Corrosion Control in the Oil and Gas Industry [1 ed.] 978-0-12-397022-0

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Corrosion Control in the Oil and Gas Industry Sankara Papavinasam

AMSTERDAM • BOSTON • HEIDELBERG • LONDON NEW YORK • OXFORD • PARIS • SAN DIEGO SAN FRANCISCO • SINGAPORE • SYDNEY • TOKYO Gulf Professional Publishing is an imprint of Elsevier

Gulf Professional Publishing is an imprint of Elsevier 32 Jamestown Road, London NW1 7BY, UK 225 Wyman Street, Waltham, MA 02451, USA 525 B Street, Suite 1800, San Diego, CA 92101-4495, USA Copyright Ó 2014 Elsevier Inc. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means electronic, mechanical, photocopying, recording or otherwise without the prior written permission of the publisher Permissions may be sought directly from Elsevier’s Science & Technology Rights Department in Oxford, UK: phone (+44) (0) 1865 843830; fax (+44) (0) 1865 853333; email: [email protected]. Alternatively, visit the Science and Technology Books website at www.elsevierdirect.com/rights for further information Notice No responsibility is assumed by the publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions or ideas contained in the material herein. Because of rapid advances in the medical sciences, in particular, independent verification of diagnoses and drug dosages should be made British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress ISBN: 978-0-12-397022-0 For information on all Gulf Professional publications visit our website at elsevierdirect.com

Typeset by TNQ Books and Journals www.tnq.co.in Printed and bound in United States of America 14 15 16 17 10 9 8 7 6 5 4 3 2 1

Foreword This book will help oil and gas practitioners responsible for corrosion management make technically sound, effective, and efficient decisions. Its greatest strength is that it strikes a middle-ground between corrosion science textbooks and technical practice documents. The demographics in our profession are such that the bulk of our most experienced oil and gas corrosion practitioners will retire in the next ten years. This is creating demand for new entrants, many of which will be drawn either from universities or the oil and gas generalist community. The university-educated corrosion scientist will benefit from the background chapters on the oil and gas industry, giving the necessary context to convert their scientific knowledge into engineering practice. The chapter on corrosion management, including risk, will be especially valuable because this topic is core to optimally managing corrosion threats but is normally absent from university corrosion science curricula. The oil and gas generalist who is trained in operations and engineering decision-making can use this book to learn about corrosion from a facility operation context. Available corrosion science textbooks are like a foreign language to those outside of our profession. After reading this book, this new corrosion practitioner can keep it as a reference to help identify unfamiliar corrosion threats and determine when they require the help of a corrosion specialist. Finally, the book is informative even for those of us who have spent many years inside the oil and gas corrosion professional practice community, and I plan to have one on my bookshelf as a reference. For sure, its presence will remind me of our genuine wish that our present and future colleagues will find success in our corrosion profession. Oliver Moghissi, Past NACE President (2011–2012)

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Preface The annual cost of corrosion in the USA oil and gas industry is over $27 billion; leading some to estimate the global annual corrosion cost of the oil and gas industry as exceeding $60 billion. For companies with oil or gas infrastructure, the need to reduce corrosion-related costs is pressing. Further, public awareness and regulatory scrutiny of the environmental impact of releases of oil and gas have enormously increased in recent years. The oil and gas industry is striving to reach ‘zero failure’. The key elements to reach ‘zero failure’ due to corrosion include: • • • • • •

Precise assessment of corrosion risks, Implementation of cost-effective methods to control corrosion, Accurate monitoring of corrosion rates at various stages of the infrastructure, Maintenance of corrosion control strategies for the entire duration of the infrastructure, Incorporation of industry best practices and standards in corrosion management, and Treatment of oil and gas infrastructures as one system in order to avoid the impacts of one segment’s corrosion management program on another segment.

The overall objective of this book is to present the unique 5-M methodology to help the industry to reach this ‘zero failure’ goal. The book discusses the characteristics of each of the methodology’s five pillars: Modeling, Mitigation, Monitoring, Maintenance, and Management. It describes implementation of the 5-M methodology in various sectors of the oil and gas industry including production, transmission, storage, refining, and distribution. This book also provides the reader a gateway to industry’s best practices, 1,000+ international standards, and fundamental scientific and engineering principles. It is based on the author’s two decades of experience in the field and on reviewing 10,000+ references and case histories. Chapter 1 provides a bird’s eye view of the oil and gas industry. It discusses the importance of energy from hydrocarbons, describes their different types, indicates their sources, and provides a brief history of the industry. This chapter then explains how the industry is regulated by various government agencies in North America, and finally presents the impact of corrosion on the industry. To use hydrocarbons as energy source, they must be extracted from underground, all other nonenergy containing products separated from them, and the different types of hydrocarbons separated from one another. These processes occur in different segments of the oil and gas industry network operating between the underground wells where the hydrocarbons are found and the locations where they are used as fuels, for example, in an automobile. Chapter 2 presents various operating conditions in different segments, the different types of materials used in those segments, and the different types of corrosion that may take place. The oil and gas industry uses various materials, both metals and non-metals. More than 90% of the materials used are metals, but non-metals serve critical functions in the industry. Chapter 3 discusses the basic properties of metals and non-metals, classification of materials, and types of materials used in the oil and gas industry. The rate at which the corrosion takes place depends on several environmental factors including flow, pressure, temperature, composition of oil phase, composition of water phase, composition of gas

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phase, solids, microbes, pH, organic acids, and mercury. Chapter 4 discusses the influence of environmental factors. Different types of corrosion occur in various segments of oil and gas industry depending on the interaction between the material and the environment. The predominant types include general corrosion, localized pitting corrosion, hydrogen induced cracking, erosion-corrosion, microbiologically influenced corrosion, erosion-corrosion, sulfide stress cracking, stress corrosion cracking (intergranular or transgranular), chloride stress corrosion cracking, corrosion fatigue, high temperature corrosion, hydrogen flaking, corrosion under insulation, metal dusting, carburization, and graphitization. Chapter 5 describes these types of corrosion and their mechanisms, as well as general methods of controlling them. Based on several years of field experience and laboratory experiments, several models have been developed to predict the risk of corrosion occurring inside the infrastructure. Chapter 6 presents models to predict hydrogen effects, general corrosion, pitting corrosion, erosion-corrosion, microbiologically influenced corrosion (MIC), high temperature corrosion, and top-of-the line corrosion (TLC). A decision should be taken at the design stage either to use corrosion-resistant alloys (CRA) or carbon steel. In either option, implementation of appropriate mitigation activities is required. Chapter 7 discusses some time-tested and proven strategies to mitigate internal corrosion including pigging, corrosion inhibitors, biocides, internal lining and coating, cladding, cathodic protection (CP), and process optimization. Successful selection of materials and successful implementation of mitigation strategies ensure that the infrastructure is safe for continued operation. It is also important that under the actual field operating conditions, corrosion proceeds according to the anticipated low rate. Various techniques are used to monitor corrosion at different stages. Chapter 8 discusses techniques to monitor internal corrosion as well as to inspect wall loss resulting from internal corrosion. The external surface of oil and gas infrastructure is exposed either to the atmosphere (above-ground structures) or to underground conditions (buried in soil or submerged in water). Electrically insulating coatings are applied to control the external corrosion of structures exposed to the atmosphere, and for underground structures, electrically insulated coatings and cathodic protection (CP) are used. Chapter 9 provides an overview of coatings and CP, as used to mitigate external corrosion in oil and gas infrastructures. Corrosion may take place when the coating deteriorates and when the CP does not adequately protect the areas where this occurs. Chapter 10 discusses models to predict the effectiveness of corrosion control strategies and the rate of corrosion when the corrosion control strategies fail. Strategies to control external corrosion are integral to the infrastructure, i.e., the coating is applied as the material (e.g., steel) is produced and the CP is applied immediately after the installation of the infrastructure. For this reason, monitoring techniques focus on estimating the effectiveness of the external corrosion control strategies as well as on estimating the external corrosion rate of the infrastructure. Chapter 11 discusses various monitoring techniques, including holiday detection, aboveground monitoring, remote monitoring, inline inspection, hydrostatic test, and below-ground inspection. Chapter 4 discusses the environmental factors which influence corrosion. These factors are normally measured for reasons other than corrosion control. Chapter 12 discusses general types of measurements, factors measured, importance of quality control during the measurement, and precautions when using these factors in developing corrosion control strategies. All strategies (selection of appropriate materials that can withstand corrosion in a given environment, development of appropriate model to predict the behavior of the system, implementation of

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mitigation strategies to control corrosion, and monitoring of system to ensure that the corrosion of the system is under control) would be inadequate if a good maintenance strategy was not developed and implemented. A comprehensive and effective program requires maintenance of five interdependent entities (equipment, workforce, data, communication, and associated activities). Chapter 13 describes the general characteristics of these entities. Corporate management implements a top-down approach (risk-avoidance, goal-based, financeoriented) to minimize the risks of corrosion. On the other hand, corrosion professional estimates risk by a bottom-up approach (field experience, fact-based, technically-oriented). Corrosion management provides a vital, seamless link between the two approaches. In a way, corrosion management is a combination of art and science to balance financial and technical requirements. Chapter 14 describes critical aspects of corrosion management. This chapter also describes methodologies to integrate the information presented in Chapter 1 through 13 for developing an effective corrosion management program. Corrosion professionals with a ‘bottom-up’ orientation may start reading the book from Chapter 1, whereas readers with ‘top-down’ orientation may start reading the book from Chapter 14. Either starting point will help the development and implementation of a risk-minimized, technically sound, and cost-effective corrosion management program. Both imperial and metric units are alternatively used in the oil and gas industry. For this reason, both imperial and metric units are used to the extent possible without losing the flow of the book. In equations only unit used in the original reference is presented. Factors to convert values from one unit to another are listed in Appendix. I would like to thank the companies and individuals for granting permission to use copyright materials. Every effort has been made to obtain copyright permission from the sources and they are acknowledged. I would be happy to hear and correct any errors or omission in providing proper acknowledgment. Lastly, I would like to quote: What we learned is smaller than handful What we need to learn is larger than the universe* Avvaiyyar (A respected poet from first century)

I would be happy to hear suggestions and ideas to further the knowledge. Sankara Papavinasam CorrMagnet Consulting Inc. Ottawa, Ontario, Canada

Acknowledgements Seeds for the 5-M methodology and for this book were planted one afternoon in 2005 when a group of corrosion professionals brain-stormed key elements for developing effective corrosion strategies. Each one of us emphasized the importance of one key element: • • • • •

Mechanism/model (Tom Jack) Mitigation (Joseph Boivin) Monitoring (Yours truly) Maintenance (Bich Nguyen) Management (Tanis Lindberg)

We all soon realized that each of the element is equally important in developing effective control strategies. Experience of organizing presentations, tutorials, workshops, and courses under the 5-M methodology title has been fruitful. Many industry leaders pointed out that they have come across proposals and reports organized under the 5-M methodology. Most technical knowledge for writing this book was acquired at CanmetMATERIALS, where I had the privilege of working for close to twenty years. I acknowledge with gratitude R. Winston Revie for introducing me to the oil and gas pipelines industry. I would also like to extend my appreciation to Alebechew Demoz, Alex Doiron, Tharani Panneerselvam, Jennifer Collier, Bill Santos, Mimoun Elboujdaini, and other colleagues at CANMET laboratories in Ottawa, Devon, Hamilton, and Calgary, Canada for their collaboration and support. I have had the fortune of developing friendships with several corrosion professionals during NACE conferences, NACE Corrosion Technology Weeks, Banff Pipeline Workshops, ASTM Corrosion Committee meetings, and CSA Coating Committee meetings. I would especially like to thank Nihal Obeyesekere, Jennifer Klements, Kimberly-Joy Harris, Amal Al-Borno, Dennis Wong, Peter Singh, John Shore, Ravinda Chhatre and Anand S. Khanna for their support throughout the progress of this book. I would also like to thank Trevor Place, Alan Bowles, and Doug Cariou for reviewing the initial draft from a technical, business, and communication perspective. Their feedback was invaluable for developing the flow of the book. I wish to express my sincere gratitude to all reviewers for their quality and timely review as well as for their valuable input. My friends from my school days, Hari Prasad and Shaheen Taj, have always provided unwavering support for all my initiatives. I have written this book based on two virtues that my father lives by and my mother helps me to follow: ‘nothing other than being honest brings satisfaction’ and ‘do not come to any conclusion until you hear the other side of the story’. I dedicate this book to my parents. My special thanks are due to my wife and son for understanding my frequent absence from family events and responsibilities while working on this book. Without their support and encouragement it would have been impossible for me to undertake this project. Throughout the writing of this book my father-in-law and my brother-in-law have supported me with their friendly queries. I also express special thanks to my sister for her unconditional love. I am blessed with love from innumerable aunts, uncles, cousins, nieces, and nephews. I would like to specially remember Thiraviamama, Shanmukka, Ayyappamama, Chakkaathai, and Leelaathai for their affection.

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Acknowledgements

The Elsevier team has provided valuable support and encouragement throughout this project. I would like to especially thank Ken McCombs, Katie Hammon, Kattie Washington, Joanna Souch, and Helen Stedman for their help. Sankara Papavinasam CorrMagnet Consulting Inc. Ottawa, Ontario, Canada

Reviewers Dharma Abayarathna Williams, Houston, TX, USA Amal Al-Borno Charter Coating Service (2000) Ltd., Calgary, AB, Canada Milan Bartos BP America Inc., Houston, TX, USA Glenn R. Cameron National Energy Board, Calgary, AB, Canada Sheldon W. Dean Dean Corrosion Technology, Glen Mills, PA, USA Donald E. Drake ExxonMobil, Houston, TX, USA Khlefa A. Esaklul Oxy, Houston, TX, USA David W. Grzyb Alberta Energy Regulator, Calgary, AB, Canada Bob Gummow B. Gummow Enterprises Ltd., Pickering, ON, Canada Thomas Jack University of Calgary, Calgary, AB, Canada Russell D. Kane iCorrosion LLC, Houston, TX, USA Fraser King Integrity Corrosion Consulting Ltd., Nanaimo, BC, Canada Jon Kvarekval Institute for Energy Technology, Kjeller, NO, Norway Allan McIntyre Cenovus Energy Inc., Calgary, AB, Canada Michael Melampy Hi-Temp Coatings Technology, Acton, MA, USA Nihal Obeyesekere Clariant Chemicals, Houston, TX, USA Raju Pakalapati ExxonMobil, Houston, TX, USA

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Reviewers

Trevor Place Enbridge Pipelines, Edmonton, AB, Canada Daniel E. Powell Williams, Tulsa, OK, USA Greg Ruschau ExxonMobil, Houston, TX, USA Sam Seagraves Danlin Industries Corporation, Thomas, OK, USA Stephen N. Smith Engineering Consultant, The Woodlands, TX, USA Saadedine Tebbal SET Laboratories Inc., Stafford, TX, USA Jeffrey L. Tides Matcor, Doylestown, PA, USA Harry Tsaprailis Alberta Innovates – Technology Futures, Edmonton, AB, Canada Alberto Valdes Chevron, Bellaire, TX, USA Jose R. Vera DNV, Katy, TX, USA Sandy Williamson Ammonite Corrosion Engineering Inc., Calgary, AB, Canada Dennis Wong ShawCor Ltd., Toronto, ON, Canada Lietai Yang Corr Instruments, San Antonio, TX, USA

CHAPTER

1

The Oil and Gas Industry

1.1 Introduction This chapter provides a birds-eye view of the oil and gas industry. It discusses the importance of energy from hydrocarbons, describes different types of hydrocarbons, indicates their sources, and provides a brief history of the industry. The chapter then explains how the industry is regulated by various government agencies in North America, and finally presents the impact of corrosion on the industry.

1.2 Energy from hydrocarbons The progress of civilization over the past two centuries has depended on the energy derived from crude oil, natural gas, coal, and nuclear reaction, as well as from renewable (wind, sun, biofuels, and hydroelectric) sources. Table 1.1 lists sources of energy in 2005; of these hydrocarbons (crude oil and natural gas) and coal comprised 84%.1 Total global energy demand in 2030 is projected to be 50–60% more than current levels. Figure 1.1 presents the anticipated sources of energy in 2030; energy from nuclear and renewable sources could increase substantially, but energy from hydrocarbons and coal would nevertheless be up to 80% of the total.2 The industry has produced 1.063 trillion barrels (bbl) of oil since its inception in the late 1800s. The global demand for oil in 2000 was 76 million bbl/day (27.74 billion bbl/year). Table 1.2 presents

Table 1.1 Current Sources of World Energy1 Energy Source

Supply Percentage)

Crude oil Natural gas Coal Nuclear Renewable )

38 23 23 7 9

Based on 2005 estimates

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00001-7 Copyright Ó 2014 Elsevier Inc. All rights reserved.

1

2

CHAPTER 1 The Oil and Gas Industry

FIGURE 1.1 Anticipated Sources of Energy in 2030.2 Reproduced with permission from Cambridge University Press.

Table 1.2

)

Worldwide Oil Production3 Crude Oil Production (Thousand Barrels Per Day)

Country

1970

1980

1990

1991

1992

1993

1994

1995

1996

Saudi Arabia United States Russia Iran China Norway Venezuela Mexico United Kingdom United Arab Emirates Nigeria Kuwait Canada Indonesia Libya Algeria Iraq Kazakhstan

3,789 9,648 NA)) 3,831 602 0 3,708 420 2 691

9,903 8,597 NA 1,662 2,113 528 2,165 1,936 1,619 1,702

6,414 7,355 10,325 3,252 2,769 1,620 2,085 2,648 1,850 2,117

8,223 7,417 9,220 3,358 2,785 1,876 2,350 2,774 1,823 2,416

8,308 7,171 7,915 3,455 2,835 2,144 2,314 2,668 1,864 2,322

8,087 6,847 6,875 3,671 2,908 2,264 2,335 2,673 1,922 2,195

8,000 6,662 6,315 3,585 2,961 2,580 2,463 2,685 2,469 2,223

8,074 6,560 6,135 3,612 3,007 2,782 2,609 2,722 2,565 2,205

8,083 6,471 6,010 3,675 3,127 3,086 2,955 2,854 2,633 2,217

1,090 2,983 1,305 855 3,321 976 1,563 NA

2,058 1,661 1,424 1,576 1,830 1,020 2,514 NA

1,811 1,235 1,518 1,289 1,374 794 2,080 515

1,867 200 1,548 1,411 1,509 803 283 530

1,902 1,050 1,604 1,346 1,493 772 425 515

1,905 1,870 1,677 1,327 1,361 747 448 460

1,883 2,000 1,742 1,319 1,380 750 550 405

1,890 2,007 1,806 1,498 1,390 764 600 415

2,014 2,060 1,820 1,516 1,403 816 600 460

)

Based on Table 1, page S2 of reference 1.3 Not available

))

1.2 Energy from hydrocarbons

3

annual production of the major oil-producing countries.3 In 2030, global oil demand is estimated to be about 37.6 to 50.4 billion bbl/year. The industry has also produced 3,000 trillion cubic feet (TCF) [85 trillion cubic meters (TCM)] of gas. The remaining gas reserve is estimated to be 7,000 TCF (200 TCM). The global demand for natural gas in 2000 was 88.7 TCF (2.51 TCM) per year. In 2030, gas demand is estimated to be about 130–212 TCF per year (3.7–6.0 TCM per year). The energy (heat) content is a unique property of each type of hydrocarbon. The normal unit used for heat is the British Thermal Unit (BTU). The amount of heat required to raise the temperature of one pound (lb) of water by 1 F is one BTU. The heating value may be reported as higher heating value (HHV) and lower heating value (LHV). HHV is a measure of the gross amount of heat produced when the hydrocarbon burns. LHV considers the loss of heat due to vaporization of water during the burning of hydrocarbon. The thermal efficiency (TE) can be calculated from the HHV and LHV using (Eqn. 1.1): TE ¼

LHV HHV

(Eqn. 1.1)

Table 1.3 presents the HHV and LHV values of some hydrocarbons.4 The oil and gas industry strives to produce and supply hydrocarbons with higher thermal efficiencies as economically as possible.

Table 1.3 Heating (Energy) Values of Hydrocarbons and Other Substances4 HHV Energy Substances

Chemical Formula

KJ/m3

Methane Ethane Propane Normal butane Iso butane Normal pentane Iso pentane Normal hexane Normal heptane Normal octane Normal nonane Normal decane Hydrogen sulfide Carbon monoxide Hydrogen Helium Water Oxygen Nitrogen Carbon dioxide

CH4 C2H6 C3H8 C4H10 C4H10 C5H12 C5H12 C6H14 C7H16 C8H18 C9H20 C10H22 H2S CO H2 He H2O O2 N2 CO2

37,694 66,032 93,972 121,779 121,426 149,654 149,319 177,556 205,431 233,286 261,189 289,066 23,791 11,959 12,091 0 0 0 0 0

LHV

BTU/ft3 1,010 1,770 2,516 3,262 3,252 4,009 4,001 4,756 5,502 6,249 6,700 7,743 637 321 324 0 0 0 0 0

KJ/m3 33,936 60,395 86,456 112,384 112,031 138,380 138,044 164,402 190,398 216,374 242,398 268,396 21,912 11,959 10,230 0 0 0 0 0

BTU/ft3

Thermal Efficiency (LHV/HHV)

909 1,618 2,315 3,011 3,000 3,707 3,699 4,404 5,100 5,796 6,493 7,189 589 321 274 0 0 0 0 0

0.90 0.91 0.92 0.92 0.92 0.92 0.92 0.93 0.93 0.93 0.93 0.93 0.92 1.00 0.85 0 0 0 0 0

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CHAPTER 1 The Oil and Gas Industry

1.3 What are hydrocarbons? Hydrocarbons are chemical species containing only carbon and hydrogen atoms. Hydrocarbons can be chemically classified into several categories, but with respect to the oil and gas industry three types are important: alkanes, cycloalkanes, and aromatic compounds.

1.3.1 Alkanes (Paraffins) In the oil and gas industry alkanes are known as paraffins. Alkanes are saturated (all bonds between carbon and hydrogen atoms are single bonds) hydrocarbons. Alkanes have a general formula CnH2nþ2; where ‘n’ is the number of carbon atoms. Table 1.4 presents the chemical and physical properties of some alkanes. The simplest hydrocarbon, having just one carbon atom (n ¼ 1), is methane. Methane is the primary component of natural gas. Natural gas containing only methane is called ‘dry gas’. In the past, natural gas was simply burned (known as flaring), but now it is used as a major fuel source. The advantage of natural gas is that it produces less CO2 when combusted compared with other hydrocarbons. Hence it is considered a clean fuel. Hydrocarbons with values of ‘n’ between 2 and 5 [(ethane (C2), propane (C3), butane (C4), and pentane (C5)] are collectively known as natural gas liquids (NGLs), liquid petroleum gases (LPGs), or condensates. At atmospheric pressure they exist in the gaseous state, but the application of pressure turns them into liquids. Natural gas containing NGLs is known as wet natural gas. The alkanes with ‘n’ values between 5 and 8 [pentane (C5), hexane (C6), heptane (C7), and octane (C8)] are refined into gasoline (petrol). Due to its high energy density, easy transportability and relative abundance, gasoline has become the most commonly used fuel in automobiles. Table 1.5 presents the common names and uses of different alkanes. Table 1.4 Properties of Alkanes (Saturated Hydrocarbons or Paraffins) Name

Chemical Formula

Methane Ethane Propane Butane Pentane Hexane Heptane Octane Nonane Decane Undecane Dodecane Eicosane Triacontane

CH4 C 2H 6 C 3H 8 C4H10 C5H12 C6H14 C7H16 C8H18 C9H20 C10H22 C11H24 C12H26 C20H42 C30H62

Melting Point ( C) 183 183 190 138 130 95 91 57 51 30 25 10 37 66

Boiling Point ( C) 164 89 42 0.5 36 69 98 125 151 174 196 216 343 450

State at 25 C Gas Gas Gas Gas Liquid Liquid Liquid Liquid Liquid Liquid Liquid Liquid Solid Solid

1.3 What are hydrocarbons?

5

Table 1.5 Use of Various Hydrocarbons Number of Carbons in the Paraffin Chain

Commonly Known as

Used as

5 to 8 9 to 10 11 to 15 16 to 20

Natural gas Natural gas liquids (NGL) Liquid petroleum gases (LPG) Condensates Gasoline (petrol) Naphtha Kerosene Diesel

21 to 25 26 to 35

Greasy material Asphalt

Above 35

Bitumen Coke

Domestic fuel Fuel, blended with gasoline, raw material for producing ethylene, propylene, and butylene Automobile fuel Raw material for chemical and plastics Heating oil and fuels for jet Fuel in automobile and trucks and heating oil Grease and lubricants Construction materials to pave roads and protective coatings Refined into hydrocarbons with lower number of carbons in the chain

1 2 to 4)

)

Pentane (number of carbon 5) is also included

1.3.2 Cycloalkanes (Naphthenes) Cycloalkanes are known as naphthenes. Cycloalkanes are saturated hydrocarbons having one or more carbon rings with a general formula CnH2n. Figure 1.2 compares the structures of hexane (paraffin) and cyclohexane (naphthane); both have six carbon atoms. Cycloalkanes have similar properties to alkanes but higher boiling points. Cyclohexane is commonly used as a solvent in the chemical industry and laboratories. It is also the raw material used to produce nylon.

CH3–CH2–CH2–CH2–CH2–CH3

(A) Hexane

(B) Cyclohexane (Each corner of the hexagon representing a –CH2 group)

FIGURE 1.2 Comparison of the Structures of Hexane and Cyclohexane. (A) Hexane. (B) Cyclohexane. (Each apex of the hexagon represents a –CH2 group).

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CHAPTER 1 The Oil and Gas Industry

(A) Cyclohexane (Each corner of the hexagon representing a –CH2 group)

(B) Benzene (Each corner of the hexagon representing a –CH group) FIGURE 1.3 Comparison of the Structures of Cyclohexane and Benzene. (A) Cyclohexane. (Each apex of the hexagon represents a –CH2 group). (B) Benzene. (Each apex of the hexagon represents a –CH group; ring represents double-bond structure).

1.3.3 Aromatic hydrocarbons Aromatic hydrocarbons are unsaturated hydrocarbons with the formula CnHn. They have at least one characteristic ‘six carbon ring’ called a benzene ring. Figure 1.3 compares cyclohexane and benzene, which both have an ‘n’ value of six. Aromatic hydrocarbons tend to burn with a sooty flame. Many of them have aroma (smell) and are carcinogenic (cancer causing).

1.4 Hydrocarbon sources Hydrocarbons occur naturally in the earth. According to the most widely accepted theory, hydrocarbons were formed when organic matter (such as the remains of plants or animals) was compressed under the earth, at very high pressure and high temperature for a very long time. Hydrocarbons may occur in the earth either as liquid or as gas. Liquid hydrocarbon is commonly known as crude oil and gaseous hydrocarbon is commonly known as natural gas. Crude oil is also known as ‘petroleum’ – derived from ‘petros’ (a Greek term for stone or rock) and ‘oleum’ (a Latin term for oil). An ancient term for petroleum is ‘rock oil’. An oil-producing well may also produce gas. The gas produced from an oil well is commonly known as ‘associated gas’. The relative proportion of gas and oil in the well is expressed as the gas to oil ratio (GOR). At relatively lower temperatures, more crude oil is formed and at higher temperatures more gas is formed. As we go

1.4 Hydrocarbon sources

7

Table 1.6 Characteristics of Some Bench Mark Crude Oils Name

API Gravity

Sulfur, %

Source

Remarks 15 oils from fields in the Brent and Ninian systems in the East Shetland Basin of the North Sea

Brent crude

38.3

0.37

North Sea

West Texas Intermediate (WTI) Tapis Minas Arab light Bonny light Fateh Isthmus Saharan Blend

39.6

0.24

North America

45.1 35.0 34.1 35.0e37.0 31.0 32.3e34.8 43.5e47.5

0.10 0.80 1.78 0.15 2.00 1.50 e 1.86 0.10

Malaysia Indonesia Saudi Arabia Nigeria Dubai Mexico Algeria

Light far east oil A weighted average of these crude oils are known as The Organization of the Petroleum Exporting Countries (OPEC) reference basket

further beneath the earth’s crust, the temperature increases. For this reason, gas is usually associated with oil in wells that are within one to two miles from the earth’s crest. Wells deeper than two miles primarily produce natural gas. In addition to oil and gas, wells may produce several other substances, including salt water (commonly known as formation or produced water), organic compounds (nitrogen, oxygen, and sulfur-containing species), metals (iron, nickel, copper, mercury, and vanadium), and radioactive materials (commonly known as NORM – naturally occurring radioactive materials). The gas phase may contain, in addition to hydrocarbons, carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen, and helium. The term ‘sweet’ is commonly used to refer to environments containing CO2 with no H2S. The term ‘sour’ is used to refer to environments containing H2S. Sour environments may also contain CO2. The less the hydrocarbons are contaminated with other non-energy substances, the easier it is to extract them from the earth. To quickly express the value of crude oils, some industry bench mark crude oils have been established. Table 1.6 presents some commonly used key industry benchmark crude oils. The value of crude oil is also ranked using American Petrochemical Institute (API) gravity. API gravity and density are inversely related, i.e., the higher the density, the lower the API gravity (Table 1.7) and the higher the API value, the more valuable is the crude oil.5 In general, hydrocarbon sources may be broadly classified into conventional, unconventional, and renewable.

1.4.1 Conventional There are no strict definitions of conventional oil and gas sources, but in general hydrocarbons can be produced from conventional hydrocarbon sources with little or no effort. For a source to be identified as conventional, 40% or more of the fluids it contains should be hydrocarbons; the underground pressure and temperature should be high enough for the hydrocarbons to reach the surface on their own (or with minimal pumping); the API gravity should be high enough for oil to flow easily; and the

8

CHAPTER 1 The Oil and Gas Industry

Table 1.7 Relationship Between API Gravity and Density5 Classification of Crude Oil Light

Medium

Heavy

Extra heavy (Bitumen)

API Gravity Scale,

Density (kilograms per cubic meter)

45.4 40.0 35.0 31.1 30.2 25.7 22.3 21.5 17.4 13.6 10.0 6.5 3.3 0.1

800 825 850 870 875 900 920 925 950 975 1000 1025 1050 1075

properties of rock in the reservoir should be conducive to the free flow of hydrocarbons. The oil and gas industry uses five rock properties to determine whether the reservoir can produce hydrocarbons by conventional methods. They are: • • • • •

Porosity: the ratio of the void space in a rock to the bulk volume of rock; Permeability: a measure of the ability of rock to permeate hydrocarbons through it; Fluid saturation: a measure of oil, water, and gas contents of a rock; Capillary pressure: a measure of ability of hydrocarbon to pass through a capillary tube which is an indirect measure of whether the rock is wetted with water or oil; Electrical conductivity: a measure of conductivity of bulk fluid in the rock. The oil-phase has low conductivity and the water-phase has high conductivity.

Conventional production may take place in three stages: primary production, secondary, and tertiary. During the early stages of production, the reservoir pressure and hydrocarbon content are high. As the reservoir pressure and hydrocarbon content decrease, water is pumped into the well to continue to produce from it. This process is known as secondary recovery or water flooding. Secondary recovery by water injection increases the amount of oil recovered over primary production, but may still leave more than 80% of oil in the reservoir. To recover more oil, gas (CO2, N2 or methane) may be injected. The process of recovering oil by injecting gas is known as tertiary recovery. A few countries with the largest conventional oil reserves account for more than 70% of hydrocarbon production. Table 1.8 presents one estimate of the remaining quantities of conventional oil in some countries.2

1.4.2 Unconventional Unconventional sources may be defined as those that cannot produce hydrocarbons at economic flow rates and in economic volumes unless the reservoir is first stimulated. The stimulation techniques

1.4 Hydrocarbon sources

9

Table 1.8 Supply of Oil in Selected Countries2 Years Remaining for Conventional Oil Reserves Producing at Current Oil Flow Rates

Country Iraq Kuwait Iran Saudi Arabia United Arab Emirates Venezuela Russia United States

168 105 87 75 70 52 20 16

include heat treatment, hydraulic fracture treatment, multilateral wellbores, and some other techniques that expose more of the reservoir to the wellbore. According to estimates, the world’s remaining supplies of unconventional resources are 13–15 trillion barrels of crude oil and 32,000 TCF (910 TCM) of natural gas (Table 1.9).6 Unconventional sources of hydrocarbons include oilsands, oil shales, gas shales, tight gas, coal bed methane, and gas hydrates.

1.4.2a Oilsands Oilsands are a naturally occurring mixture that typically contains 10–12% bitumen, 80–85% minerals (clays and sands) and 4–6% water. Bitumen is a mixture of large hydrocarbon molecules containing up to 5% sulfur compounds by weight, small amounts of oxygen, heavy metals, and other materials. Physically, bitumen is denser than water and more viscous than molasses (sometimes existing as a solid or semi-solid). Bitumen-containing oilsand deposits are found in over 70 countries, but three

Table 1.9 Global Unconventional Gas Sources6 Volume (TCF) Region North America South America Western Europe Central and Eastern Europe Russia Middle east and North Africa Africa (Sub-Saharan) Central Asia and China Pacific South Asia World

Shale Gas

Tight Gas

Coal Bed Methane

3,842 2,117 510 39 627 2,548 274 3,528 2,627 0 16,112

1,371 1,293 353 78 901 823 784 353 1,254 196 7,406

3,017 39 157 118 3,957 0 39 1,215 470 39 9,051

Total 8,228 3,448 1,019 235 5,485 3,370 1,097 5,094 4,349 235 32,560

10

CHAPTER 1 The Oil and Gas Industry

quarters of the world’s known reserves are in Canada and Venezuela. Oilsands represent about 66% of the world’s total reserves of oil. According to estimates, the volumes of oil in Canadian and Venezuelan oilsands are at least 1.7 trillion barrels (270 x 109 m3) and 235 billion barrels (37 x 109 m3) respectively.7–9 Most of the oilsands in Canada are located in three principal deposits in Northern Alberta: Athabasca, Cold Lake, and Peace River. The deposits encompass nearly 47,845 miles (77,000 km2) of land area. The first Canadian oilsand mining operations started in 1967, the second began in 1978, and the third began in 2003. Currently several further mining operations are either under development or commercial consideration. In 2005, oilsands accounted for 50% of Canada’s total crude oil output. The Venezuelan oilsands are commonly known as ‘extra heavy oil’. Bitumen and extra heavy oil are essentially the same. The Venezuelan oilsands occur at higher temperatures 120 F (50 C) and the Canadian oilsands occur at freezing temperatures. For this reason, the Venezuelan oilsands exist mostly in the liquid state, whereas Canadian oilsands exist in semi-solid and solid states. Hence the extraction of Venezuelan oilsands is relatively easier than Canadian oilsands. In the USA, oilsands are primarily concentrated in eastern Utah, with an estimated 32 billion barrels (5.1 x 109 m3) of oil. These oilsands have been quarried since the 1900s and are used mainly as paving materials. Oilsands are extracted by surface mining, or by in situ methods including cyclic steam stimulation (CSS), steam-assisted gravity drainage (SAGD), toe to head air injection (THAI), cold heavy oil production with sand (CHOPS), and the vapor extraction process (VAPEX) (see sections 2.8 and 2.9).

1.4.2b Shale oil Shale oil is a fine-grained rock containing significant amounts of hydrocarbons.10 The global deposits of shale oil from which crude oil can be recovered are estimated to be about 3 trillion barrels (w500 x 109 m3). Shale oil deposits occur in the USA, Estonia, China, Brazil, Germany, Israel, and Russia. The USA possesses 68% of the world shale oil resources, but in 2009 Estonia produced 80% of its oil requirements from oil shale.11 The most common method of extracting shale oil is by surface mining. The in situ combustion process is used for extracting shale oil from far below the surface. The extracted shale oil then undergoes pyrolysis at 842 to 932 F (450 to 500 C) to produce oil shale (synthetic crude oil), shale gas and residue (solid). This process also produces sulfur, ammonia, alumina, soda ash, uranium, arsenic, and nitrogen. Thus, similar to oilsands, the production of oil from shale oil is energy intensive and environmentally challenging. Most shale oil is used as fuel in power generation plants. For example, 90% of the shale oil produced in Estonia is used for power generation. Countries such as Romania and Russia also use shale oil for power generation. It may also be used to produce several products including carbon fibers, adsorbents, carbon black, phenols, resins, glues, tanning agents, mastic, road bitumen, cement, bricks, construction and decorative blocks, soil additives, fertilizers, rock-wool insulation, glass, and pharmaceutical products. When the price of oil is high, however shale oil is used to produce crude oil.

1.4.2c Shale gas Gas produced from shale is known as shale gas.12 Shales containing gas have a high organic material content (up to 25%), to which the natural gas is adsorbed. For this reason, the shale has low

1.4 Hydrocarbon sources

11

permeability for gas flow. The shale must be fractured to increase gas permeability. Techniques used to fracture the shale include hydraulic fracturing, horizontal drilling, and injection of large volumes of water containing sand particles at high pressure.

1.4.2d Tight gas Tight gas refers to the natural gas trapped in reservoirs of low permeability. The low permeability of the reservoir is due to the fine-grained nature of the sediments, compaction, carbonates and silicates filling the pores. Gas from these reservoirs is produced by using similar special techniques to those used to produce gas from shale gas resources.

1.4.2e Coal bed methane Methane adsorbed onto the surface of the coal bed is known as coal bed gas or coal bed methane (CBM).13 Coal beds predominantly contain methane, but they may also contain small amounts of ethane, propane, light liquid hydrocarbons, and CO2. To produce commercially, the methane content in the coal bed should be more than 92%. Extraction of methane from a coal bed depends on its porosity, the adsorption strength of methane onto carbon, fracture permeability, thickness of the formation, and initial reservoir pressure. Methane is extracted from the coal bed by drilling a steel pipe into the coal seam to release the pressure. As the pressure in the coal seam decreases, methane adsorbed onto coal desorbs and escapes to the surface through the steel pipe.

1.4.2f Gas hydrates Gas hydrates are solids with a cage-like chemical structure, in which natural gas (methane) molecules are enclosed in water molecules. Hydrates are formed naturally at sub-zero temperatures, when methane produced by the breakdown of organic materials solidifies with water. Hydrates contain immense volumes of methane. For example, one unit volume of methane hydrate may produce 160 unit volumes of methane at a given pressure. In addition ethane, propane, and butane hydrates also occur. Globally, the amount of methane in gas hydrates is estimated to be 1 x 104 gigatons.14 Canada has the most concentrated deposits of gas hydrates in the world. Russia, USA, India, Japan, and China also have substantial deposits of gas hydrates. The first hydrate core was obtained from water 5,635 feet (1,718 m) deep in Guatemala. The second hydrate core was obtained from water 1,738 feet (530 m) deep in the Gulf of Mexico. The Malik field in the Canadian Arctic was the first experimental field to produce natural gas from gas hydrates. The formation and breakdown of gas hydrates depend on water content, composition of water, pressure (normally high pressure facilitates hydrate formation), and temperature (normally low or sub-zero temperatures facilitates hydrate formation). By varying the pressure, temperature, and adding chemicals (e.g., methanol or ethylene glycol), hydrates may be broken down to produce natural gas.

1.4.3 Renewables At this time, renewable hydrocarbon technology is not mature enough to replace fossil fuels, but is mature enough to supplement them. In some countries, fossil fuels used in automobiles contain 10 to 20% biofuels. Many governments have passed legislation encouraging the use of renewable fuels.

12

CHAPTER 1 The Oil and Gas Industry

Table 1.10 Global Production of Bioethanol15 Country USA Brazil China India France Germany Russia Canada Spain South Africa Others Total

Millions of Gallons Produced (in 2006) 4,855 4,491 1,017 502 251 202 171 153 122 102 1,623 13,489

Among the renewable fuels, biofuels (bioethanol and biodiesel) are most promising. Bioethanol is mixed with gasoline and biodiesel is mixed with diesel. According to a 2006 survey, the worldwide production of bioethanol was 126 million barrels (15 billion liters) and that of biodiesel was 33 million barrels (4 billion liters). The production of both bioethanol and biodiesel is anticipated to increase 10-fold over the next ten years. Currently, Brazil and the USA are leaders in the production of bioethanol. Table 1.10 presents the amount of bioethanol produced in different countries in 2006.15 The world trend shows a nearly five-fold increase in world production over the next 20 years. The primary sources for bioethanol are corn and sugarcane. Other sources include hemp, sugar beets, maize, barley, potatoes, cassava, sunflower, wood pulp, and brewing wastes. Biodiesel is predominantly produced in Europe (90% of total biodiesel production). The remaining 10% is produced in the USA (8%) and other countries, including Argentina, Brazil, Canada, India, and Malaysia. In 2007, the USA produced 2,392 million liters (632 million gallons) of biodiesel. In 2004, Canada produced approximately 3.5 million liters (875,000 gallons) of biodiesel, and in 2010 the production is expected to reach 500 million liters (132 million gallons).1,16 Biodiesel is produced from a variety of sources. Figure 1.4 presents various sources of biodiesel.17,18 About 80% of the biodiesel in Europe is produced from rapeseed oil and about 20% from soybean oil. In the USA, most biodiesel is produced from soybeans. In Canada, biodiesel is produced from yellow grease, tallow, canola, and soybeans. Both the US and New Zealand are conducting experimental studies to produce biodiesel from algae. In India, biodiesel is produced from two nonedible plants – Jatropha curcas and Pongamia pinnata. The content of biodiesel in the blend is identified using the designation ‘B’, followed by the percentage of biodiesel. For example, B2 indicates 2% biodiesel and 98% petroleum diesel and B20 indicates 20% biodiesel and 80% petroleum diesel. Of the various blends, B20 is most commonly used. The energy content of biodiesel (as measured, for example in BTU) is about 7–9% less than that of petroleum diesel.

1.5 History of the oil and gas industry

13

FIGURE 1.4 Some Resources for the Production of Biodiesel.17,18

1.5 History of the oil and gas industry19–24 The oil and gas industry has been maturing over the past two centuries and continues to evolve. This section presents a brief history of the oil and gas industry so that we can appreciate its magnitude, knowledge, wealth, breadth, and impact. 4000 BC

347 AD 1482 1500 1594 1742 1742 1766 1783

Oil seep was reported on the banks of the Euphrates River (currently Iraq). It was considered as the ‘fountains of pitch’. Asphalt obtained from this pitch was used as mortar between building stones. Oil wells of depths 800 feet (240 meters) were drilled in China using bits attached to bamboo poles. A barrel of volume 42 US gallons (159 liters) was established as the standard for the packing of fish. This scale is now commonly used to measure crude oil. Hydrogen was first recognized as inflammable air by Paracelsus. Oil wells of 115 feet (35 meters) deep were hand-dug in Baku, Persia (currently Iran). Oilsands were used by the ancient Mesopotamians and Canadian first nations. Corrosion protection of steel by zinc coating was first described. Hydrogen was first recognized as a substance by Cavendish. The name ‘hydrogen’ was coined by Lavoisier. Continued

14

CHAPTER 1 The Oil and Gas Industry

dContinued 1815 1824 1836 1848 1849 1853 1853 1854 1854 1858 1859 1860

1860s 1860s 1861 1862 1863 1863

1865

1865

1866 1870 1872

1873

Oil was produced as an undesirable byproduct from brine wells in Pennsylvania, USA. Copper was successfully protected from corrosion by coupling it with either steel or zinc. This is the origin of cathodic protection. Steel was protected from corrosion by dipping it into molten zinc. This procedure is known as galvanizing and the product is known as galvanized steel. The first modern oil well was drilled in Baku, Iran. Abraham Gesner of Canada distilled kerosene from cannel coal and bituminous shale for the first time. Kerosene was extracted from petroleum. Biodiesel was first produced by Duffy and Patarick. The first European oil well was drilled in Bobrka, Poland. The first oil company (Pennsylvania Rock Oil Company) was formed in USA. The first North American oil well was drilled in Southern Ontario, Canada. The first commercially successful oil well was drilled in Pennsylvania, USA. The first real-time, end-to-end communications system along railway right of way was established using telegraphic line (this technology was later adopted for use in pipeline right-ofway). A company started manufacturing blue containers of volume 42 gallons. The company called it the blue barrel and abbreviated it as ‘bbl’. This term is still being used. Hydrotransport process was used during the construction of the Suez Canal. The same technology is currently being used to transport oilsands from mines to processing centers. Railroad tracks were laid in Pennsylvania, USA to transport oil from the field to the market. Oil from the wells to the railway station was transported in horse-drawn wagons. Atmospheric distillation was used in the refinery to produce kerosene. Dmitri Mendeleev first proposed the idea of transporting petroleum using pipes. The first oil transportation pipeline was constructed in Pennsylvania, USA. This 2 inch diameter (51 mm) and 2.5 mile (4 km) long cast iron pipeline used three pumps to transport oil over a 400 foot (22 meters) ridge. It was however quickly abandoned because it developed several leaks. Another 6 inch (152 mm) diameter pipeline was constructed in Pennsylvania. This pipeline transported oil along a gradient of 52 feet per mile (10 meters per kilometer). About 7,000 barrels of oil per day were transported through this pipeline without any pump. Wrought iron was used to construct pipelines to overcome the leakage problems associated with cast iron. The first wrought iron pipeline transported petroleum distillates over a distance of three miles. Subsequently, another 2 inch (51 mm) diameter, 6 mile (10 km) long wrought iron pipe was constructed. Three pumps were installed along the pipeline to increase the flow. This pipeline also had the distinction of having first data acquisition and communications system; a telegraph line was used to communicate data on oil shipments. The practice of extracting oil from the well and storing it temporarily in tanks was established. As a result, the cost of gathering the oil dropped from $1.00 to $0.25 per barrel. Vacuum distillation was established in the refinery. The Petroleum Producers Association endorsed 42 gallons (159 L) as equivalent to one barrel for reporting the volume of crude oil. This was the first consensus standard in the oil and gas industry. The first oil-tank steamer was built in Belgium, but it was not successful due to many safety concerns.

1.5 History of the oil and gas industry

15

dContinued 1878

1881 1893 1897 1800e1900 1900 1901 1901 1903

1908 1910e12 1910s

1911 1913 1916 1920s 1924 1930 1932 1932 1932 1933 1935 1935 1935 1937 1938 1938 1939 1940

The first successful oil tanker (Zoroaster) was built in Sweden to transport oil from Baku to Astrakhan. Zoroaster carried 242 tons of kerosene in two iron tanks joined by pipes. This ship was 184 feet (56 m) long, with a 27 feet (8.2 m) long beam and 9 feet (2.7 m) long draft. A tanker carrying kerosene exploded in Baku. A pipe was pushed out of its holding tank when a gust of wind hit the tanker, and as a consequence oil tanker design drastically changed. Rudolf Diesel operated the first diesel engine, using peanut oil as the fuel. The first offshore well was drilled in Summerland, California, USA. Europe and USA started using gas containing a mixture of hydrogen, methane, carbon dioxide, and carbon monoxide as fuel. This fuel was commonly known as ‘town gas’. Rotary drilling technology was first used to drill an oil well. Henry Ford formed the Ford Motor Company; as a consequence crude oil demand started to increase. Hydraulic rotary drilling technology was first used. Two tankers (Vandal and Sarma) were built with internal combustion engines (until then tankers used steam engines). Each was capable of carrying 750 tons of refined oil and was powered by a 360 horsepower (270 kW) diesel engine. Offshore production started in the shallow waters of Caddo Lake, Louisiana, USA. Impressed-current cathodic protection system was first used to protect underground structure. Underwater drilling activities started in Caddo Lake, Louisiana, USA and Maracaibo Lake, Maracaibo, Venezuela. Initially, wells were drilled from onshore piers and subsequently they were drilled from offshore wooden platforms. The volume of gasoline production exceeded that of kerosene as motor cars required them to run. Until then gasoline was discarded as a wasteful byproduct. The thermal cracking process was established in the refinery. The sweetening process was established in the refinery. Steel piers from onshore extended up to a quarter of a mile into the ocean in California, USA. Offshore platforms were constructed on top of timber or concrete pilings in Lake Maracaibo, Venezuela. The thermal reforming process was established in the refinery. The first offshore steel platform (60 x 90 feet/18  27 meters) was completed in 38 feet (w12 m) deep water. The hydrogenation process was established in the refinery. The coking process was established in the refinery. The solvent extraction process was established in the refinery. First airline was successfully flown. This started the demand for jet fuel. The solvent dewaxing process was established in the refinery. The catalytic polymerization process was established in the refinery. The catalytic cracking process was established in the refinery. An offshore field was discovered in the Gulf of Mexico, USA. The first hydrogen pipeline was constructed in Germany. The visbreaking process was established in the refinery. Divers were used for the first time to remove wall casing under the ocean. Continued

16

CHAPTER 1 The Oil and Gas Industry

dContinued 1940 1941 1942 1947 1940s

1950 1950

1952 1953 1954 1955 1957 1950s 1960 1963 1964 1964 1967 1968 1969 1960s 1970 1972 1972 1974 1975 1976 1977

The alkylation and isomerization processes were established in the refinery. An offshore well was drilled to 9,000 feet (2,743 meters) in depth, in Texas, USA. The fluid catalytic cracking process was established in the refinery. The first ‘out off sight of land’ (drilling platform), i.e., far away from the coast, oil well was constructed off the coast of Louisiana, USA. Two long pipelines, commonly known as ‘Big Inch’ and the ‘Little Big Inch’, were constructed between Texas and the east coast of the USA. The Big Inch pipeline was a 24 inch (61 cm) diameter pipeline to transport 300,000 barrel per day (BPD) of crude oil, and the Little Big inch was a 20 inch (51 cm) pipeline to transport 235,000 BPD of refined oil. The deasphalting process was established in the refinery. The first successful application of cathodic protection to control corrosion of ships in Canada, along with protective coating. Previous attempts made between 1824 and 1827 had failed due to fouling by marine organisms. The catalytic reforming process was established in the refinery. The first floating rotary drilling vessel was operated. It was capable of drilling through 400 feet (122 meters) of water to depths of 3000 feet (914 meters). The hydrosulfurization process was established in the refinery. The drilling rig was moved from the side to the center of the ship to reduce the impact of vessel motion. The catalytic isomerization process was established in the refinery. The discovery of major crude oil and natural gas fields in Western Canada led to the establishment of pipeline grid across Canada. The hydrocracking process was established in the refinery. The first commercial oil field was discovered in Alaska, USA. The first vessel carrying liquid natural gas (LNG) (Methane Princess) started operation. The first hydrogen pipeline was constructed in Canada. First commercial oilsands production started in Alberta, Canada. Fourteen platforms started producing oil and gas in Alaska, USA. A storage steel dome capable of storing 500,000 bbl oil was installed in the Arabian Gulf. This dome resembles an inverted champagne glass. The Colonial pipeline of diameter ranging between 30 inches (76 cm) and 36 inches (91 cm) was constructed. Currently this pipeline is the longest petroleum product transportation system. Buoyant articulated columns were installed in the North Sea for loading crude oil directly into oil tankers (ships). Sand and gravel islands were constructed in Alaska, USA for exploratory drilling in water depths of 100 feet (w31 meters). Flexible steel pipe was first used. The catalytic dewaxing process was established in the refinery. A two-piece jacket was installed in 850 feet (259 meters) of water off the coast of California, USA. A one-piece jacket in 680 feet (207 meters) of water was installed in the Gulf of Mexico, USA. The Trans-Alaska crude oil pipeline was constructed. This 48 inch (1.22 m) diameter, 798 mile (1,284 km) long pipeline transported approximately 1.7 million bpd of oil. Due to the extreme arctic climate, rugged mountain terrain, earthquake regions (geological faults), and stringent standards to preserve the arctic environment, the construction cost of the pipeline was $9 billion, making it by far the most costly pipeline project in the world.

1.6 Regulations

17

dContinued 1978 1970s

1981 1983 1984 1980s 1991 Current

A three-piece jacket was installed in 1,025 feet (312 meters) of water in the Gulf of Mexico, USA. Oil production activities started in the North Sea, Europe. Eighteen concrete structures were installed in water depths between 240 and 540 feet (73 and 165 meters) with loads up to 40,000 tons. A one-piece jacket was installed in 915 feet (279 meters) of water. A floating conical drilling unit was first deployed in the Canadian Beaufort Sea. A tension-leg platform was installed in 485 feet (148 meters) of water in the North Sea, Europe. Horizontal drilling was successfully used in France and Italy. The first industrial-scale biodiesel plant started operation in Austria. The Comecon pipeline transporting oil from the Urals, Russia to Eastern Europe over a distance of 3,800 mi (6,115 km) is the longest pipeline in the world. The world’s longest gas pipeline is also in Russia. This pipeline is 3,400 mile (5,500 km) long. There are more than 2.5 million miles (4 million kilometers) of pipelines in North America. If these pipelines were laid end-to-end they would circle the earth about 100 times. This pipeline network includes: • 170,000 miles (274,000 kilometers) of onshore and offshore hazardous liquid pipelines • 295,220 miles (475,110 kilometers) of onshore and offshore gas transmission pipelines • 1,900,000 miles (3 million kilometers) of natural gas distribution pipelines and propane distribution pipelines Future hydrocarbons will increasingly be produced from frontier (arctic) as well as from deep water (deeper than 33,000 feet (10,000 meters)) regions. As conventional sources become depleted, more and more efforts will be made to produce hydrocarbons from unconventional and renewable sources.

1.6 Regulations Chapter 2 describes different entities of the oil and gas industry network. Most parts of these networks are underground, except for some huge facilities such as storage tanks and refineries. The existence of underground facilities is indicated with aboveground markings in many countries. For example, in USA the American Public Works Association (APWA) uses yellow color code to indicate oil and gas structure. Table 1.11 presents the APWA color code to indicate various infrastructures. The vast underground oil and gas networks are strictly regulated by a number of government regulatory agencies; from the design and construction stages to operation and discontinuation (often referred to as abandonment) stages. These agencies ensure that the oil and gas network is operated safely, responsibly, and in the public interest. Table 1.12 presents typical types of approvals required for operating an oil and gas network in Canada, and Table 1.13 presents typical types of application required for approval.25 Table 1.14 presents the types of regulators for gas networks in the USA. Table 1.15 presents some regulators in Canada and USA. While different countries have different regulations, they are all more or less based on the same principle; i.e., to safeguard people, the environment, and the facility. Table 1.16 compares different regulators’ approaches.26 Some regulations are prescriptive in nature, while others are descriptive. In prescriptive regulations, the steps to be taken to maintain the integrity of the infrastructure are

18

CHAPTER 1 The Oil and Gas Industry

Table 1.11 American Public Works Association Color Code) Infrastructure

Color

Electric Oil and Gas Communication/Cable Water Sewer Proposed excavation

Red Yellow Orange Blue Green White

)

American Public Works Association (APWA) color code

prescribed. Generally, prescriptive regulations are to be considered only as a minimum. Responsible operation may need to go further. In descriptive regulations, the expectations of the regulators are outlined, leaving the steps to be taken with the operators. There are many terms for this style of regulation: goal-based, outcome-based, goal-oriented. All describe the desired outcome and leave the mechanics of how to achieve that to the operator. Because transmission pipelines operate at elevated pressure, travel long distances, and pass through other infrastructure such as roads, buildings, railway lines, electric towers, and industrial complexes, the regulations governing their operation can be more stringent than those governing other parts of the oil and gas industry. Regulations in Canada (mostly descriptive) and in US (mostly prescriptive) for transmission pipelines are discussed in the following paragraphs as illustration. In Canada, the National Energy Board (NEB) regulates the design, construction, operation, and abandonment of interprovincial and international pipelines within Canada. According to the NEB Act (OPR 99), ‘pipeline’ means a line that is used or to be used for the transmission of oil, gas, or any other commodity and includes all branches, extensions, tanks, reservoirs, storage facilities, pumps, racks, compressors, loading facilities, inter-station systems of communication by telephone, telegraph or radio and real and personal property and works connected therewith, but does not include sewer or water pipeline that is used or proposed to be used solely for municipal purposes. Pipelines within the province are regulated by provincial regulators. For example, in Alberta, most activities related to the planning, construction, operation, and abandonment of oil and gas pipelines are regulated by the Alberta Energy Regulator (AER). The AER is responsible for issuing approvals for gathering and transmission lines as well as high pressure (greater than 700 kPa) distribution lines that lie fully within Alberta. Alberta Transportation and Utilities (ATU) board regulates lower pressure lines. Regulations may require the operator to have manual describing operations, maintenance, repair, corrosion control, and integrity management processes as well as to have documents to demonstrate compliance. Regulations may also require the operator to evaluate, inspect, and/or test annually the operating or discontinued pipelines and the operator to submit corrosion control experience, monitoring data and inspection data. It is generally expected that the operators are responsible for ensuring that their operations are conducted in accordance with regulations and best practices. However, in certain situations, regulations may be enforced. Table 1.17 presents the enforcement ladder that AER uses to categorize the levels of non-compliance.27

Table 1.12 Typical Approval Requirements in Alberta, Canada Regulatory/Reference Documents from Regulatory Agencies Activity

Alberta Energy Regulator (AER)

Alberta Environment)

Construction operation or reclamation of an oil production site

Directive 056: Energy development application guide and schedules

Activities designation regulation; conservation and reclamation regulation, Section 3: Code of practice for oil production sites - IL 95e3 and IL 94e6

Single sour oil well Multiple sour oil or gas wells Multiple sweet oil or gas wells Conduct of an exploration operation for oil sands Oil sands mine

Directive 056 Directive 056 Directive 056

Sweet gas plant processing less than 16 kg/hr of nitrous oxide (NOx)

Oil and Gas Conservation Act, Section 21 and Directive 056

Sweet gas plant processing more than 16 kg/hr of nitrous oxide (NOx)

Oil and Gas Conservation Act, Section 21 and Directive 056

Sour gas processing plant

Directive 056

Environmental assessment; Mandatory and exempted activities regulation

Directive 056

Code of practice for compressor and pumping stations and sweet gas processing plants Activities designation regulation

Directive 056 Activities designation regulation; environmental assessment; Mandatory and exempted activities regulation

The Government of Alberta which administers and enforces Environmental Protection and Enhancement Act

19

)

Guide 23: Guidelines respecting an application for a commercial crude bitumen recovery and upgrading project

1.6 Regulations

In situ oil sands or heavy oil processing plant Commercial oil sands, heavy oil extraction, upgrading or processing plant producing more than 2000 m3 of crude bitumen or derivatives/day Sweet or sour compressor or pump stations Tank farm or Bulk petroleum storage facility Pipelines Oil refinery

Activities designation regulation, code of practice for exploration operations Environmental assessment; Mandatory and exempted activities regulation Code of practice for compressor and pumping stations and sweet gas processing plants; Activities designation regulation, A.R. 211e96 Code of practice for compressor and pumping stations and sweet gas processing plants; Activities designation regulation, substance release regulation, Section 14e1 Activities designation regulation; environmental assessment; Mandatory and exempted activities regulation Activities designation regulation

20

CHAPTER 1 The Oil and Gas Industry

Table 1.13 Energy Resources and Conservation Board Pipeline Application Procedure24 Schedule Category

Type of Application

1.0 2.1 2.2 2.3 2.4 3.0 4.1 4.2 4.3

Energy development application Facility development license Gas plants e facility H2S information Compressor/Pump e facility Pipeline license Well license Multiple wells pad location Well H2S information

Table 1.14 Examples of USA Regulatory Bodies for Gas Networks Sector

Regulator

Gas wells Production pipeline Transmission pipeline

Unregulated Regulated in some states by State regulators Federal Energy Regulatory Commission (FERC) and Pipeline Hazardous Materials Safety Administration (PHMSA) Regulated in some states by State regulators Regulated in some states by State regulators

Storage Distribution

In addition, Canadian environmental protection agencies may regulate conservation and reclamation activities on private land for gathering, transmission, and distribution pipelines. Additional approvals from environmental, fisheries, and ocean governing agencies may also be required to construct, operate, or discontinue the pipelines. In addition to these government approvals, operators must also obtain the landowner’s permission for construction and maintenance of pipelines. The Federal Energy Regulatory Commission (FERC) oversees the USA interstate natural gas pipeline industry. The commission regulates both the construction of interstate natural gas pipelines and transportation of natural gas in interstate commerce. Companies wishing to build interstate pipeline facilities or operate pipelines must first obtain a Certificate of Public Convenience and Necessity from FERC. This is done to ensure that pipeline facilities benefit consumers, are compatible with the environment, and minimize interference with the public’s and landowners’ rights-of-way along the pipeline. The Office of Pipeline Safety (OPS), within the US Department of Transportation (DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA), regulates hazardous liquid and gas onshore pipelines. Offshore pipelines are regulated by the US Department of Interior’s Minerals Management Service (MMS).

1.6 Regulations

21

Table 1.15 Some Government Bodies Regulating Oil and Gas Industry in Canada and USA Country

Regulator

Function

Canada

National Energy Board (NEB)

Canada Canada

Transportation Safety Board Alberta Energy Regulator (AER), Alberta

Canada

British Columbia Oil and Gas Commission New Brunswick Board of Commission of Public Utilities Resources, Economic Development, Minerals, Oil and Gas, North West Territories National Energy Board (COGOA)

Federal regulator of pipelines crossing country and provincial borders Failure investigation Regulator of all oil and gas infrastructure in Alberta, Canada Regulator of oil and as infrastructure in British Columbia Regulator of oil and as infrastructure in New Brunswick Regulator of oil and gas infrastructure in North West Territories

Canada Canada

Canada Canada Canada

Northern Pipelines Beaufort-Mackenzie Mineral Development Commission Nova Scotia Offshore Petroleum Board

Canada

Nova Scotia Utility and Review Board

Canada

Ontario Energy Board and Technical Standards and Safety Authority Quebec Regie de l’Energie (Quebec Energy Board) Saskatchewan Energy and Mines Yukon Territory Department of Economic Development Oil and Gas Resources Branch Manitoba Public Utilities Board and Manitoba Department of Energy and Mines Prince Edward Island Energy and Mines FERC Pipeline and Hazardous Materials Safety Administration (PHMSA) US Department of Interior - Minerals Management Service California Office of Spill Prevention and Response California Division of Oil, Gas, & Geothermal Resources Pages California State Fire Marshall’s Office Pages

Canada Canada Canada

Canada

Canada USA USA USA USA USA USA

Regulator of oil and gas infrastructure in Northwest Territories and Nunavut Regulator of oil and gas infrastructure in Beaufort and Mackenzie area Regulator of offshore oil and gas infrastructure in Nova Scotia Regulator of onshore oil and gas infrastructure in Nova Scotia Regulators of Ontario Regulator of Quebec Regulator of Saskatchewan Regulator of Yukon

Regulators in Manitoba

Regulator in Prince Edward Island Regulator of gas network Regulator of onshore pipeline Regulator of offshore pipeline Regulator in California state Regulator in California state Regulator in California state Continued

22

CHAPTER 1 The Oil and Gas Industry

Table 1.15 Some Government Bodies Regulating Oil and Gas Industry in Canada and USA Continued Country

Regulator

Function

USA USA

California State Lands Commission Washington Utilities & Transportation Commission Oregon Department of Environmental Quality Alaska Department of Environmental Conservation National Transportation Safety Board (NTSB) Office of Pipeline Safety US Coast Guard (USCG)

Regulator in California state Regulator in Washington state

USA USA USA USA USA

Regulator in Oregon state Regulator in Alaska state Failure investigators Regulator of oil and gas pipelines Security of ocean infrastructure

Table 1.16 Comparison of Different Philosophies of Regulations25 Type of Regulations Aspects of Regulations

Prescriptive

Regulations provide

Direction on methods

Compliance measured by Risk approach Compliance determined primarily through

Check lists Deterministic Inspection

Goal-Oriented (Descriptive)

Goal-Based (Descriptive)

Direction on methods and description of desired end states Check lists and professional judgment Risk informed Inspection and audit

Description of desired end states Professional judgment Risk based Audit

The minimum pipeline safety standards are prescribed in the US Code of Federal Regulations (CFR), Title 49, ‘Transportation’, Parts 192–195. • • • •

Part Part Part Part

192: 193: 194: 195:

Transportation of natural and other gas by pipeline Liquefied natural gas facilities Response plans for onshore oil pipelines Transportation of hazardous liquids by pipelines

Regulations of pipelines are often based on rigorous standards and best practices developed by various industry, technical, and scientific associations. The voluntary consensus standards and best practices are developed as a method of improving the individual quality of a product or system. Table 1.18 presents some organizations that develop standards pertaining to oil and gas industry.

Table 1.17 Alberta (Canada) Provincial Government’s Enforcement Ladder26 Compliance

Magnitude of the Issue

Types of Issue

Minor non-compliance

Does not result in a direct threat to the public and/or the environment and does not adversely effect oil and gas operations

Well/facility/pipeline identification sign(s) are not posted and are inadequate Valve handle(s) missing Oil or salt water staining on lease Required calibration tag not attached to measurement device

1 2 3

Blowout preventer failed to operate properly Tank vapor recovery unit not functional allowing H2S to vent Unaddressed spill on or off lease No crossing agreement on pipeline construction

2

Major non-compliance

The operator has failed to address an issue and/or the issue has the potential to cause an adverse impact on the public and/or the environment

Level

4

3

Instruction Instruction Full or partial suspension of operations when safe to do so. A non-compliance event will be added into the corporate data information system. Full or partial suspension of operation when safe to do so. Suspension will remain in effect until documented meeting with senior company representative with provincial authority (VP/Pres) is held. Level: Instruction and temporary suspension of certain operations to correct deficiencies and alleviate impact or potential impact. Full or partial suspension of operations to alleviate impact or potential impact when safe to do so. Suspension will remain in effect until documented meeting with senior company representative (Vice president/ President) with provincial authority is held. Immediate suspension (full or partial) of operations to alleviate issue when safe to do so. Suspension will remain in effect until documented meeting with senior company representative

23

Continued

1.6 Regulations

4

Enforcement Ladder

24

Compliance

Serious non-compliance

Magnitude of the Issue

Causing or may cause a significant impact on the public and/or environment

Types of Issue

Blowout preventer(s) missing Unaddressed spill into water, operator aware, no action is being taken Conducting an activity without an approval and/or license where required H2S odor present, operator aware, no action is being taken

Level

3

4

Enforcement Ladder with provincial authority is held. Company also confirms compliance at this and all similar facilities and submits a written acceptable action plan including examination of cause and future prevention plans and commitments. Full or partial suspension of operations to alleviate impact or potential impact when safe to do so. Suspension will remain in effect until documented meeting with senior company representative with provincial authority is held. Immediate suspension (full or partial) of operations to alleviate issue when safe to do so. Suspension will remain in effect until documented meeting with senior company representative with provincial authority is held. Company also confirms compliance at this and all similar facilities and submits a written acceptable action plan including examination of cause and future prevention plans and commitments.

CHAPTER 1 The Oil and Gas Industry

Table 1.17 Alberta (Canada) Provincial Government’s Enforcement Ladder26 Continued

1.6 Regulations

25

Table 1.18 Selected Technical Organizations Developing Standards for Oil and Gas Industry Association

Abbreviation

Association Francaise de Normalization Association Suisse de Normalization American Bureau of Shipping American National Standards Institute American Petroleum Institute American Society of Mechanical Engineers ASTM International (formerly American Society of Testing and Materials) American Welding Society American Water Works Association American Petroleum Industry American Gas Association American Society of Mechanical Engineers American Nation Standard Institute American Society of Petroleum Engineers Association of Oil Pipelines Badan Kerjasama Standardisasi Lipi-Ydni (Indonesia standard organization) British Standards Institute Bureau of Indian Standards Canadian Association of Petroleum Producers Canadian Energy Pipelines Associations Canadian Standards Association Canadian Gas Association China Association for Standardization Commission Venezolana de Normas Industriales (Venezuela) Composites Engineering and Applications Center Deutsches Normenausschub (Germany) Direccion General de Normas (Mexico) Ente Nazionale Italiano de Unificazione (Italy) Gas Research Institute Gas Technology Institute (formerly Gas Research Institute) Indian Standards Institute International Organization for Standards Interstate Natural Gas Association of America Japanese Industrial Standards Committee Nederlands Normalisatie Instituut Norges Standardiseringsforbund NACE International (Formerly National Association of Corrosion Engineers)

AFNOR SNV ABS ANSI API ASME ASTM AWS AWWA API AGA ASME ANSI ASPE AOP

BSI BIS CAPP CEPA CSA CGA COVENIN CEAC DIN DGN UNI GRI GTI ISI ISO INGAA JISC NNT SSF NACE Continued

26

CHAPTER 1 The Oil and Gas Industry

Table 1.18 Selected Technical Organizations Developing Standards for Oil and Gas Industry Continued Association

Abbreviation

NORSOK/Standard Norge National Fire Protection Association Oesterreichisches Normungsinstitut (Austria) Pipeline Research Council International Standards Association of Australia Saudi Arabian Standards Organization Singapore Institute of Standards and Industrial Research Standardisering Kommissionen (Sweden) Society of Protective Coating United Kingdom Offshore Operators Association US Coast Guard USSR State Committee for Standards (Russia)

NORSOK NFPA ONORM PRCI SAA SASO SIRU SIS SSPC UKOOA USCG

Despite the best efforts of companies, industry, regulatory agencies, and stakeholders, oil and gas infrastructure may sometimes fail, releasing their contents to the environment. The impact of the failure depends on its size and type, the location and type of infrastructure, and the products being transported. The failures may be broadly classified into accidents, incidents, and leaks. Accidents are major occurrences, such as a line rupture or an instantaneous tearing or fracturing of material, which immediately shut down the system. Incidents are minor leaks and operational malfunctions that affect the safety of the system and that curtail operations. Leaks are loss of product through small openings, cracks, or holes that do not immediately affect pipeline operation and which may have gone unnoticed for a long time. When a failure occurs, normally another government body investigates it. In Canada, for example, the Transportation Safety Board (TSB) investigates incidents on federally regulated infrastructure to identify direct causes and contributing factors. In the USA, the National Transportation Safety Board (NTSB) investigates pipeline significant accidents (fatality or substantial property damage; typically any failure causing more than five gallons or equivalent amounts of hydrocarbon release). The investigatory agencies conduct failure analysis and root-cause analysis. The investigatory agencies may also issue safety recommendations aimed at preventing future accidents.

1.7 The significance and impact of corrosion in the oil and gas industry In order to use hydrocarbons as energy source, they must be extracted from underground, all other nonenergy containing products separated from them, and the different types of hydrocarbons separated from one another. These processes occur at various stages between the wells where the hydrocarbons are found and the locations where they are used as fuels. Between the sources of the hydrocarbons and the locations in which they are used as fuels, there is a vast network of oil and gas infrastructure.

1.7 The significance and impact of corrosion in the oil and gas industry

27

Table 1.19 Annual Corrosion Cost in Major Sectors of USA Oil and Gas Industry3 Annual Cost of Corrosion in US (Million US Dollars)

Sector Production) Transmission- pipeline Transportation-Tanker)) Storage Refining Distribution Special

1,372 6,973 2,734 7,000 3,692 5,000 Not known

) The amount is only for production from conventional sources (corrosion cost for production from non-conventional and renewal sources is not included) )) World total

Table 1.20 Types of Failures and their Causes in Oil and Gas Industry27 Causes Location

Pre-Service

In Service

Main body

Mechanical damage Defective material Transportation damage

Joints (including weld)

Defective joints

Mechanical damage Defective material Corrosion (internal and external) Cracking (Hydrogen-stress, stress-corrosion, sulfide-stress and stepwise) Defective weld Weld (heat-affected) zone corrosion Incompatibility between main body and joint Secondary loads from soil movement Earthquake Internal combustion Sabotages Interferences (telluric, alternating current, and stray) Incompatibility between material and environment (i.e., selection of wrong material)

All components

Table 1.19 presents the major sectors of oil and gas network and Chapter 2 describes their characteristics. This vast network comprises different materials exposed to different environments and to different operating conditions (flow, temperature, and pressure). As consequence of various interactions, the integrity of the infrastructure may be compromised resulting in failures. In general, the causes of failure may be classified into two categories: pre-service and in service. Table 1.20 summarizes the major factors that can compromise the integrity of the oil and gas network.28 From Table 1.20 it is obvious that corrosion is a key cause of failure. Recently, the cost of corrosion in the

28

CHAPTER 1 The Oil and Gas Industry

USA was surveyed. The cost of corrosion in the oil and gas industry from that survey3 and from other studies is summarized in the following sections.

1.7.1 Production sector Components of production sector include drill pipe (see section 2.2), casing pipe (see section 2.3), downhole tubular (see section 2.4), acidizing pipe (see section 2.5), water generator (see section 2.6), gas generator (see section 2.7), wellhead (see section 2.10), production pipeline (see section 2.11), gas dehydration facility (see section 2.14), oil separator (see section 2.15), lease tank (see section 2.18), and waste water pipeline (see section 2.19). The oil and gas production sector may be broadly classified into downhole and surface units. • •

The downhole unit consists of drill pipe, casing pipe, downhole tubular, acidizing pipe, water generator, and gas generator. The surface unit consists of the wellhead, production pipeline, gas dehydration facility, oil separator, lease tank, and waste water pipeline.

The annual capital expenditure of onshore oil and gas production sector in the USA is estimated at $4.0 billion; of which $320 million (8%) is directly related to corrosion control. The annual operating expenditure of the onshore oil and gas production sector in the USA is estimated at $1.372 billion; of which $1.052 billion (76%) is directly related to corrosion control. Of that $1.052 billion, $589 million is spent on controlling corrosion in downhole units, and $463 million is spent on controlling corrosion of surface units. There are approximately 0.6 onshore downhole tubular failures per year per well, and 30% of these failures are caused by corrosion. Each onshore downhole tubular failure incurs $3,000 of direct cost. It is difficult to repair and replace downhole tubulars operating offshore. Therefore additional precautions are taken when maintaining these infrastructures. For this reason, the cost of corrosion control for offshore downhole tubulars is higher than onshore downhole tubulars. Table 1.21 presents the average corrosion cost associated with maintaining a surface unit in the USA; as the amount of water produced, along with oil, increases the cost of corrosion also increases. There is a vast network of production pipelines between the wellhead and gas dehydration facilities, as well as between wellhead and oil separators. Figures 1.5, 1.6, and 1.7 present statistics for production pipelines in Alberta, Canada.29,30 Figure 1.8 presents factors that cause failure of production pipelines. Figure 1.9 presents the number of failures caused by corrosion. More than 70% of failures were caused by corrosion; of which about 58% were due to internal corrosion and 12% were due to external corrosion.

Table 1.21 Corrosion Cost in Production Pipeline Unit in the USA3 Production

Cost per Barrel, $

Offshore oil Onshore oil Offshore water Onshore water

0.40 0.20 0.14 to 0.18 0.07 to 0.09

1.7 The significance and impact of corrosion in the oil and gas industry

29

400,000 Crude oil Natural gas Sour gas Water Multiphase Others Total

Length, Km

300,000

200,000

100,000

0 1980

1985

1990

1995

2000

2005

2010

Year

FIGURE 1.5 Lengths of Production Pipelines in Alberta, Canada.28,29 (The reduction of pipeline length in 1998 is due to transfer of regulatory responsibility of some pipelines to federal regulator).

88.9 (3)

60,000

1219.0 (48)

1067.0 (42)

914.0 (36)

864.0 (34)

762.0 (30)

660.0 (26)

610.0 (24)

559.0 22)

508.0 (20)

457.0 (18)

406.4 (16)

355.6 (14)

4. 3 16 (4) 8. 3 21 (6) 9. 27 1 (8 3. ) 1 32 (10 3. ) 9 35 (12 5. ) 6 40 (14 6. ) 4 45 (16 7. ) 0 50 (18 8. ) 0 55 (20 9. ) 0 61 2 0. 2) 0 66 (24 0. ) 0 76 (26 2. ) 0 86 (30 4. ) 0 91 (34 4. ) 10 0 (3 67 6) . 12 0 (4 19 2 .0 ) (4 8)

) (3

11

.9 88

60

.3

(2

)

0

323.9 (12)

219.1 (8)

20,000

273.1 (10)

40,000 60.3 (2)

Length, km

80,000

168.3 (6)

114.3 (4)

100,000

Diameter mm (inches)

FIGURE 1.6 Typical Diameter of Gas Production Pipelines in Alberta, Canada.28,29

30

CHAPTER 1 The Oil and Gas Industry

3,500

Length of Pipelines, Km

3,000 2,500 2,000 1,500 1,000 500

60 .3 (2 ) 88 .9 ( 11 3) 4. 3 16 (4) 8. 3 21 (6) 9. 1 (8 27 ) 3. 1 32 (10 3. ) 9 35 (12 ) 5. 6 ( 1 40 4) 6. 4 45 (16 ) 7. 0 50 (18 ) 8. 0 (2 0 55 9. ) 0 61 22 ) 0. 0 66 (24 ) 0. 0 76 (26 ) 2. 0 ( 86 30 ) 4. 0 ( 3 91 4) 4. 0 (3 6)

0

Diameter, mm (inches)

FIGURE 1.7 Typical Diameter of Oil Production Pipelines in Alberta, Canada.28,29

Some components, such as open mining (see section 2.8), in situ production (see section 2.9), heavy crude oil pipelines (see section 2.12), hydrotransport pipelines (see section 2.13), recovery centers (see section 2.16), upgraders (see section 2.17), and tailing pipelines (see section 2.20), are exclusively used in producing oil from oilsands. This part of the industry is relatively new and expanding rapidly. The corrosion cost of these components is not fully understood. Oilsands plants can cost $10 billion or more to build. Individual companies in Canada spend over $20 million in corrosion control program per year on just one operating field. One study does however indicate that the annual corrosion cost for just one company producing oil from oilsands is over $450 million.31

1.7.2 Transportation – pipeline sector Transmission pipeline sector normally includes pipelines (see section 2.21), compressor stations (see section 2.22), pump stations (see section 2.23), and pipeline accessories (see section 2.24). They operate mostly onshore, transporting large quantities of products across countries or continents. In USA, there are more than 483,000 km (300,000 mi) of natural gas transmission pipelines operated by over 60 companies, and 217,000 km (135,000 mi) of hazardous liquid transmission pipelines operated by more than 150 companies. In Canada there are approximately 45,000 km of oil and gas transmission pipelines. In the USA as of 1998, total investment for establishing gas pipeline network was $63.1 billion and that for establishing the liquid pipeline network was $30.2 billion; i.e., the total capital investment for the transmission pipeline industry was $93.3 billion. If this transmission pipeline network were to be

1.7 The significance and impact of corrosion in the oil and gas industry

31

FIGURE 1.8 Alberta, Canada Production Pipeline Failure Data for 1980–2005.28,29

replaced today the cost would be $541 billion. The annual capital investment is estimated at $8.1 billion, based on construction cost of $746,000 per km ($1.2 million per mi). The annual maintenance cost is estimated at between $470 and $875 million. Table 1.22 presents the annual cost of corrosion in the USA transmission pipeline sector. The total annual cost ranges between $5.40 billion and $8.56 billion (with an average of approximately $7 billion). Of the 7 billion dollars, 52% is for operation and maintenance (O&M), 38% is capital (including replacement cost), and 10% is for repair after failures (non-related O&M). It should be noted that the corrosion cost estimated in the survey also included the corrosion cost of 45,000 km (38,000 mi) of natural gas gathering pipelines and 34,000 km (21,000 mi) of crude oil gathering pipelines.1,3 Table 1.23 summarizes the accidents and incidents associated with transmission pipelines. 25% of these accidents were caused by corrosion. Of these, approximately 35% of gas transmission pipeline failures were due to external corrosion, and approximately 65% were caused by internal corrosion. Approximately 65% of oil transmission pipeline failures were due to external corrosion and approximately 35% were due to internal corrosion.

32

CHAPTER 1 The Oil and Gas Industry

1,000

100

Failures due to internal corrosion

800

80

600

60

400

40

200

20

0 1975

1980

1985

1990

1995

2000

2005

Percentage of failures

Number of Failures

Percentage of failures due to internal corrosion

0 2010

Year

FIGURE 1.9 Failures Caused by Corrosion of Production Pipelines in Alberta, Canada.28,29

Table 1.22 Summary of the Total Annual Cost of Corrosion in USA Transmission Pipeline Sector3 Estimate ($ x million) Corrosion Cost Cost of capital Operations and maintenance (O&M) Cost of failures (Non-related O&M)) Total cost due to corrosion

Minimum

Maximum

Average

Percent

2,500 2,420

2,840 4,840

2,670 3,630

38 52

471

875

673

10

5,391

8,555

6,973

100

)

non-related O&M costs include indirect costs associated with fatalities, injuries, loss of throughput, and legal expense

Table 1.24 presents the data for the transmission pipeline sector in the USA between 1970 and 1984.32 There were 5,872 failures during this period, of which approximately 17% were caused by corrosion. Of the corrosion failures, 40% were due to external corrosion and 27% were due to internal corrosion. About 40% of the failures occurred in pipelines of diameter 10 or 20 inches; almost all failures were due to corrosion. Most failures of larger diameter pipelines were due to external corrosion, and most failures of smaller diameter pipelines were due to internal corrosion. About 50% of corrosion failures occurred in pipelines that were 30 years old, or older. Over 90% of corrosion failures were due to localized pitting corrosion.

1.7 The significance and impact of corrosion in the oil and gas industry

33

Table 1.23 Transmission Pipeline Accidents and Incidents in USA3 Accidents/Incidents Number of major accidents Number of accidents/10,000 miles) Number of injuries) Number of fatalities) Property damage ($M)) Total accidents)) Total accidents due to corrosion)) Percent of accidents due to corrosion)) Percent of accidents due to external corrosion)) Percent of accidents due to internal corrosion)) Percent of non-corrosion accidents)) )

Natural Gas Transmission

Hazardous Liquid

500 14 100 22 180 448 114 25.4

675 42 100 16 330 1,116 270 24.3

36.0

64.9

63.2

33.6

0.8

1.5

)

Based on data between 1989 and 1998 e this data does not distinguish the accidents/incidents caused by corrosion )) Based on data between 1994 and 1999

Table 1.24 Service Failures of Natural Gas Transmission and Gathering Lines Between 1970e1984 as Reported to DOT USA32 Cause Outside force Material failure Corrosion Other Construction defect Construction of material Total

Number of Events 3,144 990 972 437 284 45 5,872

Percentage 53.5 16.9 16.6 7.4 4.8 0.8 100.0

1.7.3 Transportation – other modes sector In addition to pipelines, oil tankers (ships) (see section 2.25), railcars (see section 2.27), and trucks (see section 2.28) transport oil and gas. Table 1.25 presents some characteristics of these modes of transportation. Currently there are more than 9,320 tankers and carriers transporting oil across the world. These tankers constitute approximately 11% of the world’s total number of ships. The total gross tonnage of tankers and carriers is 168,011,588 metric tons (185,200,000 tons). They transport oil and gas, chemicals, liquefied gas, ores, and other materials; of which 35% transport oil and gas. The global

34

CHAPTER 1 The Oil and Gas Industry

Table 1.25 Some Modes) of Transportation of Oil and Gas3 Transportation Across

Vehicle

Land

Trucks

Water

Trains Ships

Air

Airplanes

Loading/Unloading Facilities

Containers

Refineries, terminals, and consumer tanks Stations Directly from production wells and docks Airports

Tanks Tanker train cars Tanks and drums Special containers

)

Other than pipelines

Table 1.26 Average Annual Corrosion Cost for Construction of Ships to Transport Oil and LNG3

Type of Ship Oil tankers LNG (Refrigerated cargo)

Number

Percentage Cost of Construction Due to Corrosion

Average Cost of Vessel ($ x million)

Average Corrosion Cost per Year ($ x million)

6,920 1,441

13 10

50 6

1,799 35

annual cost of corrosion in the shipping industry is approximately $7.5 billion. Based on the proportion of ships carrying oil and gas, the average annual cost attributable to transport of oil and gas is estimated at approximately $1.835 billion (Table 1.26). This estimate however does not include corrosion costs in liquefaction and regasification facilities for LNG (see section 2.26). More than 483,000 car loads of petroleum and coke are transported annually by railroad cars in USA. Based on the percentage of commodity transported, the annual cost of corrosion in USA for transporting petroleum and coke by the railroad industry is estimated at $11.16 million. Trucks are used when construction of pipelines is not economical, the materials are only to be transported for shorter distances, or the volume of materials transported is small. In the USA annually, there are at least 300 million shipments transporting over 3.1 billion metric tons of hazardous materials, of which about 2.6 billion metric tons are petroleum products. The average annual cost of corrosion for all hazardous materials transportation is over $887 million. The annual corrosion cost includes the cost of the transporting vehicles ($400 million per year), the cost of specialized packaging ($487 million per year), and indirect costs ($0.5 million per year). The indirect costs include the cost of cleaning due to accidental release of hazardous materials.

1.7.4 Storage tank sector There are approximately 8.5 million aboveground storage tanks (ASTs) and underground storage tanks (USTs) for storing hazardous materials (HAZMAT) in the USA. Table 1.27 presents details of these storage tanks. Most of these storage tanks are used to store oil (see section 2.30) and gas (see section 2.29). Most of the storage tanks are regulated in the USA by Spill Prevention Countermeasure and

1.7 The significance and impact of corrosion in the oil and gas industry

35

Table 1.27 Statistics of Aboveground and Underground Storage Tanks in USA3 Types of Tanks

Regulated by

Product

Type of Storage Tanks

Various Office of Underground Storage Tanks (OUST)

Miscellaneous Petroleum & HAZMAT

UST UST

Heating oil LPG/Propane Kerosene

AST and UST Mostly AST Mostly AST

Unregulated

TOTAL

Number of Tanks 133,400 742,805 3,283,752 1,825,984 147,383 8,506,600

Table 1.28 Volume Capacity of Storage Tanks Under SPCC Regulation3 Used in Oil production Petroleum refining and related industries Petroleum bulk stations and terminals Gasoline service stations Fuel oil storage )

Total Capacity, m3 x million) 54.4 288.3 44.0 37.0 0.9

Based on 1995 survey

Control (SPCC) or by the Office of Underground Storage Tanks (OUST). A total of 2.5 million tanks are regulated by SPCC, 0.75 million tanks are regulated by OUST, and 5.25 million tanks are nonregulated. Table 1.28 presents the volume capacity of the tanks regulated by SPCC. The average annual cost of corrosion for storage tanks in USA is estimated at $7.0 billion.

1.7.5 Refinery sector The annual average cost of corrosion in refineries (see section 2.31) in the USA is estimated at $3.692 billion. This cost includes $1.767 billion for maintenance, $1.425 billion for vessel turnaround, and $0.5 billion for cleaning.

1.7.6 Distribution sector There are approximately 95,000 miles of refined petroleum product pipeline (see section 2.32) in the USA. These pipelines carry refined products from the refineries to consumer terminals (see section 2.33) and to storage tanks. The natural gas distribution systems connect transmission pipelines to city gates as well as city gates to customers (see section 2.34). In the USA, the gas distribution system consists of 2,785,000 km (1,730,000 mi) of relatively small diameter pipelines operating at relatively low pressure. They may be

36

CHAPTER 1 The Oil and Gas Industry

Table 1.29 Leak Incidence by Cause for Distribution Pipelines3 Type of Distribution Lines Mains Services

Number of Leaks Corrosion 83,864 99,024

Third Party 29,566 95,555

Outside Force 12,107 21,814

Construction Defect 6,466 20,965

Material Defect 12,835 32,356

Other

Total Leaks

64,999 138,267

209,837 407,981

broadly divided into 1,739,000 km (1,080,000 mi) of mainlines connecting transmission pipelines and city gates and 1,046,000 km (650,000 mi) of service lines connecting city gates and customers. The service lines are connected to approximately 55 million customers. The diameters of distribution mainlines are typically between 40 mm and 150 mm (1.5 in and 6 in) and those of service lines are typically between 13 mm to 20 mm (0.5 to 0.75 in). The distribution mainlines and service lines serving commercial and industrial establishments are typically larger in diameter than those serving homes. In addition the natural gas may also be distributed using compressed natural gas (CNG) cylinders (see section 2.35). The gas distribution pipelines operate at low pressures, and failures in these pipes result in leaks rather than the ruptures which may occur in high pressure natural gas transmission pipelines. The primary concern regarding the gas distribution pipeline is the accumulation of leaked gases in a confined space, as these will eventually ignite and explode. Table 1.29 presents the causes of failures in gas lines. Corrosion causes approximately 40% of the leaks in mainlines and 24% of the leaks in service lines. In terms of frequency, corrosion causes 8.4–12 leaks per 100 km (13.6–19.3 leaks per 100 mi) in mainlines and 3.9–7.4 leaks per 1,000 services in the service lines. The average annual cost of corrosion in distribution pipelines is approximately $5.0 billion. One data source shows that over a five year period in the USA, 83,864 corrosion leaks occurred in distribution mainlines and 99,024 leaks occurred in service lines. The majority of these leaks were detected and repaired without major incident, but there were 26 major incidents resulting in 4 fatalities and 16 injuries. The cost of these major incidents was $4,923,000 in property damage. The cost of repairing minor leaks is typically between $1,200 and $2,500 per leak in distribution mainlines and $800 and $1,500 per leak in service lines. Table 1.30 presents another set of data obtained between 1989 and 1998. There is currently a tendency to replace metal distribution lines with plastic, but plastic pipes are also susceptible to aging and degradation processes. There were 36,948 leaks in plastic (polyethylene) distribution mainlines and 134,448 leaks in plastic service lines within one year in the USA. In terms of failure frequency, there were 8.5 leaks per 100 km (13.7 leaks per 100 mi) in polyethylene mainlines and 6.21 leaks per 1,000 polyethylene service lines. The leaks in plastic pipes are slightly smaller than those in metallic pipeline, but their frequency is still significant. Recent studies however have indicated that by improving durability of plastic materials and testing the materials under realistic operating conditions, failure frequency of plastic pipeline may be reduced.

1.7.7 Special sector The oil and gas industry also operates pipelines for transporting special products. Some of those special pipelines include diluent pipeline (see section 2.36), high vapor pressure pipeline (see section

References

37

Table 1.30 Gas Distribution Pipeline Accidents and Incidences in USA3 Accidents/Incidents

Natural Gas Distribution

Number of major accidents Number of accidents/10,000 miles) Number of injuries) Number of fatalities) Property damage ($M)) Total accidents)) Total accidents due to corrosion)) Percent of accidents due to corrosion)) Percent of accidents due to external corrosion)) Percent of accidents due to internal corrosion)) Percent of non-corrosion accidents)) )

900 4 700 162 140 708 26 3.7 84.6 3.8 11.6

) Based on data between 1989 and 1998 e this data does not distinguish the accidents/ incidents caused by corrosion )) Based on data between 1994 and 1999

2.37), CO2 pipeline (see section 2.38), hydrogen pipeline (see section 2.39), ammonia pipeline (see section 2.40), and biofuel infrastructure (see section 2.41). In general, the operating conditions (pressure, temperature, flow conditions, and compositions of fluids) in these infrastructure systems are more severe than those of traditional oil and gas pipelines. As a consequence, the corrosion cost of operating these infrastructures is anticipated to be higher. But this sector has only emerged recently, and its corrosion costs have not yet clearly been documented.

References 1. Arunachalam VS, Fleischer. Harnessing Materials for Energy. MRS Bulletin April 2008;33:261. 2. Holditch SA, Chianelli RR. Factors that will influence oil and gas supply and demand in the 21st century. In: MRS Bulletin, vol. 33; April 2008. p. 317–25 (Based on International Energy Agency best estimate for energy supply in 2030 from US energy information administration reference case). 3. Koch GH, Brongers MPH, Thompson NG, Virmani YP, Payer JH. Corrosion Cost and Preventive Strategies in the United States. 6300, Georgetown Pike, McLean, VA: US Department of Transportation, Federal Highway Administration, Research, Development, and Technology, Turner-Fairbank Highway Research Center; March 2002. 22101–2296, FHWA-RD-01–156. 4. Mohitpour M, Golshan H, Murray A. In: Pipeline Design and Construction: A Practical Approach. 3rd ed. Three Park Avenue, New York, 10016: The American Society of Mechanical Engineers; 2007. Table 3.1a, p. 66. ISBN: 0-7918-0257-4. 5. Petroleum Communication Foundation /Canadian Center for Energy Information 2004. http://www. centerforenergy.com/AboutEnergy/ONG/OilsandsHeavyOil/Overview.asp?page¼1; [accessed 24.01.13]. 6. Holditch SA. Tight Gas Sands. Society of Petroleum Engineers (SPE) Paper 103356, Distinguished Author Series (2006) – based on Working document of the National Petroleum Council Global Oil and Gas Study, released on July 18, 2007.

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CHAPTER 1 The Oil and Gas Industry

7. Canadian Upstream Oil and Gas Industry Financial Performance – Outlook 2006–2008 – A Study Prepared for the Canadian Association of Petroleum Producers. March 2006. http://www.capp.ca; [accessed 03.08.06]. 8. Oilsands Workshop SPP Report. Oilsands Experts Group Workshop, Security and Prosperity Partnership of North America, Houston, Texas, January 24–25, 2006. Petroleum Resources Branch, Oil Division, 580 Booth Street, Ottawa. Phone: 992–8642. 9. Papavinasam S, Rahimi P, Williamson S. Corrosion Conditions in the Path of Bitumen from Well to Wheel. Toronto, Ontario, Canada: NACE Northern Area Eastern Conference, Paper Number 2012–02; Oct. 28–31, 2012. 10. Survey of energy resources. 21st ed. World Energy Council. 2007. pp. 93–115. ISBN 0946121265 – http:// www.worldenergy.org/documents/ser2007_final_online_version_1.pdf; [accessed 13.11.07]. 11. About Oil Shale. Argonne National Laboratory. http://ostseis.anl.gov/guide/oilshale/index.cfm, Retrieved 2007–10–20. 12. US Department of Energy. Modern shale gas development in the United States. April 2009, p. 17. Available at: http://www.netl.doe.gov/technologies/oil-gas/ReferenceShelf/RefShelf_archive.html#Reports09; [accessed 12.07.13]. 13. Squarek John, Dawson Mike. Coalbed methane expands in Canada. Oil Gas J July 2006;24:37–40. 14. Earth Sciences Sector. Economic Opportunities Evaluation, Reports 2009. http://www.nrcan.gc.ca/ evaluation/reports/2009/2831?destination¼node%2F2831; [accessed 23.01.13]. 15. Barron R. Ethanol’s Growing Pains. GreenTech Media, (Source: F.O. Licht: Renewable Fuels Association), www.greentechmedia.com/articles/ethanols-growing-pains.html; September 4, 2007. 16. Report on the Technical Feasibility of Integrating an Annual Average 2% Renewable Diesel in the Canadian Distillate Pool by 2011. http://oee.nrcan.gc.ca/transportation/alternative-fuels/programs/nrddi/report-2010/ toc.cfm?attr¼16; [accessed 12.01.11]. 17. Anand A, Paramesh MHN, Krishnamurthy SR, Mani SR, Papavinasam S. Compatibility of Metals in Jatropha Oil. NACE 2011, Paper Number 11140. USA: Houston, Texas; 2011. 18. Paramesh MHN, Anand A, Krishnamurthy SR, Mani SR, Papavinasam S. Corrosivity of Pongamia Pinnata Biodiesel – Diesel Blends on a Few Industrial Metals. Paper Number 11142, NACE 2011. USA: Houston, Texas; 2011. 19. A timeline of highlights from the histories of ASTM Committee D02 and the Petroleum Industry. http://www. astm.org/cgi-bin/SoftCart.exe/COMMIT/D02/to1899_index.html?Lþmystoreþgstz2228þ1208247757; [accessed 14.04.08]. 20. Pipeline Transport Retrieved from: http://en.wikipedia.org/wiki/pipeline_transport; [accessed 13.04.08]. 21. History of Refining. http://www.setlaboratories.com/overview/tabid/81/Default.aspx; [accessed 23.01.13]. 22. Silcox WH, Bodine JA, Burns GE, Reeds CB, Wilson DL, Sauve ER. Chapter 18, Offshore Operations. In: Petroleum Engineering Handbook. Richardson, TX, USA: Society of Petroleum Engineers; 1987. ISBN: 1–5563–0101–3. 23. Second Panel Forum. Hydrogen Pipeline Transmission: Updates and Opportunities. Calgary, Alberta, Canada: ASME 6th International Pipeline Conference, Sept. 25–29; 2006. 24. Revie RW, Uhlig HH. Corrosion and Corrosion Control. 4th ed; 2008. Wiley Hoboken, NJ. 25. Schedule 2: Facility Licence Application, Version May 1, 2007, Alberta Energy Regulator (AER), 250–5th Street SW, Calgary, Alberta, Canada, T2P 0R4. 26. Murray A. Pipeline Integrity – An Ounce of Prevention. Calgary, Alberta, Canada: Second Canada-India Workshop; September 25–26, 2008. 27. Directive 56: Section 1.4: Requirements, Enforcement, and Expectations, Version May 1, 2007, Alberta Energy Regulator (AER), 250–5th Street SW, Calgary, Alberta, Canada, T2P 0R4.

References

39

28. Kiefner JF, Eiber RJ. Pipeline Operation and Maintenance: Service Problems. In: McKetta JJ, editor. Piping Design Handbook. 270b Madison Avenue, New York: Marcel Dekker; 1992. 10016, ISBN: 0–8247–8570–3, p. 968. 29. Utilities Board (ERCB) 91-G Report. Alberta Energy Regulator (AER), 250–5th Street SW, Calgary, Alberta, Canada, T2P 0R4 (Historical report) due to database merger in 2007 there was some correction in the length of the pipelines. 30. Alberta Energy, Utilities Board. Report 2007-A: Pipeline Performance in Alberta, 1990–2005. 250-5th Street SW, Calgary, Alberta, Canada: Alberta Energy Regulator (AER); April 2007. T2P 0R4. 31. Neville A, Reza F. Erosion-Corrosion of Cast White Irons for applications in Oilsands Industry; 2007. NACE Paper #7678, Houston, Texas, USA, 2007. 32. Eiber RJ, Jones DJ, Kramer GS. Pipeline Failure. In: McKetta JJ, editor. Piping Design Handbook. 270b Madison Avenue, New York: Marcel Dekker; 1992. p. 1024. 10016, ISBN: 0–8247–8570–3.

CHAPTER

Oil and Gas Industry Network

2

2.1 Introduction For hydrocarbons to be used as an energy source, they need to be extracted from underground, all other non-energy containing products separated from them, and the different types of hydrocarbons further separated from one another. These processes occur at different locations in the oil and gas industry network operating between the underground wells where the hydrocarbons are found and the locations where they are used as fuels, for example, in an automobile. Figures 2.1 and 2.2 respectively present

FIGURE 2.1 Paths of Conventional Crude Oils from Well to Wheel.

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00002-9 Copyright Ó 2014 Elsevier Inc. All rights reserved.

41

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FIGURE 2.2 Paths of Natural Gas from Reservoir to the User.

typical paths of oil and gas from the well to their final locations of use. This chapter presents various operation conditions found at different points in these paths, different types of materials used in those locations, and different types of corrosion that may take place.

2.2 Drill pipe When geological and geophysical clues indicate the probability of the presence of hydrocarbon, a well is drilled. Depending on the ground and the depth of the hole, drilling may take less than a day or many months. Information about rocks and types of hydrocarbons contained in the rocks is collected. The information is used to decide whether a well could be used to produce hydrocarbons or should be abandoned. Typical drilling equipment (Figure 2.3) includes a drill head, drill pipe, rotary equipment (to insert the drill pipe), joints (to connect drill pipes), drilling fluid (to lubricate the drill head to wash away the cuttings, and to maintain pressure in the hole), and blowout preventer (BOP) (to control pressure and to prevent blowout). Some drilling equipment is thick (6 in. (152.4 mm) or greater wall thickness) and heavy (several tons of mass). The type of material depends on the operating pressure. Table 2.1 presents typical construction materials of various parts of drill pipe. Table 2.2 presents standards providing guidelines

2.2 Drill pipe

43

Rotary box connection Tool joint box member Drill pipe

Tool joint box member Rotary pin connection Rotary box connection

Crossover sub

Rotary pin connection Rotary box connection Drill collar

Rotary pin connection Rotary box connection Bit sub Rotary box connection Rotary pin connection

Bit

FIGURE 2.3 Typical Components of Drilling Equipment.1 Reproduced with permission from MetCorr.

to complete drilling, including material selection. Drilling equipment may be constructed from carbon steel, titanium, or aluminum. Most drill pipe failures occur due to corrosion fatigue (see section 5.16). Drill heads and drill pipes, especially those made from high strength materials, may suffer sulfide stress cracking (SSC) in the presence of hydrogen sulfide (H2S) (see section 5.18.4). Although the reservoir itself is the main source of H2S, the degradation of certain drilling fluids can also produce

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Table 2.1 Materials of Construction of Drill Pipes2 Drill Pipe Components

Hardness) )

Drill head Drill pipe

HRC 22 e30 HRC 20e34 HB 135

Tool joints

HRC 30e37 HB 285 BHN 285e341

Drill collars

Other components (drill jars, Various values depending on stabilizers, and barrels) the environment

Materials Carbon steel Carbon steel Aluminum (with steel joints) Titanium Carbon steel Carbon steel MonelÔ)) Stainless steel Beryllium copper Carbon steel

)

See section 3.2.1c for description of hardness and the scales used to represent hardness. In the presence of H2S the maximum hardness is reduced to HRC 22. This restriction applies to all materials used in the drilling assembly in the presence of H2S )) Nickel alloys consist of nickel (up to 67%), copper (typically up to 34%), carbon, manganese, sulfur, silicon, iron, and other trace elements

H2S. Drilling fluid can be altered relatively easily. For example, using oil-based instead of water-based drilling fluid reduces corrosion susceptibility. If only water-based fluid is available, its corrosivity may be reduced by controlling the pH, removing H2S and oxygen, and adding corrosion inhibitors. Tool joints are larger in diameter than the drill pipe. As a consequence their external surface suffers wear and abrasion. To control wear, the tool joints are overlayed (commonly known as hard-facing) with an alloy that has greater wear resistance. Tungsten carbide, chromium, molybdenum, nickel, tin, and boron particles are used to increase the wear resistance of joint materials. Because the hardness of the tool joints is higher than drill pipe, tool joints are more susceptible to SSC than drill pipe. The BOP components are typically over designed, because any failures here would release the contents of the well uncontrollably. For this reason, BOP failures are very rare. However failures due to SSC, stress-corrosion cracking (SCC) (see section 5.17), and brittle fracture (see section 3.2.1) of BOP components have occurred.

2.3 Casing The casing serves as a structural retainer in the well. It separates the oil and gas from other undesirable underground fluids such as water. Once the feasibility of producing hydrocarbon from the well has been established, the drill equipment is removed and a casing pipe is inserted into the well. Concrete is pumped into the well outside the casing pipe. The casing pipe along with the concrete prevents the well from collapsing. Once the casing pipe reaches a predetermined depth, a perforating gun is lowered to punch holes in the casing to start production. Gravel pack screens may be placed at the bottom of the casing pipe to control the production of sand. The gravel pack typically contains a perforated inner tube and outer wire mesh screens.

2.3 Casing

45

Table 2.2 Standards Providing Guidelines for Selecting Materials for Drill Pipe Components Organization

Designation Number

API API API API API

16A 6A 5D 53 7G-2

API

53

ISO ISO

13500 13626

ISO

13625

ISO

13533

ISO

13534

ISO

10407

ISO ISO ISO

13535 11961 17078

NORSOK Industry Recommended Practice (IRP))

M-702 IRP-1 IRP-2 IRP-6 IRP-7 IRP-14 IRP-22

Title Recommended Practice for Drill through Equipment Recommended Practice for Wellhead Equipment Recommended Practice for Drill pipe Recommended Practice for Bolting Preventers Recommended Practice for Inspection and Classification of Used Drill Stem Elements Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells Drilling fluid materials e Specifications and tests Recommendations for suitable steel structures for drilling and well servicing operations in the petroleum Recommendations for the design, rating, manufacturing and testing of marine drilling riser couplings Drilling and production equipment e Drill-through equipment Drilling and production equipment e Inspection, maintenance, repair and remanufacture of hoisting equipment Drilling and production equipment e Drill stem design and operating limits Drilling and production equipment e Hoisting equipment Steel drill pipe Drilling and production equipment e Part 2: Flow-control devices for side-pocket mandrels Drilling and production downhole equipment Critical Sour Drilling Completing and Servicing Critical Sour Wells Critical Sour Underbalanced Drilling Standards for Wellsite Supervision of Drilling, Completion, and Workovers Non-Water-Based Drilling and Completions/Well Servicing Fluids Underbalanced and Managed Pressure Drilling Operations Using Jointed Pipe

) An IRP is a set of best practices and guidelines prepared by knowledgeable and experienced industry and government personnel. IRPs are intended to provide management and operators in the Canadian oil and gas industry2,3

The casing must withstand tension loads resulting from being suspended. The top portion of the casing should support its whole length. For this reason, high yield strength material with large wall thickness is used. High strength casing materials are, however, susceptible to SSC in the presence of H2S. In addition, producing heavy-walled casing materials with uniform microstructure is difficult.

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Table 2.3 Typical Mechanical Property Requirements of Casings4,5 Casing Grade e Common (API) Identification H-40 H-55 K-55 C-75 L-80 N-80 C-90 C-95 HC-95 P-110 Q-125 V-150

Yield Strength (psi) Minimum

Maximum

Minimum Tensile Strength (psi)

40,000 55,000 55,000 75,000 80,000 80,000 90,000 95,000 95,000 110,000 125,000 150,000

80,000 80,000 80,000 90,000 95,000 110,000 105,000 110,000 e 140,000 150,000 180,000

60,000 75,000 95,000 95,000 95,000 100,000 100,000 105,000 110,000 125,000 135,000 160,000

Strength and thickness are optimized when producing the casings. The selection of casing materials for a specific environment depends on many other factors including gas composition, water chemistry, pressure, temperature, flow rates, risk, and economics. Carbon steel is used to the greatest extent possible. When this is not effective, casings are manufactured from stainless steel. At higher chloride concentrations, when 13 Cr steels suffer from pitting corrosion, Super-13 stainless steel is used. The casings constructed from duplex stainless steels are resistant to chloride SCC (see section 5.17) and have lower corrosion rates than other stainless steels in environments containing high CO2 levels. They are resistant to SSC when the partial pressure of H2S is less than 1.0 psia. Corrosion resistant alloy (CRA) casing is not economical; but CRA-clad carbon steel may be used. Table 2.3 presents typical materials used for producing casings, together with their physical properties. Standards providing guidelines to select casing materials include: • • •

API 5CT, ‘Specifications for Casing and Tubing’ API 5D, ‘Specification for Drill Pipe’ NACE MRO175/ISO 15156: Petroleum and Natural Gas Industries – Materials for Use in H2S-containing Environments in Oil and Gas Productions (Parts 1, 2, and 3)

Cement is used to protect the external surface of the casing from well fluids, and to isolate the producing zone. The effectiveness of the cement depends on many factors, including the cement setting time, pressure, temperature, borehole size, cement characteristics, casing surface, and squeezing operations. Table 2.4 presents standards providing specifications for cement used in downhole applications. In some instances the drill fluids injected between the annulus of casing and cement have caused severe SSC on the external surface of the casing. The primary cause of this SSC is H2S produced by degrading drill fluids. Gravel pack screens may fail if erosion creates holes large enough for sand to enter the production tubular, defeating the purpose of using the screen. Gravel pack screens may also suffer SCC. Calcium

2.4 Downhole tubular

47

Table 2.4 Standards Specifying Cements for Downhole Applications ISO Standard )

10409 10426e1)) 10426e2))) 10426e3 10426e4 10426e5 10426e6 10427e1)))) 10427e2)))) 18165)))))

Title Application of cement lining to steel tubular goods, handling, installation, and joining Cements and Materials for Well Cementing e Part 1: Specification Cements and Materials for Well Cementing e Part 2: Testing of Well Cements Cements and Materials for Well Cementing e Part 3: Testing of Deepwater Well Cement Formulations Cements and Materials for Well Cementing e Part 4: Preparation and Testing of foamed cement slurries at atmospheric pressure Cements and Materials for Well Cementing e Part 5: Determination of shrinkage and expansion of well cement formulations at atmospheric pressure Cements and Materials for Well Cementing e Part 6: Methods for determining the static gel strength of cement formulations Bow-spring casing centralizers e Part 1: specification Bow-spring casing centralizers e Part 2: Recommended Practice Recommended Performance Testing of Cementing Float Equipment

) Equivalent API Standard is RP 10E, ‘Recommended Practice for Application of Cement Lining to Steel Tubular Goods, Handling, Installation, and Joining’ )) Equivalent API Specification is RP 10A, ‘Specification for Cements and Materials for Well Cementing’ ))) Equivalent API Specification is RP 10B,‘Recommended Practice for Testing Well Cements’ )))) Equivalent API Specification is RP 10D, Recommended Practice for Centralizer Placement and Stop Collar Testing’ ))))) Equivalent API Specification is RP 10F, ‘Recommended Practice for Performance Testing of Cementing Float Equipment’

bromide (CaBr2), calcium chloride (CaCl2), and zine bromide (ZnBr2), present in the formation water may initiate SCC at temperatures greater than 200 F (93 C).

2.4 Downhole tubular A smaller pipe (known as downhole tubular) is inserted into the casing through which the hydrocarbons flow from the well to the surface. Figure 2.4 presents typical components of a downhole tubular.6 The tubular may be attached to the packer permanently (tubular is latched or fixed on the packer) or semi-permanently (tubular is attached to the packer using a seal assembly) or freely placed (with a long seal assembly that does not limit the movement of tubing). The packer (Figure 2.5)7 is used to isolate well fluids, isolate well pressure, keep gas mixed with liquids, create the annular volume (casing/tubing/packer) for gas lift or subsurface hydraulic pumping systems, control the tubing from the surface, and hold well service fluids (e.g., packer fluids) in the casing annulus. Additional equipment such as a hydraulic pump, electric submersible pump (ESP), sucker rod pump, valves, monitoring devices, and logging tools are housed inside the downhole tubular. To place and retrieve such tools, wirelines of diameter between 66 and 92 mil (1.68 and 2.34 mm) are used. Hydraulic pumps, ESP, and sucker rod pumps are used to pump crude oil from the well. Figure 2.6 presents a typical hydraulic pumping system.8 To operate the hydraulic pump, power fluid is pumped

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Tubing Casing

Seal Element Slips

Perforation

FIGURE 2.4 Components of Downhole Tubular.6 Reproduced with permission from Society of Petroleum Engineers.

through the tubular by an engine placed at the surface. Table 2.5 presents typical constituents of power fluids.9 The power fluids are separated from the produced fluids at the surface. They are analyzed for impurities (solids, gas, and other chemical constituents) and these are removed before the fluids are reused. The ESPs comprise a pump, electric power cable, and surface controls (Figure 2.7).10 The pump is suspended inside the tubing using string hanging on the wellhead. The pump is powered through a power cable from the surface. The use of sucker rod pumps (Figure 2.8)11 is the simplest method to produce oil from a well. Table 2.6 presents typical components of subsurface sucker rod pumps. A pumping unit imparts reciprocating motion to a rod and thereby to the sucker rod string. Though several types of pumping units are available, most of them basically are the same but arranged in different ways. Pumping units may also have counterbalance, e.g., adjustable weights on the rotating cranks or air pressure which move the walking beam. The counterbalance system balances out the weight of the sucker rod string. Standards providing guidelines on the design and operation of pumps include: • •

API 11AX, ‘Specifications for subsurface pumps and fittings’ API RP 11AR, ‘Recommended practice for care and use of subsurface pumps’

2.4 Downhole tubular

49

FIGURE 2.5 Components of Packers.7 Reproduced with permission from Society of Petroleum Engineers.

• • • • • • •

API RP 11L, ‘Recommended practice for design calculations for sucker rod pumping systems (conventional units)’ API specification 11E, ‘Specifications for Pumping Units’ API RP 11G, ‘Recommended practice for installation and lubrication of pumping units’ API specification RP 11ER, ‘Recommended practice for guarding of pumping units’ API specification 7B-11C, ‘Internal combustion reciprocating engines for oil field service’ API RP 7C-11F, ‘Recommended practice for installation, maintenance, and operating of internal combustion engines’ API RP 500B, ‘Recommended practice for classification of areas for electrical installations at drilling rigs and production facilities on land and on marine fixed and mobile platforms’

Materials for packer construction are selected on the basis of their resistance to sweet (in the presence of CO2 – see section 4.5) or sour (in the presence of H2S – see section 4.6) corrosion, SSC, and chloride SCC. Most materials are constructed from carbon steel, but some critical parts are constructed from CRA. The packer is designed to avoid galvanic corrosion (see section 5.4). When dissimilar metals are connected, a larger anode (normally carbon steel) to smaller cathode (normally CRA) ratio is established for better corrosion control. In addition, non-metallic seals are used in the joints. Seal materials used include nitrileÔ up to 325 F (121 C), vitonÔ up to 300 F (149 C); and TeflonÔ up to 450 F (232 C). A Teflon seal is ideal due to its resistance to H2S and other chemicals, but extrusion of Teflon seals can be a problem. To prevent this, a suitable metallic backup is used. Most of the materials requirements discussed in the casing section also apply to the downhole tubular. The typical construction material is carbon steel, and as the severity of the environment

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FIGURE 2.6 Typical Hydraulic Pumping System.8 Reproduced with permission from Society of Petroleum Engineers.

Table 2.5 Properties of Power Fluid Used to Operate Hydraulic Pumps9 Properties

Unit

Value

API gravity Total solid (maximum) Salt content (maximum) Particle size (maximum)



30 to 40 20 12 15

ppm lb/1,000 barrel of oil mm

increases CRAs are used. Figure 2.9 qualitatively presents regions in which various materials may be used.12 Standards providing guidelines for materials selection for downhole tubular include: • • •

API 5CT, ‘Specifications for Casing and Tubing’ API 5D, ‘Specification for Drill Pipe’ NACE MRO175/ISO 15156: Petroleum and Natural Gas Industries – Materials for Use in H2S-containing Environments in Oil and Gas Productions (Parts 1, 2, and 3)

2.4 Downhole tubular

51

Transformers

Switchboard Junction Box Wellhead

Power Cable

Motor Flat Cable

Pump

Standard Intake

Protector

Motor

FIGURE 2.7 Submersible Pumps.10 Reproduced with permission from Society of Petroleum Engineers.

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CHAPTER 2 Oil and Gas Industry Network

BEAM PUMPING UNIT

CARRIER BAR AND POLISHED ROD CLAMP

WELLHEAD

POLISHED ROD STUFFING BOX FLOW LINE CASING VENT CASING

TUBING SUCKER ROD

PLUNGER TRAVELING VALVE STANDING VALVE

PUMP BARREL GAS ANCHOR

FIGURE 2.8 Sucker Rod Pumps.11 Reproduced with permission from PennWell Corporation.

Table 2.6 Components of Subsurface Sucker Rod Pumps Component

Function

Barrel Plunger Standing valve Traveling valve Standing valve puller Valve rod Pull tube Seating assembly

A cylinder into which the well fluid is collected A tubular piston to displace well fluid from the pump barrel Intake valve of the pump The discharge valve that moves with the plunger Attached to the standing valve To connect the lower end of the sucker rod string to the pump plunger To connect the plunger with the setting assembly An anchoring device for retaining the rod pump in its working position

In general, temperature increases with the depth of the well. At the bottom of the well, the temperature is too high for water to condense to cause corrosion, but tubing at the bottom is susceptible to chloride SCC. As the strength of the material increases, the temperature at which it becomes susceptible to SSC increases. Therefore higher strength materials can be used in deeper wells where temperatures are higher.

2.4 Downhole tubular

53

FIGURE 2.9 Selection of Materials for Downhole Tubulars.12

The downhole tubulars are susceptible to corrosion in regions closer to the surface where both temperature and pressure decrease and consequently the water phase condenses. The water phase in downhole tubing can consist of produced water, injected water, and condensed water (see section 4.4 for the effect of composition on corrosivity of water). The corrosivity of water also depends on concentrations of CO2 (see section 4.5), H2S (see section 4.6), and O2 (see section 4.7). Produced water as such does not contain oxygen, but may be contaminated with oxygen if proper precautions are not taken to avoid leakage of air. A wide variety of materials are used to manufacture various parts of subsurface pumps. The type of materials depends on the corrosive environment. Table 2.7 presents typical materials used for the construction of the ESP. Standards providing guidelines to select materials for ESP include: • •

API RP 1R, ‘Recommended Practice for electric submersible pump installation’ API RP 11S, ‘Recommended Practice for the operation, maintenance and trouble shooting of electric submersible pump installation’

Because the components of pumps are constructed from several materials, galvanic corrosion (see section 5.4) may take place. The pump components may also suffer from SSC in sour environments. Some of the constituents of the fluid may be above or near their boiling points at the pressure and temperature of the pump. When the pressure of the well drops slightly, large volume of gases may be released resulting in cavitation corrosion (see section 5.10). Sucker rods were originally constructed from wooden poles with steel ends. Currently approximately 90% of the rods are constructed from carbon steel and 10% are constructed from fiberglass.

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Table 2.7 Components of Electric Submersible Pumps Component

Part

Materials

Motor

Housing Heads and bases Impellers Motor-shaft Sleeve bearings Diffusers Shaft High-strength shaft material Conductors Mechanical protection

Heavy-wall, seamless, low-carbon steel tubing 416 or 400 stainless steel or duplex stainless steel Cast iron or duplex stainless steel Carbon steel NitralloyÔ) and bronze Ni-ResistÔ)) MonelÔ InconelÔ and HastelloyÔ Copper Armor made from galvanized steel or MonelÔ

Pump

Power cable

)

Steels consist of carbon, manganese, silicon, chromium, molybdenum, and aluminum Alloys consist of nickel, chromium, silicon, copper, manganese, carbon, molybdenum, and other trace elements

))

Carbon steel components of sucker rods are chrome-plated or nickel-plated to protect them from corrosion. Steel rods are 25 to 30 ft in length where as fiberglass rods are typically 37.5 or 30 ft in length. Both steel and fiberglass rods are connected by 4 in. long coupling to form rod strings. The ends of the sucker rods are threaded into couplings. The length of the rod stringers can vary from a few hundred feet to a few thousand feet depending on the depth of the well. Table 2.8 shows typical materials used for manufacturing sucker rods.13 Standards providing guidelines to select materials for suck rods include: • •

API Specification 11B, ‘Specification for Sucker Rods’ API Specification 11D, ‘Specification for Miscellaneous Production Equipment’

Most of the failures (60–80%) of the sucker rod occur in the body. Rubbing on the rods on the tubing leads to wear (see section 5.11) and corrosion fatigue (see section 5.16) failures. Some high strength steels may also suffer from SSC. The first fiberglass rod was installed in 1970s. A typical fiberglass rod consists of parallel strands of fiberglass embedded in a plastic matrix. The ends of the rods are fitted with steel. The fiberglass rods with steel end-fittings are joined together with standard couplings to form rod strings similar to steel

Table 2.8 Typical Properties of Materials Used to Manufacture Sucker Rods13 Tensile Strength, psi API Grade

Material

K C D

AISI 46XX AISI 1536 Carbon steel

Minimum 85,000 90,000 115,000

Maximum 115,000 115,000 140,000

2.5 Acidizing pipe

55

Table 2.9 Properties of Steel and Fiberglass Sucker Rods14 Sucker Rod Properties

Steel

Fiberglass

Weight of 1-inch rod, lbm/ft Modulus of Elasticity, psi

2.9 29.5 x 106

0.84 7.0 x 106

rods. Table 2.9 compares the properties of fiberglass and steel sucker rods.14 Standards providing guidelines to select materials for fiberglass sucker rods include: • • •

API RP 11L, ‘Design calculations for sucker rod pumping systems’ API bulletin 11 1.3, ‘Sucker rod pumping system design book’ API Specification 11C, ‘Specification for reinforced plastic sucker rods’

The fiberglass rods are more easily damaged during installation than steel rods. Therefore extensive precautions are taken to protect the fiberglass rods from mechanical damage and from ultraviolet (UV) light. During operation, the fiberglass sucker rod may fail due to breakdown of the end connector joint (due to stress) and breakdown of the body due to the mishandling or misalignment. Standards which provide guidelines for selecting materials for sucker rod couplings and wirelines include: • •

API Specification 11B, ‘Specification for Sucker Rods’ API Specification 9A, ‘Specification for Wire Rope’

2.5 Acidizing pipe15,16 Depending on the reservoir it may be necessary to create channels for the oil to flow. Acids, sand, or crushed walnut shells are used to create channels and to hold them open. Acidizing the well to stimulate and improve oil production from carbonate reservoirs was first attempted in 1895, but severe corrosion of well casing and other metal equipment prevented successful implementation of the practice. Discovery of arsenic inhibitors enabled the acid to react with the formation rock without corroding the metal well equipment. Since then acidizing has been successfully used to stimulate several wells. The most commonly used acids include hydrochloric (HCl), hydrofluoric (HF), acetic (CH3COOH), and formic (HCOOH). In limestone reservoirs, 15 and 28% HCl is used; in sandstone reservoirs, 3% HF is used; and in sour reservoirs 12% HCOOH is used. The acids are pumped through the acidizing pipes into the well. All these acids are corrosive and the corrosion is controlled by the addition of corrosion inhibitors (see section 7.4). In addition to corrosion inhibitors, the acids contain surfactants silicate control agents, iron control agents, alcohols, gelling and fluid loss agents, liquefied gases and retarded acids. Table 2.10 presents the roles of each of the additives.17 Acidizing pipes are normally constructed from carbon steel. When carbon steel corrosion cannot be controlled by the addition of corrosion inhibitors, CRAs (including stainless steel and materials high nickel alloys) are used. Fluid returning after acidizing process is called spent acid. The spent acids (pH typically 2 to 3) are also corrosive. Failures of CRAs and steel equipment have occurred in spent acids, rather than during acid treatment. Studies have indicated that spent acids are more corrosive than fresh acids.18

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Table 2.10 Additives to Acids for Well Stimulation17 Additives

Function and Characteristics

Examples

Corrosion inhibitors

• To control corrosion of casing, tubing, pumps, valves and other well equipment

Amides and imidazolines; carboxylic acids containing nitrogenous salts; quaternaries; and heterocyclic compounds containing nitrogen.

Surfactants

Silicate control agents Iron control agents

Alcohol Gelling and fluid loss agents

Liquefied gases Retarded acid

Note: The inhibitors should have no effect on the reaction between acid and limestone and dolomite. Relatively large concentrations of organic inhibitors are required above 200 F and organic inhibitors become ineffective above 400 F • To decrease the surface tension or interfacial tension of fresh acid or spend acid • To improve the permeation of acid solution into formation • To facilitate the return of spent acid following the treatment • To inhibit formation of emulsions • To disperse and suspend solids • To prevent formation of crude sludge containing asphaltenes, resin, paraffin and other complex hydrocarbons • To prevent swelling of silicates in clays and silts • To prevent precipitation of iron

• To reduce surface tension • To increase the viscosity of the acid solution thereby preventing loss of acids due to leakage through rock pores • To facilitate well cleanup • To retard the reaction rate of the acid with formation

Methyl-diethy-alkoxymethyl ammonium methyl sulpates, alkylpolyglucosides, and alkylphenol ethoxylates

Acrylamides and acrylonitrile Erythoboric acid, citric acid, lactic acid, acetic acid, and ethylenediaminetetraacetic acid (EDTA) Methyl alcohol and isopropyl alcohol Oil-soluble resins

Liquid nitrogen and liquid CO2 Acetic acid and formic acid

2.6 Water generators and injectors Sometimes water may be pumped into a well to increase its pressure. This process is called water flooding or secondary recovery. Water from various sources, including lakes, ocean, industrial waste, or recycled, is used for this purpose. The water generator and injection system includes the pipes that collect water from the sources, the units that treat the water before it is injected underground, and the injection pipelines.

2.6 Water generators and injectors

57

Gas outlet Mist eliminator Raw water inlet

Gas inlet Water outlet

FIGURE 2.10 Schematic Diagram of Gas Stripping.19 Reproduced with permission from ASM International.

Before water is pumped into the well, the oxygen and dissolved solids are removed to control corrosion. Oxygen or air is removed from water by mechanical (gas stripping or vacuum de-aeration) stripping or addition of chemicals. Gas stripping is performed in either a packed column or a perforated tray column. Figure 2.10 illustrates a typical tray-type gas stripping column.19 Oxygenated water is charged from the top of the column, while the stripping gas (typically a natural gas) is injected from the bottom of the column. As the gas bubbles up through the water, oxygen is released. The trays or packing in the column increases the contact area and time between water and the stripping gas; thereby increasing the efficiency of deoxygenation. Natural gas or scrubbed exhaust gas from engines is commonly used as stripping gas. It is important that they be free of both oxygen and H2S. In the vacuum de-aeration process, vacuum is created in a packed tower and the oxygenated water is passed through the tower. The low pressure releases oxygen from water. The vacuum pump sucks oxygen, water vapor, and other gases from the top of the tower. Figure 2.11 presents a typical vacuum tower.20 A single-stage tower reduces the oxygen concentration to 0.1 ppm (100 ppb). Multiple columns are used to reduce oxygen concentration further. Dissolved oxygen concentrations below 0.01 ppm (10 ppb) can be achieved in three-stage towers. Oxygen can also be removed (scavenged) from the water by using chemicals. Three commonly used scavengers are sodium sulfite (Na2SO3), ammonium bisulfite (NH4HSO3), and sulfur dioxide

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CHAPTER 2 Oil and Gas Industry Network

Liquid inlet

V1 Vacuum takeoffs 2.4 m

Stage 1

L1

V2 Stage 2

L2

2.4 m

V2 2.4 m

Stage 3

3m

Storage section 2.1 m

L3

12.2 m

Transfer pump

FIGURE 2.11 Schematic Diagram of Vacuum De-aeration Tower.20 Reproduced with permission from ASM International.

(SO2). Sulfites are the most effective oxygen scavengers. Sometimes catalysts such as cobalt may be used to increase the rate of reaction. It is not only important to remove oxygen content from water, but also equally important to ensure that oxygen does not re-enter into the system. The most common means of excluding oxygen is by the use of gas blankets on water supply wells and water storage tanks. Maintenance of valve stems and pump packing is also important. In water handling systems, a leaking valve is the main source of oxygen contamination. Dissolved solids (especially those of Mg and Ca compounds) should be removed from water.21 If they are not, they form scale in the boiler and react with chemicals added in the water flooding process and precipitate in the well. The former effect results in heat exchange inefficiency in the boiler, and the latter effect may plug the well. Dissolved solids are normally removed by chemical treatment. Commonly used chemicals include lime, soda ash, alum, and coagulants. If the dissolved solids are low in concentration, an ion-exchange process may be used to remove them. In such a process, ions are

2.7 Gas generators (Teritiary recovery)

59

exchanged between the solid and water. Granules or beads (approximately 11 to 39 mil (0.3 to 1.0 mm) in diameter) are used in ion-exchange processes. Most water generation units are constructed from carbon steel. Water injection pipes may be constructed from carbon steel, fiberglass, or stainless steel. Carbon steel pipes may be internally protected with plastic liners, e.g., polyethylene. Table 2.11 presents general material requirements for water handling systems.22 Standards providing guidelines for material selection for water injection systems include: •

ISO 21457, ‘Material Selection and Corrosion Control for Oil and Gas Production Systems’

Corrosion generally increases with water injection rate, because larger surface areas of the metal are in contact with water. In addition, if oxygen is not properly eliminated, it greatly accelerates the corrosion. If proper precautions are not taken, the corrosion mechanism may even change during water injection. For example, a normally sweet field (i.e., fluids containing no H2S) will become a sour field (i.e., fluids containing H2S due to the growth of sulfate-reducing bacteria [SRB]). Deposition of inorganic scale may increase during water injection. This usually happens when the composition of the formation water is changed by the injected water. Scale formation may lead to underdeposit corrosion (see section 5.13). Plugging of the injection wells may occur due to lubricant oil from the compressors or due to corrosion products from downhole tubular. To avoid lubricating oil entering the injection wells, coolers, scrubbers, drips, collectors, mist extractors or wire mesh filters are installed on the discharge side of the compressors. The plugging caused by corrosion products may sometimes be removed by reversing the flow, i.e., using the injection well as production well. Water injection lines may be periodically acidized to remove the corrosion products and mineral scale (see section 2.5). Design of the injection pump must take into account the presence of dissolved acid gases (H2S and CO2) and solids in the water. Injection pumps may undergo cavitation corrosion if the water contains dissolved gases; erosion and erosion-corrosion if the water contains solids (corrosion products, formation fines, and mineral-scale particulates); chloride SCC if the water contains chloride ions; and corrosion fatigue if there are sharp changes in cross section, or if there are grooves or pits in the material.

2.7 Gas generators (Teritiary recovery) Secondary recovery by water injection increases the amount of oil recovered over primary production, but may still leave more than 80% of oil in the reservoir. To recover more oil, gas (CO2, nitrogen [N2] and methane) may be injected. The process of recovering oil by injecting gas is known as tertiary recovery or enhanced oil recovery (EOR). In some wells water and CO2 are injected alternatively. This process is known as the water and gas (WAG) process. Typically, primary production is followed by water flooding (secondary recovery), which is followed by gas injection (tertiary recovery). The sequence of processes may recover up to 60% of the oil from the reservoir. Normally, crude oils with an API gravity of 25 or lower are recovered by tertiary processes from low-permeability reservoirs. CO2 readily dissolves in crude oils and drastically reduces oil viscosity. For this reason CO2 gas is preferred over N2 and methane. An oil field is an ideal candidate for CO2 flooding if the water flooding process has previously been successful; if the addition of CO2 swells the

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Table 2.11 Typical Materials for Handling Water22 Equipment

Type of Water (System)

Materials

Wellhead equipment/ Christmas Trees

De-aerated seawater (Injection) Untreated seawater (Injection) De-aerated seawater (Injection) Untreated seawater (Injection)

Carbon steel; low alloy steel; and CRAs

Piping

Untreated seawater

Fresh water

Vessels

Untreated seawater (Injection)

Untreated seawater

Fresh water

De-aeration tower Pumps and valve body/bonnets

De-aerated seawater (Injection) De-aerated seawater (Injection) Untreated seawater (Injection) Untreated seawater

Fresh water

Carbon steel; glass fiber reinforced plastic; and stainless steel CRAs (including stainless steel; 90Cu10Ni; and titanium) Carbon steel with internal polymeric coating with cathodic protection; CRAs (including stainless steel, titanium; and 90% Cu e 10%Ni); reinforced elastomer pipe; and glass fiber reinforced plastic (epoxy resin) Glass fiber reinforced plastic; galvanized carbon steel; polyethylene (PE); polypropylene; PVC; glass fiber reinforced plastic (Vinyl ester resin); glass fiber reinforced plastic (epoxy resin); epoxy coated carbon steel; and CRAs (including copper, stainless steel, and 90% Cu e 10% Ni) Carbon steel with internal polymeric coating with cathodic protection exposed surface or with CRA cladding and CRAs (including stainless steel) Carbon steel with internal polymeric coating with cathodic protection; CRAs (including stainless steel); and glass fiber reinforced plastic (epoxy resin) Glass fiber reinforced plastic (polyester resin); poly vinyl chloride; glass fiber reinforced plastic (Vinyl ester resin); glass fiber reinforced plastic (epoxy resin); epoxy coated carbon steel; and CRAs (including 90% Cu e 10% Ni and stainless steel) Carbon steel with internal polymeric coating with cathodic protection CRAs (including stainless steel) Carbon steel clad with CRAs; low alloyed steel clad with CRAs; and stainless steel Carbon steel with internal polymeric coating with cathodic protection; CRAs (including stainless steel and titanium); and reinforced elastomers Al-Bronze

2.8 Open mining

61

Table 2.11 Typical Materials for Handling Water22 Continued Equipment

Type of Water (System)

Materials

Tanks

Fresh water

Glass fiber reinforced plastic (polyester resin); glass fiber reinforced plastic (vinyl ester resin); glass fiber reinforced plastic (epoxy resin); PVC; PE; Polypropylene; Epoxy coated carbon steel; and CRAs (including 90% Cu e 10% Ni and stainless steel)

oil and reduces its viscosity; and if the reservoir pressure required for the oil to be miscible in CO2 can be readily achieved at the reservoir temperature. CO2 for the EOR process is transported in pipelines (see section 2.38) from various sources including fields that produce CO2, power generation units, and industrial emissions. The gases from various sources are first collected in compressor stations, where they are pressurized and transferred into pipelines. The compressors are normally constructed in series. The gas arriving at the first compressor is typically saturated with water. The temperature in the first compressor is normally at the water dew point. The temperatures of operation of subsequent compressors progressively increases, and, consequently, the gas loses water. The first compressor is normally constructed using carbon steel which meets the requirements of NACE MR 0175. The remaining compressors and piping are either stainless steel alone or a combination of stainless steel and carbon steel. How much stainless steel is used depends on the chloride content – as the chloride content increases, less stainless steel is used, due to its susceptibility to chloride SCC. Corrosion inhibitors may be added to control corrosion of carbon steel. The pressurized gas is injected into the annulus between the downhole tubular and the casing pipe through gas lift valve. The gas injection may be performed in batches or continuously. The gas entering into the injection systems is typically completely dehydrated (dry gas) and is free from chlorides; hence corrosion is not a major concern in gas injection systems. The injection systems are typically constructed from carbon steel, and to a smaller extent stainless steel. Injection systems for WAG processes are normally constructed from stainless steel. Carbon or lowalloy steels are not adequate to withstand the corrosive environment created by these processes, and the use of internal polymeric liners or nickel plating is not sufficient to control corrosion under WAG conditions. When the coating or plating fails, locally accelerate localized pitting or galvanic corrosion occurs. Christmas trees and valves constructed using stainless steel may also suffer from pitting corrosion.

2.8 Open mining23–25 Oilsands are naturally occurring mixtures that typically contain 10–12% bitumen, 80–85% minerals (clays and sands) and 4–6% water. Bitumen is a mixture of large hydrocarbon molecules containing up to 5% sulfur compounds by weight, small amounts of oxygen, heavy metals, and other materials.

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Table 2.12 Characteristics of Normal Crude and Bitumen Derived Crudes Bitumen

Characteristics

Athabasca Bitumen

Cold Lake Bitumen

Gravity, API Specific gravity Sulfur, Wt% Nitrogen, ppm Vanadium, ppm Nickel, ppm Asphaltene, wt% TAN Number Salt, lb/1000 bbl

7.9 1.0151 4.9 4,000 222 87 17.5 3 40

11.0 0.9928 4.6 3,740 182 65 16.0 1 20

Bitumen Derived Cold Lake Blend 23.1 0.915 3.5 3,230 152 57 13.4 0.8 15e20

Sweet Blend 31.8 0.8663 0.1 630 < 0.4 < 0.4

Reference Crude (West Texas Intermediate) 40.8 0.8212 0.3 800 1.6 1.6 0.1

Physically, bitumen is denser than water and more viscous than molasses (sometimes existing as a solid or semi-solid). Table 2.12 compares the characteristics of bitumen to conventional crude oil. Surface mining is an efficient extraction method when the oil-bearing formation occurs within 262 feet (80 meters) from the surface. The oilsands used to be mined with draglines and bucket-wheel excavators; Truck-and-shovel operation, using large power shovels (100 or more tons) and trucks (400 tons) is the main method currently used in the Athabasca oilsands area. The materials used in the oilsands industry may suffer corrosion, erosion, abrasion, and wear (see section 5.11). The most common failure mechanism for materials used in open mining operation is wear. Materials are selected to withstand the impact when the mining equipment hits rocks and boulders. The degree of impact damage depends on the season; for example, the effect of impact is higher during winter months when the sand and bitumen consolidate into larger lumps. White irons are used to fabricate machinery parts for crushing, grinding, and handling abrasive materials. These irons are adjusted by alloy content and heat treatment to develop the proper balance between resistance to abrasion and the toughness needed to withstand repeated impact. The mining equipment is further protected with composite materials such as chromium carbide alloys and tungsten carbide.26

2.9 In situ production It is estimated that around 80% of Canadian oilsands and nearly all of Venezuelan oilsands are too far below the surface (i.e., further than 262 feet (80 meters) from the surface) to be accessed with open mining techniques. These oilsands are therefore extracted by in situ methods, some of which are discussed in this section.

2.9.1 Cyclic steam stimulation (CSS) Cyclic Steam Stimulation (CSS) to recover heavy oil has been used in California since the 1950s. CSS is often colloquially termed as a ‘huff-and-puff’ operation. In this method, steam is injected into a well

2.9 In situ production

63

at a high temperature (572 to 644  F (300 to 340 C)) for an extended period of time (typically weeks or months). The well is soaked with steam for some period (days to weeks) in order to liquefy the bitumen, and finally the heated bitumen (or extra heavy oil) is pumped out of the well. When the production of oil decreases, the cycle is repeated. The CSS method may recover 20 to 25% of oil in the formation, but the cost of injecting steam is high. During the operation, the temperature of the reservoir ranges between the steam temperature (at the injection point) and reservoir temperature (at the production point). The thermal expansion of equipment, which occurs when steam is injected, is a major problem, so materials with suitable thermal expansion properties are selected for steam injection operations. The temperature in the producing wells is lower than that in the injection wells, hence thermal expansion is not an issue. Production wells are susceptible to abrasion because steam flooding produces excess sand. Critical areas of the equipment are frequently hard-faced to control abrasion.

2.9.2 Steam assisted gravity drainage (SAGD) The steam assisted gravity drainage (SAGD) process was developed in Canada in the 1990s. SAGD can recover up to 60% of the oil in the formation. In this process, two horizontal wells are drilled into the oilsand formation – one near the bottom of the formation, and another about 13 to 20 feet (4 to 6 meter) higher up. The steam is injected into the formation via the upper well forming a steam chamber. Heat from the steam reduces the viscosity of the bitumen, allowing it to drain to the lower well where it is flowed (under formation pressure) or pumped to surface. Progressive cavity pumps are commonly used to pump bitumen because of their compatibility with high-viscosity fluids containing suspended solids. Some small amounts of steam may be produced with the bitumen. The gases released (methane, CO2, and H2S) from the formation rise, filling the void space left by the oil and forming a thermal blanket. Table 2.13 presents typical operating conditions of a SAGD process.27 The SAGD infrastructure is predominantly constructed using carbon steel. Some equipment at the bottom of the underground tubing is constructed from stainless steel. The SAGD infrastructure may suffer erosion and erosioncorrosion (due to the presence of solids), flow-accelerated corrosion (if the fluid velocity exceeds 16 to 20 feet/sec (5 to 6 m/sec) localized corrosion (due to condensing water containing acid gases on the inside surface of the casing and external surface of the production tubing), caustic embrittlement (threads of tubular connection if steam condensate containing caustic [sodium hydroxide] leaks through a connection), chloride SCC (of 316 stainless steel components at the bottom of the production well), and crevice corrosion (if the connections are not properly threaded between tubular and injection wellhead).

2.9.3 Toe to heel air injection (THAI) or fireflooding (In situ combustion) This method combines a horizontal production well and a vertical air injection well located near the most distal end of the horizontal well (the ‘toe’). This process works by igniting some of the hydrocarbons in the reservoir. The heat produced by combustion and the pressure partially upgrade the bitumen by in situ thermal cracking (see section 2.9.1) and forces the bitumen towards the production well where it is pumped to surface. Over time, the active combustion zone progresses from the ‘toe’ towards the ‘heel’ of the horizontal portion of the production well. This process uses less water and produces less greenhouse gases than SAGD or CSS, but presents a considerable challenge in

64

Percentage Water

Percentage CO2, ppm

Percentage, H2S, ppm

5,000

w95 as steam

4,000

w95 as steam

235

2,750

235

2,750

8 to 235

2,750

90e92 as steam 90e92 as steam 90e92

230

2,700

Trace during circulation phase Trace during circulation phase Trace during circulation phase Some generated from reservoir Pipeline quality gas e

None

235

Carryover from steam generator Carryover from steam generator Carryover from steam generator Some generated from reservoir Pipeline quality gas w7

230

2,700

w7

w4

w1,000

230

2,100

w2

w1

w1,000

6 to 230

2,100

w2

w1

None

w2

w1

w1,000

Section), #

Temperature,  C

Injection tubing e top

235

Injection tubing/casing annulus-top Injection heel to toeinside injection string Injection heel to toeoutside injection string Injection e intermediate casing annulus Production toe to heel outside production string Production toe to heel inside production string Production e gas lift string terminus Production intermediate e casing annulus Production tubing e top )

Pressure, kPa

230

Relative flow: SAGD solution gas: 1 and SAGD lift gas: 8 Most construction materials are carbon steel

#

800

Steam condensate Steam condensate Steam condensate Steam condensate Steam condensate

Chloride, ppm

None None Some from formation water None w1,000

CHAPTER 2 Oil and Gas Industry Network

Table 2.13 Operating Conditions of Typical SAGD27

2.10 Wellhead

65

controlling the underground combustion process. A related production process known as combustion overhead gravity drainage (COGD) uses the fire-flood concept but uses a horizontal air injector to create a combustion zone above the horizontal producing well in a SAGD configuration. The temperatures in the injection wells may be in the range 600–1200 F (315 to 649 C) and the temperature in the adjacent production wells may reach 200–350 F (93-177 C). The combustion gases (oxygen, organic acids, carbon dioxide, sulfides, and chlorides), steam, and temperature together create a severely corrosive environment. Failures due to corrosion and erosion have been experienced in the casing, tubing, chokes, valves, and fittings of the producing wells.

2.9.4 Cold heavy oil production with sand (CHOPS) Oil can be simply pumped out of the sands using subsurface progressive cavity pumps equipped with sand filters. The technique works only when the oil is fluid enough to flow at the reservoir temperature. This technique is commonly used in Venezuela and in some oilfields in Canada. Although cost effective, this technique produces only 5–6% of oil in the formation due to plugging of the formation near the sand filters and poor heavy oil mobility through the producing formation. Canadian companies have recently discovered that removing the sand filters from the wells and producing sand along with the oil can increase recovery rates to approximately 10% of in situ reserves. This technique has become known as Cold Heavy Oil Production with Sand (CHOPS). Pumping sand oil out of the well creates additional fragmentation of the reservoir, which allows more oil to reach the production well. CHOPS produces large volumes of oil-soaked sand that can be used for laying roads and to reduce the dust during construction. Some amounts of produced sand are also disposed in underground salt caverns. Because of the volume of sand produced, erosion-corrosion is a major problem in the producing wells.

2.9.5 Vapor extraction process (VAPEX) VAPEX is similar to SAGD, but a hydrocarbon solvent instead of steam, is injected into an upper horizontal well to dilute the bitumen and allow it to flow into a lower horizontal well. VAPEX has higher energy efficiency than SAGD. This process is relatively new and corrosion mechanisms have not been established.

2.10 Wellhead Drill pipe (see section 2.2), casing (see section 2.3), and downhole tubular (see section 2.4) are collectively known as Oil Country Tubular Goods (OCTG). The term ‘wellhead’ refers to all equipment attached on top of OCTG on the surface. The wellhead consists of the pieces of equipment mounted at the opening of the well to regulate and monitor the extraction of hydrocarbons from underground. It prevents oil or natural gas leaks and blowout of the well. Wellheads withstanding pressures up to 20,000 psi (pounds per square inch) are used. The wellhead consists of three components: the casing head, the tubing head, and the ‘Christmas tree’. The casing head consists of heavy fittings that provide a seal between the casing and the surface. The casing head also supports the casing that runs down the well. Using a gripping mechanism, it ensures a tight seal between the head and the casing. The tubing head is similar to that of the casing

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FIGURE 2.12 Christmas Tree.28 Reproduced with permission from PennWell Corporation.

head. It provides a seal between the tubing and the surface. The ‘Christmas tree’ fits on top the casing and tubing heads, and controls the flow of hydrocarbons and other fluids from the well. It consists of many branches and is shaped somewhat like a Christmas tree (Figure 2.12).28 Hence it is commonly known as Christmas tree. Christmas tree is the most visible part of a producing well. Additional components of wellhead include hangers, valves, adapters, flanges, fittings, control systems, regulators, plugs, and sensors. Standards providing guidelines for constructing wellhead components include: • • • •

API Specification 6A, ‘Specification for Wellhead and Christmas Tree Equipment’ ISO 10423, ‘Petroleum and Natural Gas Industries – Drilling and Production Equipment – Wellhead and Christmas Tree Equipment’ NACE MRO175/ISO 15156: Petroleum and Natural Gas Industries – Materials for Use in H2S-containing Environments in Oil and Gas Productions (Parts 1, 2, and 3) NACE RP 0475, ‘Standard Recommended Practice for Selection of Metallic Materials to be Used in All Phases of Water Handling for Injection into Oil-bearing Formulations’

The components of the wellhead are constructed from a variety of materials including low-alloy steel, carbon steel, CRAs (nickel, stainless steel, and MonelÔ), and elastomers. The components of wellhead

2.11 Production pipelines

67

Table 2.14 Types of Corrosion and Corrosion Control of Offshore Wellhead Components Type of Corrosion

Condition

Type of Corrosion Control

Surface

Localized corrosion

When the CO2 partial pressure in the bottomhole is between 30 and 100 psi When the CO2 partial pressure in the bottomhole exceeds 100 psi When the bottomhole pressure exceeds 65 psia, with partial pressure of H2S exceeds 0.05 psia Underwater or submerged equipment in salt water containing dissolved oxygen Splash zone (most severe corrosion conditions exist)

• • • •

Internal

General corrosion

SSC and localized corrosion

Localized corrosion

Localized corrosion

CRA corrosion inhibitors coatings CRA

Internal

• CRA

Internal

• • • • •

External

CRA coatings CP CRA Coatings

External

are over-designed because failure of a wellhead is catastrophic. The components may be susceptible to corrosion, erosion-corrosion, galvanic corrosion, cavitation corrosion, abrasion, and SSC. The major difference between an onshore and a subsea Christmas tree is that the latter is protected externally by the application of cathodic protection. The requirements of subsea Christmas trees are presented in API 17D/ISO132628–4. These standards are similar to API 6A, except with respect to the requirement of cathodic protection (CP). Like onshore Christmas trees, the subsea trees are constructed from several materials and all are protected externally by CP. This additional protection is necessary for all underwater metallic components, including joining and bolting. NORSOK standard M503 provides guidelines for applying cathodic protection. Low alloy steels are first choice materials, but CRAs are also used. In general, the corrosion control of wellhead equipment includes use of corrosion-resistant alloys, addition of corrosion inhibitor, application of coatings, and application of cathodic protection. Table 2.14 presents types of corrosion and the relevant protection methods.

2.11 Production pipelines Production pipelines may also be known as flowlines, gathering lines, or surface pipelines. Production pipelines gather crude oil and gas from the wellhead and transport them to oil processing centers (sometimes known as batteries) and natural gas dehydration (or gas processing) facilities, respectively. The oil processing centers and gas dehydration centers may also co-exist and may be collectively known as separators. Sometimes the production pipelines transport natural gas directly to transmission pipeline or to storage facility. The production pipelines start as smaller diameter pipelines operating for a shorter distance. As the production pipelines from different wellheads converge, the downstream sections become larger. This is analogous to small creeks or streams converging to create a major river downstream.

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Table 2.15 Maximum Allowable Pipe Bends and Minimum Chord Lengths29 Nominal Pipe Size (NPS) (Diameter in Inch)

Minimum Chord Length, m

4 6 8 10 12 16 18 20 24 30 36 42

18 18 18 18 18 23 23 23 23 23 23 23

Maximum Pipe Bends,  40 35 35 30 30 30 25 25 20 20 15 12

Reproduced with permission from ASME.

Production pipelines are typically horizontal (as opposed to OCTGs which are typically vertical). However, depending on the topography of the land, the pipelines may have various bends and inclination angles. Table 2.15 presents typical allowable pipeline bends and chord lengths.29 Offshore production pipelines present another level of complexity. Two unique features of offshore production are the presence of subsea manifolds and wet Christmas trees (see section 2.10). Jumpers connect offshore wellheads to manifolds. In onshore they are installed by pipe fitters, but in offshore situations, more elaborate installation equipment is used. Manifolds are large diameter pipelines with multiple inlet connections to receive oil and gas from the jumpers and with one outlet to the risers. The risers transport oil and gas from the manifold to the production platform. The production platforms are either fixed to the bottom of tall structures, or are floating structures that are anchored to the sea-bottom by chains or wires. Offshore production platforms separate and process oil and gas. Subsea production pipelines then transport oil and gas from the offshore platform to onshore facilities. The subsea production pipelines may also transport the oil and gas directly to tankers (ships) (see section 2.25). The subsea production pipelines may be under 10,000 ft of water, with an outside pressure as high as 4000 psi. The pressure inside the pipeline is high enough to lift oil to the platforms, overcoming the outside pressure and friction loss (see section 4.2). The freezing cold temperature can cause the formation of hydrates in gas pipelines, and the deposition of paraffins, wax, and asphaltenes in oil pipelines. In both cases the pipeline becomes plugged; consequently production stops or reduces. Therefore most of the offshore production pipelines are externally coated with insulating materials, and anti-freezing chemicals are injected inside the pipeline. In some operations, the pipe-in-pipe principle is used. In this approach a smaller pipeline is enclosed inside another larger pipeline and the annular space between the pipes is filled with insulating materials.

2.11 Production pipelines

69

Standards which provide guidelines on selecting materials for pipelines include: • • • • •

API 5L, ‘Specification for Line Pipe’ ASTM A106, ‘Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service’ CSA Z245.1, ‘Steel Pipe’ ISO 3183, ‘Petroleum and Natural Gas Industries – Steel Pipe for Pipeline Transportation Systems’ NACE TM0284, ‘Standard Test Method for Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen Induced Cracking’

Standards providing guidelines for selecting materials for joining the steel pipes include: • • •

CSA Z245.11, ‘Steel Fittings’ CSA Z245.12, ‘Steel Flanges’ CSA Z245.15, ‘Steel Valves’

Flexible pipelines (coil pipes) are increasingly used in offshore production pipelines (see section 3.3.1c). Standards providing guidelines for selecting materials for coiled pipes include: •

API 5LCP, ‘Specification for Coiled Line Pipe’

A pipeline may suffer from transit fatigue caused by gravitational and inertial forces resulting from cyclic stresses during transportation. The pipe exerts a gravitational stress on pipes below during transportation. The stress fluctuates as the pipe load moves up and down. For transit fatigue to occur the loads must be high and number of cycles must be large. Transit fatigue failures are normally associated with transportation of pipes in ships or by rail. Standards providing guidelines for preventing transit fatigue include: • •

API RP 5 L1, ‘Recommended Practice for Railroad Transportation of Line Pipe’ API RP 5L5, ‘Recommended Practice for Marine Transportation of Line Pipe’

Localized internal corrosion caused by acid gases (CO2 and H2S) is the predominant failure mechanism of production pipelines. Production pipelines may also suffer from erosion at higher velocities. Standards providing guidelines for designing pipelines to avoid erosion-corrosion include: •

API RP 14E, ‘Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems’

Production pipelines may suffer SSC, hydrogen induced cracking (HIC), stepwise cracking (SWC), and hydrogen blistering in the presence of H2S (see section 5.18). Therefore materials non-susceptible to hydrogen effects should be selected. Although the lower strength pipeline steels do not suffer SSC, the welds may suffer SSC. Grooving corrosion may occur in carbon steel production pipelines carrying oxygenated solutions. Although grooving corrosion is most often observed internally, it has been found on the external surfaces of production pipelines. Grooving corrosion is a type of galvanic corrosion (see section 5.4). Clad pipeline consists of carbon steel base pipe, and CRA material, e.g., stainless steel, may be used in extremely corrosive environments. Standards providing guidelines for selecting clad materials include: •

API 5LD, ‘Specification for CRA Clad or Lined Steel Pipe’

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Corrosion resistant materials such as stainless steel are used in sweet environments and HastelloyÔ may be used in sour environments. The compatibility of the chosen materials with oxygen must be evaluated when considering CRAs for production pipelines, as oxygen contamination may occur. CRA pipelines may be susceptible to SSC in the heat affected weld zone. Stainless steels are generally immune to sensitization (a process which causes susceptibility of an alloy to intergranular corrosion or intergranular environmentally assisted cracking in a specific environment), but improper welding may produce a sensitized structure that is susceptible to SSC. External surfaces of stainless steel subsea pipelines may be susceptible to hydrogen cracking caused by CP. The CP requirements for each alloy must be determined (see section 9.3).

2.12 Heavy crude oil pipelines Heavy crude oil pipelines are special types of production pipelines transporting crude oils either with very high pour points (at pour point liquid looses its flow characteristics) or with high wax contents. They normally transport crude oil for a short distance, mostly from offshore production platforms to oil processing onshore facilities. Before entering the pipelines, the crude oils are heated to reduce their viscosity. During transportation, wax deposits in the pipeline due to dissipation of heat into the ocean water. Deposition of wax decreases the efficiency of the pipelines and, in extreme conditions, flow may stop. The construction materials of heavy crude oil pipelines are similar to those of production pipelines. Because of the higher viscosity of heavy crudes, however, special approaches are taken to operate these pipelines. Some of the unique features in operating heavy crude oil pipelines include insulation of the external surface of the pipelines with polyurethane foam to retain the heat, and inclusion of a high-density polyethylene outer shield to minimize water entry into the polyurethane foam; heating the crude oil to higher temperatures at the inlet and transporting to the destination before it cools below its pour point; mixing of the heavy crude oils with diluents or less waxy crude oil to decrease their pour point; emulsification of the heavy crude oil with water; injection of water to form a layer between the pipe wall and the crude; installation of heaters along the pipeline to maintain the temperature of the pipe above the pour point of the crude oil; and injection of paraffin inhibitors into the crude oil to prevent the wax content. In general all corrosion mechanisms discussed in production pipelines (see section 2.11) can occur in the heavy crude oil pipelines, but the corrosion conditions of heavy crude oil pipelines are less severe than those of traditional production pipelines. The mildly corrosive conditions in heavy crude oil pipelines are primarily due to the tendency of heavy crude oils to wet the metal surface. However, the water-soluble components of the heavy crude oil may affect its corrosivity.

2.13 Hydrotransport pipelines The oilsands are transported either by conveyer belt or by hydrotransport pipelines from the mining area (see section 2.8) to the extraction facilities (see section 2.16). Since 2005 hydrotransport pipelines have been the predominant method for transporting oilsands. Hydrotransport pipelines are another type of production pipeline. In general, transportation of solids in a liquid carrier stream is called

2.14 Gas dehydration facilities

71

hydrotransport. Introduction of the water and solid mixture into the pipelines is critical and is commonly performed downstream of the crushers. Slurry pumps then mix oilsands and hot water (90 C) to form stable slurries and introduce them into the hydrotransport pipelines. Large lumps of oilsand are broken down by mechanical forces during hydrotransport, allowing some of the bitumen to be separated in the form of tiny droplets. Hydrotransport pipelines consume less energy (compared to conveyer belt transportation), but erosion of pipelines by fine solids (clays), bitumen, and sands is a critical issue.

2.14 Gas dehydration facilities The gas dehydration facility is part of the natural gas network. Natural gas from wells often contains impurities that need to be removed in order to ensure its safe transportation, to help maintain the cleanliness and integrity of the pipeline system, and to create a product ready for normal consumption. Common impurities in natural gas include natural gas liquids (NGLs), H2S, CO2, helium, and water. Impurities are removed in gas processing and treatment facilities designed specifically for the gas stream. Each type of impurity within a gas stream requires a specific treatment process to ensure its complete or adequate removal. As the well depletes and the pressure drops, the NGLs condense at various surface processing vessels. Heavier hydrocarbons and water have higher dew points than natural gas (methane). If they are not removed from the natural gas, they condense into liquids along the pipeline. These liquids collecting in the low spots of the pipeline, may restrict or, in extreme cases, completely block gas flow. Additionally, the BTUs of NGLs are higher than that of natural gas; therefore it is economical to separate them (see Table 1.3).

2.14.1 Oil separation Gas containing trace amounts of oil is called oily gas. The small amount of oil is separated from the gas by separators which are often identified by their shapes as vertical or horizontal. In both separators the liquid is separated from the gas by baffles. The baffles create centrifugal forces in the vertical separators or an abrupt change in direction in the horizontal separators to separate the gas and liquid. The separators are typically manufactured from carbon steel. Localized pitting corrosion and flowinduced localized corrosion (FILC) may occur in these units. The separators may be clad with CRAs to control corrosion.

2.14.2 Acid gas removal Acid gases (H2S and CO2) present in the natural gases are removed in the gas treating units. The unit may also be known as gas sweetening or acid gas removal unit. To remove H2S, the natural gas is passed across iron fillings. The H2S reacts with iron forming iron sulfide. Iron sulfide is removed from the vessel and fresh lots of iron are frequently added. Treating the gas with iron fillings is economical when the sulfur content of the gas is below 20 pounds per day. When this level is exceeded, the acid gases are removed by using amines. CO2 is also removed by using amines. Commonly used amines are monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), and diaminoethoxyethanol (Diglycolamine) (DGA).

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A typical amine gas treating process includes an absorber unit and a regenerator unit. In the absorber tower, the amine solution flows downwards, absorbing H2S and CO2 from the natural gas flowing upwards. The acid gas free natural gas is collected at the top of the unit. The amine solution rich in absorbed acid gases is collected from the bottom of the unit. The amine rich in acid gases is regenerated by boiling to strip off the acid gases and is reused in the absorber tower. The H2S gas removed from the amine solution in the regenerator is then sent to the Claus unit (section 2.31.18) where it is converted into elemental sulfur. Many components of acid gas removal units may suffer internal corrosion due to the presence of large amounts of CO2 and H2S being handled.

2.14.3 Water removal Gas transmission pipelines (see section 2.21.2) require a water content of less than 7 lb/MMSCF (pounds per million cubic feet). The gas is treated to remove water in gas dehydration facilities. The three principle methods used are glycol treatment, desiccant, and adsorption. In glycol treatment plant, natural gas enters the bottom of the vessel with baffles or loosely packed fillers. Triethylene glycol (TEG) or a similar chemical is charged from the top of the vessel. As the TEG passes the natural gas, it absorbs the water. The water-free gas exits through the top of the vessel and the TEG exits through the bottom. TEG is regenerated by heating it in the reboiler to evaporate water, and is reused. Desiccants use activated charcoal or molecular sieves of tiny metal particles. The sieves are manufactured with tiny holes to trap only certain-sized molecules. As gas comes in contact with these sieves, water particles are retained in the holes. Adsorption systems contain substances that specifically adsorb water but not hydrocarbons. Localized internal corrosion occurs in almost all locations of water removal units due to the presence of acid gases. In the reboiler (to reclaim glycol) higher temperature and presence of oxygen decompose glycol to produce organic acids. Therefore the reboiler units experience the highest internal localized corrosion. The reboiler units may also undergo H2S blistering and HIC.

2.15 Oil separators Crude oil from the wells may contain several contaminations. The separators remove gas (oil-gas separators), water (oil-water separators), and solid (oil-sand separators) from oil. Oil separators are traditionally constructed using carbon steels and are further protected by the addition of corrosion inhibitors. Some separators are internally coated with polymeric or metallic coatings. Use of metallic coatings increases the probability of galvanic corrosion if the coating is damaged. Internal surfaces of certain separators can be protected by CP. Separators handling corrosive fluids may be constructed from carbon steel clad with CRAs, or CRAs themselves. To minimize corrosion and scaling, the separators and heat-transfer surfaces are cleaned periodically. The entry of oxygen is prevented to the greatest extent possible with an inert gas blanket. If the scaling tendency is high, the oil separators are constructed from steel containing increasing amounts of chromium (2.25 to 12% Cr). If steels with higher chromium content suffer from localized corrosion in sour environments, then CRAs are used to construct the oil separators.

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The separators are designed to handle high flow rates. For this reason, the oil separators are designed as pressure vessels. Standards providing guidelines for designing pressure vessels include: • • • • • • • •

ASME Sec. VIII, Div. 1, ‘Code for Unfired Pressure Vessels’ API 510, ‘Pressure Vessel Inspection Code – Maintenance, Inspection, Rating, Repair and Alteration’ API RP 14, ‘Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems on Offshore Production Platforms’ API RP 14E, ‘Recommended Practice for the Design and Installation of Offshore Production Platform Piping Systems’ AIME 5, ‘Separators technique, Oil and Gas Separation Theory, Application and Design’ API 12J, ‘Specification for Oil and Gas Separators’ API 1104, ‘Standard for Welding Pipelines and Related Facilities’ API 2610, ‘Design, Construction, and Operation of Pressure Vessels’

2.15.1 Oil-gas separator Oil containing small amounts of gas is known as gassy oil. The gas from the oil is separated in an oilgas separator. Typical components of an oil-gas separator include a primary separation section; a secondary gravity settling section; a mist extractor (for removal of small liquid particles from the gas); a liquid settling section (to separate gas and water from oil); gas outlet; oil outlet; water outlet; storage tanks; and several accessories such as valves and motors. During separation, formation of foams, deposition of paraffin, and corrosion are avoided to the greatest extent possible. When pressure is reduced in the separators, foam or froth may occur due to the liberation of gas bubbles trapped in the oil. Foaming delays the oil and gas separation. The foam is broken by settling, agitation (baffling), heating, addition of chemicals, and use of centrifugal force. Deposition of paraffin in oil-gas separators fills the vessel and blocks the mist extractor and fluid passages. Though paraffin can be removed from the separator by cleaning with steam or solvent, deposition of paraffin in the oil-gas separators are avoided by heating the separator, coating the internal surface of the separators, or adding chemicals. Most sand and solids are removed by sand filters placed in the downhole tubular. If the downhole sand filters are not in place, or are not working properly, sand and other solids reach the oil-gas separators in appreciable quantities. Small quantities of sand can be removed by constructing oilgas separators with conical bottoms. Salt may be dissolved in water and the water and sludge are periodically separated from the bottom of the oil-gas separator. The presence of solids, acid gases (H2S and CO2), and salt may cause localized pitting corrosion in the oil-gas separators. Some measures taken to avoid foams and paraffins counteract corrosion control measures. Therefore all control measures are optimized. To avoid internal corrosion, CP is applied in some separators.

2.15.2 Oil-water separator Oil and water can co-exist in several forms; when the diameter of oil droplets exceeds about 30 microns, a free oil-free water mixture typically exists. When such a mixture is mechanically dispersed

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Table 2.16 Types of Water-Oil Separation Process30 Separation Process

Smallest Oil Droplet Removed, mm

Gravitational Centrifugal Filtration Chemical Membrane

150 100 25 15 5

Necessary Equipment/ Accessories Large equipment Motor Pressure Recovery of chemicals Cleaning treatment of membranes and power

(by a pump, for example), dispersion of one phase in another may occur, in which the droplet diameter may be between 1 and 30 microns. Emulsions (water-in-oil or oil-in-water) may form when there is chemical interaction between oil and water due to the presence of surface active substances at the oil/ water interface. The surface active substances may also result in dissolution of water and oil. This happens because the surface active substances change the ionic nature of water (making it non-ionic) or oil (making it ionic). Finally, finely dispersed water-wet solids in the oil phase or oil-wet solids in the water phase may also exist. Formation of stable oil-water emulsions during the transportation of hydrocarbons from the well to the separators is prevented to the greatest extent possible. The measures taken include avoidance of chemicals (e.g., corrosion inhibitors) which may cause stable chemical emulsions; selection of appropriate pipe size to avoid turbulence and to avoid formation of fine droplet dispersions; and avoidance of devices such as pumps, valves, elbows, and tees which may form mechanical dispersions. Several types of separators are used including gravitational, centrifugal, filtration, chemical, and membrane. Table 2.16 presents their general characteristics.30 Standards providing guidelines for designing and operating separators include: • • •

ASTM D6104: ‘Standard Practice for Determining the Performance of Oil and Water Separators Subjected to Surface Run-Off’ ASTM D6157: ‘Standard Practice for Determining the Performance of Oil and Water Separators Subjected to a Sudden Release’ ASME Sec. VIII. Div. I, ‘Unfired Pressure Vessels’

2.15.3 Oil-solid separator Suspended solids, e.g., sand, rust, and scales in oil, are separated by gravity settling, cyclones, desanders, centrifuges, filters, and flotation methods.

2.16 Recovery centers (Extraction plants) Recovery centers (may also be known as extraction plants) are associated with oilsand operation (see sections 2.8 and 2.9) and are equivalent to oil separators (see section 2.15). In the recovery centers, the bitumen from oilsands is treated with hot water and is agitated, causing the oil to float as froth. The

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froth contains bitumen, water, and inorganic solids. Poor quality oilsand froths have lower oil contents and higher contents of water and solids. The froth is further treated to extract oil. In one process the froth is diluted with naphtha to decrease the density and viscosity of the bitumen and to promote coalescence of emulsified water; the mixture is then separated by centrifuging. In another process, a paraffinic solvent is added to the froth to reduce the bitumen density and viscosity and to promote flocculation of the suspended solids and promote water separation. Refineries (see section 2.31) are designed to process only specific crudes. Bitumen from oilsands (see sections 2.8 and 2.9) does not meet the input requirements of some refineries. In addition, extra heavy crudes do not meet minimum specifications for oil transportation pipeline (see section 2.21.1). In order to be transported through pipelines to the refineries the bitumen is either diluted or upgraded. The bitumen is diluted with naphtha, light synthetic crude oil, or natural gas condensates (e.g., pentanes) to produce diluted bitumen (dilbit). The dilution of bitumen also takes place in extraction centers. The material requirements of recovery centers and their corrosion characteristics are similar to those of oil separators. However, the recovery centers handle large volumes of sand, operate at higher temperatures, and have more fluid movement than traditional oil separator units. Therefore, the rates of erosion-corrosion and FILC are higher.

2.17 Upgraders Section 2.16 discusses the preparation of dilbit so that the bitumen from oilsands meets the requirements of the oil transmission pipeline as well as refinery requirements. Alternatively, the crude oil may be ‘upgraded’ to produce synthetic bitumen (synbit) or synthetic crude oil (SCO). Upgraders are essentially standard refinery elements that have been moved upstream to permit conversion of nontransportable bitumen into pipeline- and refinery-ready crude oil. A variety of processes have been developed to upgrade heavy hydrocarbons to light hydrocarbons. Through upgrading, bitumens are converted into hydrocarbon streams – naphtha, light gas oil (LGO) and heavy gas oil (HGO) – that are blended to create transportable crude oils. There are two basic steps in the upgrading process: primary upgrading and secondary upgrading. In primary upgrading, sour crude (or crude containing more than 0.5% sulfur compounds) is produced and in the secondary upgrading sweet crude (crude containing less than 0.5% sulfur) is produced. Upgraders may consist of atmospheric distillation unit (ADU) (see section 2.31.2), vacuum distillation unit (VDU) (see section 2.31.3), hydrotreating unit (HTU) (see section 2.31.4), catalytic cracking unit (CCU) (see section 2.31.5), thermal cracking unit (TCU) (see section 2.31.6), coker (see section 2.31.12), and other units of refineries (see section 2.31), for functionalities, materials of construction, and corrosion characteristics of these units.

2.18 Lease tanks The crudes from oil separators (see section 2.15), recovery centers (see section 2.16), and upgraders (see section 2.17), are collected in the lease tanks. The quality of the crude oil collected in the lease tank is checked. In manual operations, facility personnel measure and test the oil to determine whether

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it meets the specifications set by the pipeline operators. Specific measurements include gross volume of product, temperature, and basic sediment and water (BS&W) content. If the tank products do not meet the required specifications, the contents may be rejected, reprocessed or blended until they again satisfy pipeline requirements. These measurements may be automatically evaluated by a lease automatic custody transfer (LACT, or simply ACT) unit. After verification that the hydrocarbons meet specified quality requirements, quanta of product (called batches) are transmitted into the transmission pipeline system (see section 2.21.2) or into tankers (see section 2.25). If the amount of crude being produced at a location does not justify the capital costs of building a pipeline to the lease, the crude may be hauled by rail (see section 2.27) or truck (see section 2.28) to a larger transportation center. Standards providing guidelines to construct lease tanks include: • •

API 620, ‘Design and Construction of Large, Welded, Low Pressure Storage Tanks’ API 650, ‘Welded Steel Tanks for Oil Storage’

Lease tanks may experience corrosion where water accumulates on the tank floor. The presence of acid gases (sour and sweet) and microbes increase the corrosion susceptibility. Many lease tanks contain internal coatings to minimize their susceptibility to internal corrosion by providing a protective physical barrier to the water. The tanks may also suffer corrosion at the inside surface of the roofs if moisture is allowed to enter the tanks.

2.19 Waste water pipelines31 Water is separated from crude oil at various points, including at gas dehydration facilities (see section 2.14) and oil separators (see section 2.15). Most of the water is purified and reused, but a portion of water becomes waste. Waste water pipelines transport the waste water to a disposal facility (underground or surface) according to site-specific environmental regulations. Waste water is typically treated to remove materials including acid gases (CO2 and H2S) (see section 2.14.2), suspended oil (see section 2.15.2), suspended solids (see section 2.15.3), scale (by the addition of scale inhibitors), and bacteria (by the addition of biocides). The extent to which the impurities are removed depends on the environmental regulations. Standards providing guidelines for constructing waste water pipelines include: • •

API. 1612, ‘Guidance Document for the Discharge of Petroleum Distribution Terminal Effluents to Publicly Owned Treatment Works’ API 4602, ‘Minimization, Handling, Treatment and Disposal of Petroleum Products Terminal Wastewater’

Selection of materials for surface facilities (pipe, valves, and fittings) to handle water for disposal depends on the pressure rating, the corrosivity of the fluid, the location, and the economic cost over life. Large diameter cement pipe is used in low pressure water systems (200 psi (1,379 kPa) or less). This pipe is resistant to corrosion and is relatively low cost. The pipes are jointed with rubber rings. Because the pipes are not flexible, a deflection of 6 in. (152 mm) is obtained using the rubber joints.

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The cement pipes are coated internally with plastic or fiberglass to reduce friction loss and to remove seepage of fluids. Standards providing guidelines for constructing cement pipes include: •

API 10E, ‘Recommended Practice for Application of Cement Lining to Steel Tubular Goods, Handling, Installation, and Joining’

Plastic pipes are increasingly used to transport waste water. Plastic pipes are typically smaller in diameter (12’ (305 mm) or lower) and operate at lower pressure (300 psi (2068 kPa) or lower). The plastic pipes are light weight, are corrosion resistant, and have low friction loss. Standards providing guidelines to construct plastic pipes include: • • •

API 5LE, ‘Specifications for Polyethylene Line Pipe’ API 5LP, ‘Specification for Thermoplastic Line Pipe’ API 5LR, ‘Specification for Reinforced Thermosetting Resin Line Pipe’

The strength of the pipes decrease in the order: fiber reinforced plastic (FRP) pipe (strongest) > poly vinyl chloride (PVC) > PE. FRP is increasingly used because of its strength and resistance to heat and hydrocarbons. Currently these pipes are available in diameters up to 12 in. (305 mm). Plastic pipes are brittle. Therefore extreme care should be taken during construction and installation. The properties of plastic pipes vary with temperature and fluid being transported. Cast iron pipes are used over the pressure range 200 to 250 psi (1,379 to 1,724 kPa). Under waste water pipeline operating conditions, the corrosion resistance of cast iron pipe is same as that of carbon steel. It is less susceptible to impact and temperature effects than plastic pipe, but is more brittle than carbon steel pipe. Cast iron is susceptible to cracking in the presence of cold water. Waste water pipelines are predominantly constructed from carbon steel. Carbon steel pipes are available in diameters up to 64 inches (1.6 meter). They can withstand high pressure, have high impact resistance, and have flexural strength. They are however susceptible to both internal and external corrosion. External corrosion is controlled with polymeric coating (coal tar, epoxy, and extruded) and CP. Internal corrosion of carbon steel pipes is controlled to a large extent by excluding oxygen. Further they may be protected by internal liners. Pipelines transporting highly corrosive fluids, e.g., CO2 floods, are constructed using stainless steel.

2.20 Tailing pipelines Tailing pipelines, which may also be known as slurry pipelines, are a variation of waste water pipelines. Tailings are a mixture of water, clay, silts, and finely ground sand that is left over once heavy oil is removed from oilsands. These tailings are deposited in containment ponds to prevent residual oil from leaching into the environment. Providing safe, permanent storage of tailings is important because tailing materials that are not properly contained can have undesirable effects on the environment. The tailings are transported in pipelines from the oilsands extraction facilities to the ponds. The operation of tailing pipelines is different from that of other pipelines, because the fluids being transported are considered as non-Newtonian. In general, fluids can be classified as Newtonian or non-Newtonian. Pure fluids (water, air, oil) are Newtonian fluids and fluids containing suspended solid particles are non-Newtonian. A rheogram is

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Shear Stress

Non-Newtonian fluid

Non Newtonian fluid Non Newtonian fluid

Newtonian fluid Non Newtonian fluid Velocity

FIGURE 2.13 Rheograms of Newtonian and Non-Newtonian Fluids.32

commonly used to differentiate between Newtonian and non-Newtonian fluids. This is constructed from the following equation:32 UL (Eqn. 2.1) Wss ¼ hl L where Wss is the wall shear stress, hl is the viscosity of liquid, UL is the velocity of the liquid, and L is the distance perpendicular to the wall. The plot of Wss and UL/L is known as a rheogram. For Newtonian fluids, it is a straight line passing through the origin (Figure 2.13).32 The slope of the rheogram is the viscosity and for Newtonian fluids it is independent of shear stress. The rheogram of a non-Newtonian fluid is either curved or does not pass through the origin. The pumps used to move slurries in the pipe are similar to liquid pumps, but they are constructed of materials resistant to wear and corrosion. Positive displacement pumps are used for transporting slurries in a long distance pipeline and propeller pumps are used for transporting slurries in a small distance pipeline but at higher discharge rate. Centrifugal pumps are used under medium transportation conditions. Typically, tailing pipelines are designed with a minimum velocity at which solids do not settle (typically between 3.9 to 4.3 feet/s (1.2 and 1.3 m/s)); a maximum velocity at which erosion becomes the prominent issue (typically at 16 feet/s (5 m/s) depending on the particle size and density); a maximum slope that the pipeline can tolerate, and pumps and valves that are compatible with pipeline operations. The main failure mechanism of tailing pipelines is erosion and corrosion. To control erosion-corrosion the tailing pipelines may be internally coated with erosion resistant coatings such as tungsten carbide.33 The start of the tailings pipelines can experience oxygen corrosion which leads to further metal loss due to erosion and corrosion.

2.21 Transmission pipelines Transmission pipelines are the arteries of oil and gas industry, transporting the hydrocarbons from the wells to locations where they are used as fuels or where they are refined into useful products.

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Tanker

Pipeline

Barge

Rail

Truck

0

10

20

30

40

50

60

70

80

Cents / Barrel-mile

FIGURE 2.14 Advantages of Pipelines.

34

Transmission pipeline systems are often referred to as ‘midstream pipelines’, ‘interstate pipelines’, ‘cross-country pipelines’, or simply ‘pipelines’. Pipelines are the most convenient method for transporting large quantities of crude oil and gas. They have several advantages – the transportation cost of pipelines is lower than other modes of transportation (Figure 2.14);34 the energy required to operate the pipelines is lower than that required to operate other modes of transportation (Table 2.17);35 and

Table 2.17 Energy Requirements of Operating Pipelines and Other Modes of Transportation35 Mode of Transportation Airplane Truck Railroad Waterway (barge) Oil pipeline

Energy Consumption (BTU/Ton-mile) 37,000 2,300 680 540 450

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pipelines are environmentally friendly, safe, reliable, convenient, and less sensitive to inflation when compared to other modes of transportation. According to one statistic, the worldwide total length of transmission pipelines is about 800,000 miles (1.3 million kilometers) of which 57% are in North America, 19% are in Russia and China, 14% are in Europe; and the remaining 10% are in the rest of the world. Transmission pipelines are typically built as a single line. As the demand expands, parallel pipelines are often built. These parallel lines are often called loop lines. It is common to have three or more pipelines in the same pipeline corridor or right-of-way. Hydrocarbons are physically transported through pipelines as a result of pressure differentials; i.e., the hydrocarbons flow from an area of high pressure to an area of low pressure. The pressure is created inside the pipeline by compressor stations (see section 2.22) in gas transmission pipelines, and by pump stations (see section 2.23) in oil transmission pipelines. The compressor and pump stations are commonly known as facilities. The extent to which the pipeline can be pressurized is first determined as the design pressure (Pdesign):36 Pdesogm ¼

2½SMYSŠ:tw :Fdesign :Flocation :Fjoint :Ftemperature do

(Eqn. 2.2)

where Pdesign is the design pressure, [SMYS] is the specified minimum yield strength of pipe material, psia; tw is the pipe thickness, inches; do is the pipeline diameter, inches; Fdesign is the design factor; Flocation is the location factor; Fjoint is the joint factor; and Ftemperature is the temperature factor. The SMYS provides a measure of allowable stress (see also section 3.2.1a) which the pipeline material can be subjected to. The pipeline experiences three types of stress: longitudinal (along the length), circumferential, and radial. For thin-walled pipes, (i.e., where the wall thickness is less than one-tenth of the radius) only longitudinal and circumferential stresses exist. For thick-walled pipes, in addition, radial stresses may become appreciable.36 Internal pressure is the primary source of stress and it exerts both in longitudinal and circumferential directions. If the pressure exceeds the yield strength of the pipe, the pipe bulges, i.e., the diameter of the pipe increases and consequently the wall thickness decreases. Other causes of stresses include the mass of pipe itself, the mass of its contents (e.g., mass of hydrocarbons), the mass of materials on it (e.g., coating and insulation), external loads and thermal stress (e.g., expansion and contraction of the pipe wall as the temperature fluctuates). Internal pressure causes twice the amount of circumferential stress in a pipe than longitudinal stress; therefore the minimum wall thickness to contain internal pressure is determined by the allowable circumferential stress. The circumferential stress on a thin-wall cylinder is given by: s¼

P:r tw

(Eqn. 2.3)

where s is the stress, P is the pressure, r is the radius, and tw is the pipe wall thickness. Equation 2.3 or similar equations are used to determine the minimum wall thickness of a pipeline and the maximum allowable operating pressure (MAOP). Designing the pipeline based on allowable circumferential stress is known as stress-based design. Designing pipelines based on anticipated failure due to longitudinal stress is known as ‘strain-based design’. Normally transmission pipelines are based on allowable circumferential stress, i.e., stress-based design. However, in locations where longitudinal stress is the limiting factor, the pipelines are designed

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so as to overcome it, i.e., strain-based design. For example, a strain-based design is used to construct northern pipelines where the frost-heave and thaw-settlement of ice causes longitudinal stress. The operation of pipelines is strictly controlled within the established operational conditions. Most operations, such as starting and stopping of pumps, opening and closing of valves, reading meters, servicing equipment, and repairs are carried out physically on the pipelines in the field. With the advancement of communication technologies, more and more operations are carried out remotely and automatically from central control rooms. Central control rooms have become the nerve centers of pipeline operations. Common control room operations include planning and scheduling operations, monitoring and controlling the pipeline, and responding to and correcting abnormal operations. Abnormal operations may either be planned or unplanned. Planned abnormal operations include running internal inspection devices, maintenance operations, and performing pressure tests. Unplanned abnormal operations include unintended closure of valves, drift of pressure beyond the normal operating limit, loss of communication, and operation of any safety device. Safety devices are installed for fail-safe protection as backup. Under normal operation conditions they do not function. Their activation signals abnormal operation. Abnormal operations do not always mean an emergency situation. The controllers analyze the situation and respond appropriately. The majority of oil and gas transmission pipelines are constructed using carbon steel. Standards providing guidelines for the requirements of pipeline steel as well as values of design factors (see Eqn. 2.2) include: • • •

CSA Z662, ‘Oil and Gas Pipeline Systems’ ASME B31, ‘Standards of Pressure Piping’ API 5L, ‘Specifications for Line Pipe’

By regulation, the external surfaces of most transmission underground pipelines are protected by polymeric coatings and further backed up by cathodic protection. When both these systems fail, the external surface is susceptible to corrosion. Several types of corrosion can take place including general, pitting, SCC (see section 5.17), stray-current (see section 5.21), telluric current (see section 5.22), and alternating current (see section 5.23). Offshore transmission pipelines are normally larger diameter with do/tw between 25 and 30. Some pipelines may be bundled together and may be further protected with thermal and concrete coatings to reduce heat loss and to increase stability. Standards providing guidelines for constructing offshore pipelines include: • • • •

ASME B31, ‘Standard for Process Piping’ CSA Z187, ‘Offshore Pipelines’ DNV 1981, ‘Rules for Submarine Pipeline Systems’ Institute of Petroleum Pipeline Code IP6 (UK)

The external surfaces of offshore pipelines may undergo general, pitting, SCC, and splash zone corrosion, i.e., the pipe section that is splashed by the surface wave undergoes severe corrosion.

2.21.1 Gas transmission pipelines Gas transmission pipelines transport gas from gas dehydration facilities (see section 2.14) to consumers who may be several thousands of miles away. The gas transmission pipeline may deliver

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directly to customers (e.g., electric power gathering stations), local distribution centers (LDC) (see section 2.34), or gas storage facilities. Demand for natural gas depends on time of day, day of the week, weather conditions, and season. Therefore gas transmission pipeline operations are continuously adjusted to meet the demand. The gas is transported through the transmission pipelines by pressure differentials (see section 4.2). Upstream producers prefer the transmission pipelines to operate at as low a pressure as possible so that they can supply into the lines with little compression. On the other end of the transmission pipelines, higher gas transmission pipeline pressures enable LDC operators to draw natural gas easily into their distribution pipelines. Transmission pipeline operators therefore continuously balance the needs of different groups by adjusting the line pressure. Compressors (see section 2.22) are used along the pipeline to control the flow and pressure. The quantity and quality of gas entering the transmission pipelines are strictly controlled. The gas expands to fill the pipeline, so measurement of gas quantity is relatively difficult. Orifice meters, turbine meters, and ultrasonic meters are commonly used. Besides quantity, the quality of natural gas is important. To maintain the quality of the gas, samples are drawn, manually or automatically, into a pressure bottle and analyzed with a gas chromatograph (see section 12.3). Common contaminants analyzed include ethane, propane, butane, heavier hydrocarbons, organic acids, CO2, H2S, and water. Gas transmission pipeline operations require water content to be less than 7 lb/MMSCF. However water may enter into the gas transmission pipelines accidently when the separators malfunction or when wet gas is intentionally injected into the gas transmission pipelines. The presence of water increases the susceptibility of pipelines to corrosion. Gas impurities such as acid gases (CO2 and H2S) and organic acids (e.g., acetic acid) increase the corrosivity of water. Normally the corrosion in gas transmission pipelines occurs at the bottom of the pipeline in the low lying areas if water is allowed to accumulate. However, under certain conditions corrosion may occur at the top of the pipeline, commonly known as ‘Top of the Line Corrosion’ (TLC) (see section 5.24). Gas transmission pipelines may contain several types of solids including sand, sludges, biomass (containing microbial species), inorganic scales (e.g., calcium carbonate, barium carbonate), organic scales (e.g., paraffins and asphaltenes) and corrosion products. These solids are commonly known as black powders due to their appearance. Black powders may increase susceptibility to corrosion (see section 4.8).

2.21.2 Oil transmission pipelines Oil transmission pipelines are also known as trunk lines. They gather crudes from oil separators (see section 2.15) or recovery centers (see section 2.16) and transport them to tankers (see section 2.25) or to refineries (see section 2.31). Crude oils are transported through pipelines by the differential pressure provided by pumps. Pumps are used along the pipeline to control both flow rate and pressure; as well as to overcome hydrostatic (elevation) pressure gradients. The total number of pump stations required to move crude oil across long distances is determined by consideration of the maximum allowable operating pressure of the pipe, the hydrostatic pressure gradients along the pipeline, and the expected operating pressure drop along the pipeline. Transmission pipeline design represents a capital and operational cost balance between diameter, wall thickness, grade, energy costs, and pump facilities. For liquid pipeline systems, pump stations are typically located every 40 to 60 miles (64 to 97 km). The time the oil takes to travel from one end of a pipeline to another is known as transmit time. Under

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normal operating conditions the transit time is between 12 and 15 days to transmit oil through a distance of 1,000 miles (1609 km) (approximately 3 to 4 miles (5 to 6.5 km) per hour). The operation of pipelines is strictly controlled within established normal operational conditions. With the advancement of automation and communication technologies, most pipeline operations, such as starting and stopping pumps, opening and closing of valves, monitoring and evaluating pipeline conditions are carried out remotely under 24/7 oversight by specially trained, control center personnel. Common control room operations include planning and scheduling operations, monitoring and controlling the pipeline, and responding to and correcting abnormal operations that may be planned (i.e., pigging or other pipeline maintenance tasks) or unplanned (i.e., automatic activation of safety devices). Crude oil quality is important, since each crude oil type results in different refined products. Crude oil transmission pipelines have quality requirements. Most of these are based on the specific gravity and sulfur content of the crude oil. The specific gravity and sulfur contents of the product are measured at injection and delivery points (custody transfer locations) of transmission pipelines, and at various intermediate locations for batch tracking purposes. In multiproduct lines, different grades of crude oils move end to end in successive batches. When one product or type of crude follows another, some mixing inevitably occurs. This volume of mixed fluids is called transmix or interface material. Transmix materials are handled in various ways depending on their quality. The transmix is typically added to the batch of the lower grade crude, but may be segregated in a transmix receipt tank for separate processing. The possibility of corrosion in oil transmission pipelines is low unless water is allowed to accumulate. This is due to the fact that the majority of corrosive and erosive materials are removed upstream of the pipelines as part of achieving transport quality specification (i.e., BS&W limit of 0.5% of volume). Additionally, transmission pipelines carry little or no CO2 or H2S, and they operate at temperatures too low for corrosive species such as naphthenic acid or sulfur to influence corrosion.

2.22 Compressor stations Compressors are used to pressurize the gas for transportation through transmission pipelines. The pressurized gas flows from a high pressure area upstream through the pipeline to low pressure area downstream. The compressors are present in locations commonly known as ‘compressor stations’. To determine the number of stations, the total pressure requirement is divided by the MAOP. For example, if the total pressure requirement is 5,000 psi (34 MPa) and if the MAOP is 1,000 psi (7 MPa), then the number of compressor stations is five. Compressor stations are generally built every 50 to 100 miles (80 to 160 km) along the length of the gas transmission pipeline. In addition to compressor stations, gate settings are installed periodically (typically every 10 miles (16 km)) along the natural gas transmission pipelines. When multiple pipelines run parallel to one another in the same right-of-way, crossover pipings connecting those pipelines are built at the gate settings. Gate settings are used to stop the flow in a pipeline or to divert the flow between the adjacent pipelines. This flexibility is often useful to isolate a pipeline section which had a leak or on which some maintenance or other activities need to be carried out. A typical compressor station consists of three components (Figure 2.15):37 compressors, prime movers, and accessories.

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FIGURE 2.15 Schematic Diagram of Compressor.37 Reproduced with permission from ASME.

There are three major types of compressors: positive displacement, dynamic (centrifugal), and injectors; of these, positive displacement and dynamic compressors are predominantly used in gas transmission pipelines. Positive displacement compressors are sometimes called intermittent flow compressors. They confine gas within an enclosed volume and then reduce the volume of the entrapped gas. As a consequence, the pressure of the entrapped gas increases. The compressed gas at higher pressure is then discharged at the discharge point. The positive displacement compressors can further be divided into two types: reciprocating compressors and rotary compressors. In reciprocating compressors, the volume of the gas within a cylinder is reduced by a piston. Valves are placed in the cylinders to direct the flow of compressed gas. In rotary compressors, the rotors are equipped with vanes or lobes. The rotors trap the gas between them and the outside casing and pressurize them. The gas moves from the inlet to outlet as the motor turns. Dynamic compressors are also known as continuous flow compressors or turbo-compressors. They increase the pressure of the gas by inertial forces, i.e., they increase the velocity of gas by changing the energy into pressure. Dynamic compressors can further be divided into centrifugal (radial)

2.23 Pump stations

85

compressors and axial compressors. In centrifugal compressors the velocity of the gas is increased by the blades of the rotating impeller. As the impellers spin, centrifugal forces increase the tangential velocity of the gas. In axial compressors gas flows parallel to the shaft. The spinning motor compresses the gas stream. Compressors are connected to another machine known as a prime mover that drives the shaft of the compressors. Some common types of prime movers or driving machines are: gas turbine, electric motor, engine, and steam turbine. The gas turbines are the most commonly used prime movers in gas transmission pipelines. They utilize hydrocarbons as fuel and deliver the shaft power to the compressor by a power turbine. The electric motors have a limited number of moving parts and operate at constant speed. They are ideally suited for driving centrifugal pumps and compressors. Their noise emission level is low and they produce no hydrocarbon emissions, making them the ideal choice for compressor stations located in populated areas. The engines work in virtually the same way as car engines, but with higher horse power (10,000 to 20,000 horse power). They use natural gas as fuel. The reciprocating nature of the engines makes them ideal prime movers for reciprocating compressors. The steam turbines are similar to gas turbines, except that they use steam as fuel. Accessories commonly found in the compression stations include a station block valve (before the station to isolate the station from the pipeline if necessary); a scraper receiver (to receive pigs – [see section 7.2]); scrubbers (to remove liquids from the gas); incoming meters (to measure the gas); strainers (to remove debris from the gas); outgoing block valve (to regulate the gas from the station); pressure reducers (to reduce the pressure of the gas flowing into the station); and boosters (to boost the pressure of the gas flowing out of the station). Compressors may be exposed to benign dry gas or corrosive wet gas. In dry environments, the components of compressor are constructed from carbon steel, cast iron, and low-alloy steel; in wet sweet environments causing corrosion and erosion-corrosion, the components are constructed from stainless steels; in wet sour environments causing SSC, the components are constructed from materials meeting the requirements of NACE MR0175/ISO 15156; and in environments causing both erosion-corrosion and cavitation the components are constructed from nickel alloys or cobalt alloys. The components of compressors may suffer from general corrosion, pitting corrosion, galvanic corrosion, and erosion-corrosion. An industry survey has indicated that 50% of failures of transmission pipelines occur in the facilities.38,39 Of these, more than 80% are caused by corrosion (Table 2.18).38

2.23 Pump stations Pump stations perform the same function that compressor stations perform for gas transmission pipelines, i.e., they house pumps that generate pressure to transport oil through oil transmission pipelines. There are two categories of pumps: kinetic and positive displacement (Figure 2.16).40 Kinetic pumps may be centrifugal, peripheral, and special; of these centrifugal pumps are extensively used in oil transmission pipelines. Centrifugal pumps are high-speed, high-volume units powered by internal combustion engines or electric motors. In large stations they are connected in series, thereby increasing the amount of pressure exerted on the liquid. Positive displacement pumps are further classified into rotary, reciprocating, and blow case pumps. The rotary pump consists of a fixed casing containing gears, cams, screws, vanes, or similar elements

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Table 2.18 Failure Incidences in Pipeline Facilities38 Components Involved

Number of Incidences

Percentage

)

Pipe Valve Other Pump Threaded and other fittings Sump/Separator Meter/Provers Scraper trap Weld fitting Weld, including heat affected zone Repair fitting

20 17 16 16 14 7 3 3 2 1 0

73 61 59 58 50 26 10 10 7 4 1

)

57 of them were caused by corrosion

Pumps

Positive displacement

Reciprocating

Blow case

Kinetic

Rotary

Centrifugal

Peripheral

Special

Piston/Plunger

Diaphragm

FIGURE 2.16 Types of Pumps.40

actuated by rotating of the drive shaft. The reciprocating pumps may use a piston or a crank to pressurize the liquid. The materials used to construct the components of pumps depend on environmental conditions. In mildly corrosive environments the pump components are constructed from carbon steel or cast iron;

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87

in severely corrosive and erosive environments the components are constructed from CRAs including stainless steel, MonelÔ, HastelloyÔ, and Ti alloys. Standards providing guidelines for selecting materials for pumps include: • • •

API 610, ‘Centrifugal Pumps for General Refinery Service’ ANSI/ASME B73.1M, ‘Specification for Horizontal End Suction Centrifugal Pumps for Chemical Process’ ANSI/ASME B73.2M, ‘Specification for Vertical In-line Centrifugal Pumps’

Pump components may suffer from general corrosion, pitting corrosion, galvanic corrosion, cavitation corrosion, and erosion-corrosion.

2.24 Pipeline accessories A pipeline network, although continuous, is not uniform. They change in direction, vary in diameter, branch out, join together, and have different flow rates. Several accessories play vital roles in operating the pipelines, in facilitating the changes and in monitoring the condition of the pipeline. For instance, fittings, flanges, bolts, valves, loops, branch, expansion, joints, and manifolds are used to make changes to the pipeline network. Actuators are used to execute these changes. Meters, provers, and pressure gauges are used to monitor the changes. These accessories are briefly described in the following paragraphs. Fittings are often welded onto pipes during installation of pipelines. There are several types of fittings including 90s, 45s, 180s, tees, weldolets, threadolets, reducers, expanders, and caps. Fittings (45 , 90 , 180 ) are used to change the direction of pipe flow. Tees provide a connection to a line perpendicular to the mainline pipe. For connecting a smaller pipeline to a mainline, a weldolet is welded to the mainline and the smaller pipeline is then welded to the weldolet. Threadolets allow threaded insertion. Reducers and expanders are used to join pipelines of different diameters. Caps are used to terminate a section of pipeline. Like fittings, flanges come in various configurations including weld neck, slip on, raised-face, flat faced, ring joint, and blind. Flanges are welded to the pipe and bolted to a valve. Valves control the flow inside the pipe. Some commonly used valves include gate valves, ball valves, plug valves, check valves, globe valves, and pressure relief valves. The presence of parallel pipelines is called looping. Looping is normally added to accommodate higher flow rates and to increase capacity. Thermal fluctuations change pipeline length. Expansion joints are used when the magnitude of such fluctuation is high. The expansion joint enables a pipeline to accommodate thermal cycles without losing integrity. When expansion joints are not practical then pipe loops are constructed to accommodate thermal cycles. Manifolds are used either to disperse or collect flows. They can be characterized as dividing, combining, reverse, or parallel depending on their functions (Figure 2.17).41 An ideal manifold transmits flow at approximately the same rate through all branches. Devices mounted onto valves to operate them are called actuators. They can be manual, electric (use electric motors), pneumatic (driven by compressed air), or hydraulic (driven by hydraulic oil).

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DIVIDING FLOW

COMBINING FLOW

REVERSE FLOW

PARALLEL FLOW

FIGURE 2.17 Schematic Diagram of Manifolds.41 Reproduced with permission from Taylor & Francis.

Volumes of oil and gas transported through a pipeline are measured using meters. There are two types of meters: direct volume meters or interference meters. Direct volume meters measure the volume by separating the flow stream into discrete volumetric segments. Interference meters determine the volume by measuring a particular property and correlating the property to the volume. In both types of meters, the measurements are corrected to standard pressure and temperature conditions. A meterfactor is used to correct the difference between the volume measured by the meter and the actual volume. This correction is normally determined using provers. Some typical meters used in the oil and gas industry include positive displacement meters, turbine meters, orifice meters, ultrasonic meters, and Coriolis meters. Provers are used to calibrate meters and to determine the meter-factors. Provers are devices with a fixed, known volume. A known volume of fluid is passed through the meters to the provers. By comparing the volume reported by the meters to the volume actually collected in the provers the accuracy of the meter is established and the meter-factor is estimated. There are two types of provers: pipe provers and master provers. Pressure and temperature gauges are used to measure the pressure and temperature respectively. Several materials are used to construct various pipeline accessories. The majority of accessories are constructed from carbon or low-alloy steel. Depending on the severity of the environment, the accessories may be constructed from carbon steel clad with CRA, or CRAs including stainless steels, bronzes, nickel alloys, and titanium alloys. The accessories should be constructed from materials

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89

similar to pipe materials in terms of their chemical, mechanical, and heat-treatment properties, otherwise the locations where these accessories are present may be susceptible to galvanic corrosion (see section 5.4). For this reason the accessories are constructed using a nobler metal than the material of construction (see section 5.2). Standards providing guidelines for the selection of accessories include: • • • • • • • • • • • • • • • • • • • • • • • • • •

ASME B16, ‘Standards for Pipes and Fittings’ API 6A, ‘Specification for Gate Valves’ API 6D, ‘Specification for Pipeline Valves’ ASTM A381, ‘Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High Pressure Transmission Systems’ ASTM A694, ‘Standard Specification for Carbon and Alloy Steel Forgings for Pipe Flanges, Fittings, Valves, and Parts for High Pressure Transmission Service’ ASTM A707, ‘Standard Specification for Forged Carbon and Alloy Steel Flanges for Low Temperature Service’ Manufacturers Standardization Society (MSS) SP6, ‘Standard Finishes for Contact Faces of Pipe Flanges and Connecting-End Flanges of Valves and Fittings’ MSS SP25, ‘Standard Marking Systems for Valves, Fittings, Flanges and Unions’ MSS SP42, ‘Corrosion Resistant Gate, Globe, Angle and Check Valves with Flanged and Butt Weld Ends’ MSS SP43, ‘Wrought and Fabricated Butt-Welding Fittings for Low Pressure, Corrosion Resistant Applications’ MSS SP44, ‘Steel Pipeline Flanges’ MSS SP53, ‘Quality Standard for Steel Castings and Forgings for Valves, Flanges and Fittings and Other Piping Components – Magnetic Particle Exam Method’ MSS SP54, ‘Quality Standard for Steel Castings for Valves, Flanges, and Fittings and Other Piping Components – Radiographic Examination Method’ MSS SP55, ‘Quality Standard for Steel Castings for Valves, Flanges, Fittings, and Other Piping Components – Visual Method for Evaluation of Surface Irregularities’ MSS SP58, ‘Pipe Hangers and Supports – Materials, Design, Manufacture, Selection, Application, and Installation’ MSS SP60, ‘Connecting Flange Joint between Tapping Sleeves and Tapping Valves’ MSS SP61, ‘Pressure Testing of Valves’ MSS SP69, ‘Pipe Hangers and Supports – Selection and Application’ MSS SP75, ‘Specification for High-Test, Wrought, Butt-Welding Fittings’ MSS SP86, ‘Guidelines for Metric Data in Standards for Valves, Flanges, Fittings, and Actuators’ MSS SP88, ‘Diaphragm Valves’ MSS SP89, ‘Pipe Hangers and Supports – Fabrication and Installation Practices’ MSS SP90, ‘Guidelines on Terminology for Pipe Hangers and Supports’ MSS SP92, ‘MSS Valve User Guide’ MSS SP93, ‘Quality Standard for Steel Castings and Forgings for Valves, Flanges, Fittings, and Other Piping Components – Liquid Penetrant Examination Method’ MSS SP94, ‘Standard for Ferritic and Martensitic Steel Castings for Valves, Flanges, Fittings, and Other Piping Components – Ultrasonic Examination Method’

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MSS SP102, ‘Multi-Turn Valve Actuator Attachment – Flange and Driving Component Dimensions and Performance Characteristics’ MSS SP114, ‘Corrosion Resistant Pipe Fittings Threaded and Socket Welding Class 150 and 1000’ MSS SP115, ‘Excess Flow Valves, 1 1/4 NPS and Smaller, for Natural Gas Service’ MSS SP118, ‘Compact Steel Globe & Check Valves – Flanged, Flangeless, Threaded & Welding Ends (Chemical & Petroleum Refinery Service)’

2.25 Oil tankers A ship transporting oil across oceans is called an oil tanker or petroleum tanker. There are two types of oil tankers: crude tankers and product tankers. Crude tankers transport unrefined crude oil from the production fields to the refineries, and product tankers transport refined products from refineries to consumers. Crude tankers are normally larger than product tankers and they typically travel longer distances. The size of an oil tanker – normally measured in terms of deadweight – may range from 1,000 to 500,000 metric tons. Tankers transport approximately 2 billion metric tons of oil every year and a single tanker voyage may take as long as 70 days. The technology of transporting oil in tankers has evolved along with the oil industry. Originally boats and barges were used to transport oil in wooden barrels. There were several problems with this mode of transportation, including the weight and the cost of the barrel, and frequent leakages. As a consequence of initial failures (see section 1.5), the oil tanker design was changed drastically. Instead of one or two large oil holds, several holds were included. These holds were further divided into ports and sections by a longitudinal bulkhead. Earlier designs may have caused the ship to capsize due to oil sloshing from side to side. This approach of dividing the ship’s storage space into smaller tanks (Figure 2.18)42 eliminated sloshing of oil and is used universally today. A major component of a tanker is the hull or the outer structure. A tanker with a single outer shell between the product and the ocean is known as single hulled ship. A tanker with an extra space

FIGURE 2.18 Schematic Diagram of Oil Tanker (Side View).42

2.26 Liquid natural gas (LNG) transportation

91

between the hull and the storage tanks is known as double-hulled. Oil tankers (over 5,000 tons deadweight) are built with double hulls. A hybrid tanker has double-bottom and double-sided design which combines aspects of both single and double-hull designs. Another important part of the tanker design is the design of the inert gas system. Hydrocarbon vapors are explosive when mixed with air in certain concentrations. The inert gas system is designed to create an atmosphere inside the tanks in which the hydrocarbon oil vapors cannot burn. As the oil in the tank is pumped out it is filled with inert gas until it is refilled with oil. Inert gas systems deliver air with oxygen concentrations below 5% by volume. Carbon steel is extensively used to build oil tankers. However, other materials including glass reinforced polymer, thermoplastics, polyethylene and fiberglass materials are also increasingly used for fabricating certain components of tankers. Corrosion may occur at the bottom of the oil tankers if water and sediments are allowed to accumulate. To control corrosion the water may be periodically drained and the internal surface cleaned – typically after each voyage. In addition, the internal surface of oil tankers may be coated. The space within the double-hull is filled with seawater to increase weight. Sediment buildup, leading to corrosion, may occur if the water used to fill the tanks is not treated properly. In addition, the surfaces of the tankers are protected by both protective coating and cathodic protection. The corrosion inside the ballast tanks may occur in locations where the coating has cracked and where the CP cannot be effectively applied. Such cracking may occur in areas such as sharp angles, welds, transitions between structural, frames, brackets, toes and similar connections, ends of spans and connections between longitudinal and web frames. The corrosion rate of double-hulled tankers is higher than that of single hulled tanks. Typically, repair and replacement of steel are performed after 15 years in single hulled tankers but in doublehulled tankers the replacement is performed after 5 years. The higher frequency of replacement is due to the use of thinner high strength steels as well as due to higher heat retention in the double-hulled tankers. In certain parts of the world, the oil is pumped at higher temperatures into the tankers. The heat from the hot oil is quickly disseminated by the ocean water in the single hulled tankers, but the double-hull structure acts as insulator, retaining the heat for a longer period. The outer surface of the tankers is susceptible to localized corrosion, splash zone corrosion, and fouling. For this reason, the outer surface is protected by coatings. The outer surface of the tankers immersed in ocean water is protected by a combination of coating and CP.

2.26 Liquid natural gas (LNG) transportation Liquid natural gas (LNG) is natural gas in the liquid state. LNG typically consists of 90% methane and 10% of other hydrocarbons (ethane, propane, butane, and some heavier alkanes). LNG consisting of 100% methane may also be produced. Natural gas turns into a liquid at 260 F ( 162 C). In the liquid state, the volume of natural gas is reduced 600-fold, therefore transporting natural gas in the liquid form is economical. The LNG industry has four distinct entities: LNG trains, LNG storage tanks, LNG carriers, and LNG regasification plants. A LNG train is a facility where natural gas is purified and liquefied. A typical LNG train consists of purification facilities, compression area, propane condenser area, ethane condenser area, and methane condenser area. The natural gases are first treated to remove dust, helium, water, H2S, CO2, and other

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heavy hydrocarbons, are then compressed and cooled to produce LNG. In the extraction facilities, internal corrosion may occur due to the presence of acid gases and water. Once liquefied, the LNG is stored in tanks. The LNG tanks are typically the full containment type storage facilities. The tanks have double walls – a reinforced concrete outer wall and a high nickel steel inner wall, with an insulator between them. Large tanks have low aspect ratio (height to width), are cylindrical in shape with a domed roof, and operate at low pressure (typically less than 50 kPa [7 psig]). Smaller tanks may be horizontal or vertical in shape and operate at a higher pressure 50 to 1,700 kPa (7 to 250 psig). Smaller tanks are insulated by the creation of vacuum around their wall. The common characteristic of LNG tankers is the ability to operate at temperatures as low as 256 to 261 F ( 160 to 163 C) LNG tankers have double containers, with the inner container filled with LNG and the outer container filled with insulation materials. The inner container is constructed from a steel or nickel alloy specially designed to operate at 160 C, and the outer insulating container may be 3 ft (0.9 meter) thick concrete. LNG tankers are increasingly being constructed using a membrane structure. The impermeable membrane is constructed using nickel, special steel, stainless steel, or invar metal (nickel-iron alloy). The basic requirements of the materials are to provide insulation for the tanks and to withstand the temperature of 160 C. A stainless steel membrane with waffles can absorb thermal contraction when the tank is cooled, whereas invar metal has no such thermal contraction. In the latter case, insulation is provided by other materials, e.g., plywood boxes filled with perlite. The membrane structure requires a smaller void space between the cargo tank and the ballast tank. The membrane types of tanks are robust and resist sloshing forces. Because the LNG tankers operate at very low temperatures corrosion is not an issue, but the materials need to be able to withstand these low temperatures. In spite of the insulation, inevitably a small portion of LNG will vaporize. As the vapor boils off, the heat from the phase change cools the remaining liquid. A small amount of vaporization is sufficient to maintain the temperature and this process is known as auto-refrigeration. Depending on the efficiency of the insulation, 0.1 to 0.25% of LNG may be converted into gas per day. The vaporized gas is traditionally used as fuel in the LNG carriers. LNG carriers are ships (Figure 2.19)43 transporting LNG storage tanks. Currently there are more than 200 LNG carriers sized between 750,000 and 880,000 barrel (w120,000 and 140,000 m3). LNG regasification is a simpler process than liquefaction. In the LNG regasification facilities, the LNG is pumped out of the LNG carriers and is warmed until it returns to the gaseous state. Standards providing guidelines for the construction and operation of LNG facilities include: • • •

National Fire Protection Associations (NFPA) 59A ‘Standard for the Protection, Storage, and Handling of LNG’ US Federal Regulation, 49 Code Part 193, ‘LNG Facilities’ US Coast Guard (33 code of Federal Regulations, Parts 127 and 165), ‘Waterfront Facilities and LNG Tanker’

2.27 Transportation by railcars Crude oil may be transported in special tanks placed in railcars in locations where construction of pipelines is not economical, and in locations where the railway network is relatively well established.

2.29 Gas storage

93

FIGURE 2.19 Schematic Diagram of LNG Tanker.43

The tankers used to transport oil are constructed using carbon steel. The corrosion characteristics of the tanks are similar to those discussed in lease tanks (see section 2.18). However corrosion control practices such as application of coatings and other control measures are not implemented. The relatively low probability of corrosion, shorter duration of transportation, relative easiness of cleaning and inspecting the tanks, and costs do not justify elaborate corrosion control measures.

2.28 Transportation by trucks Crude oil is transported in trucks when construction of pipelines is not economical, when crude oil is to be transported only over shorter distance, and when the volume of materials transported is small. The volume of crude oil or natural gas transported in trucks is relatively small. The tankers used are constructed using carbon steel. The corrosion characteristics are similar to those discussed for rail cars (see section 2.27).

2.29 Gas storage Natural gas may be temporarily removed from the transmission pipeline system and stored, and then later re-injected into the pipeline system. Natural gas is stored for several reasons. The gas is produced

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at locations far away from the consumers, so the gas is transported and stored in facilities that are located near the consumers. Demand for natural gas is usually higher during the winter, partly because it is used for heat in residential and commercial buildings. The excess natural gas is stored during the summer months to meet the increased demand of the winter months. Natural gas is also stored as insurance against any unforeseen accidents, natural disasters, or other occurrences that may affect its production or delivery. Natural gas is sometimes stored for commercial reasons. The gas is stored when the prices are low and withdrawn when prices are high. Natural gases are stored in depleted gas reservoirs, in underground salt caverns and, in the liquid form (LNG – see section 2.26), in aboveground tanks. The underground storage facilities are not constructed using metals and hence corrosion is not an issue. However the pipes for injecting the natural gas into the storage facilities and the pipes for retrieving gas from the storage facilities are constructed from carbon steel. They are susceptible to corrosion in a similar way to downhole tubulars (see section 2.4). When the natural gas stored in the salt cavern is retrieved, its corrosivity may increase due to presence of salt water. Therefore it should be purified and dehydrated.

2.30 Oil storage tanks Oil storage tanks may be present in many locations for different reasons. They function as staging areas to collect crude oils from various production fields and to deliver them into pipelines or tankers (see section 2.18). Oil storage tanks may be present at locations close to refineries. They collect crude oils from the transportation sectors (e.g., oil transmission pipelines, tankers, rail cars, and trucks). Storage tanks are also present immediately after the refinery to store different refined products. The functionality and operating principles of all oil storage tanks are similar. Tanks are built in groups – commonly known as tank farms. They can be as high as 46 feet (14 m) and as wide as 328 feet (100 m). The tank size depends on batch arrival, demand for refined products, cycle-time, safety-stock, tank-bottom, and safe-fill allowance. Batch arrival is the frequency at which particular crude arrives. Demand for refined products varies seasonally; for example, gasoline demand is typically higher in the summer, whereas heating fuel demand is typically higher in the winter. Cycletime is the time between delivery of batches of a particular product. Tank-bottom is the volume of oil in the bottom of the tank that cannot be accessed. Safe-fill allowance is the safety factor to keep the tank from overflowing. The roofs of the tanks may be fixed or floating. Fixed roof tanks can be pressurized. Floating roof tanks are operated at atmospheric pressure. Floating roofs provide minimum void between the surface of oil and the roof and are designed to provide a good seal between the periphery of the floating roof and the tank shell. This arrangement minimizes oxygen contamination. In certain designs, a combination of fixed roof with internal floating-roof is used, e.g., in areas of heavy snowfall or rain to prevent the accumulation of snow or water on the floating roof. Most storage tanks are fabricated using carbon steel. Table 2.19 presents typical materials of construction of oil storage tanks, and standards providing guidelines for constructing the tanks.44 Special attention is paid to constructing and operating tanks used for storing sour crudes. These include inspection of locations for potential iron sulfide deposition; closing of all openings to prevent H2S gas leaks; and installation of gauges at the bottom of the tanks to collect samples for analysis. Aluminum tanks may be used to store sour crude.

Table 2.19 Materials for Constructing Oil Storage Tanks44 Tank Type

Construction Material

Specification

Size (Typical)

Other Characteristics

Bolted steel tank

Steel with • Painting • Galvanized coating • Polymeric coating Heavier steel

API 12B

100 to 10,000 bbl

• Easily dismountable • Construction is easy

API 12F BS 2654 API 620

90 to 500 bbl

• Pressure up to 16 oz

Welded steel tank Flat-sided tanks

Heavy gauge steel

API 12D

500 to 10,000 bbl

Field e welded

Heavy gauge steel

API 650

150,000 bbl

2.30 Oil storage tanks

Field e welded

• Atmospheric pressure operation • Useful when space is limited • Flat-sided tanks • Provides large storage capacities in a single unit • Standard tank for large storage of oil and petroleum products

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Atmospheric corrosion

Vent Vapour phase Vapour phase corrosion Crevice corrosion

Interface corrosion

Inside bottom corrosion

Oil phase

Aqueous phase

Tank bottom corrosion

FIGURE 2.20 Types of Internal and External Corrosion Occurring in an Aboveground Tank.45

Figure 2.20 presents types of corrosion occurring in above ground tanks.45 More than 65% of tank failures are associated with corrosion. In general, the incidences of external corrosion are higher than those of internal corrosion. The most susceptible part of the external surface is the bottom of the tank. Most external tank surfaces are coated. External coating protects the surface from corrosion and, in the above ground areas, provides an aesthetic look. The areas below ground may further be protected with CP. Internal corrosion occurs due to the contaminants in the crude oil settling at the bottom of the tank where water also accumulates. Some tanks have cone-bottoms to drain water, in order to prevent corrosion. Some metallic tanks are internally coated, typically with coal tar, epoxy resin, rubber lining, or they are galvanized (zinc coating). The internal coating protects the surface of the tank from corrosion and protects the oil from contamination. Coatings that are immersed in liquids are often backed with CP. Vapor phase corrosion may occur in aboveground tanks in the areas above the stored product. Depending on the temperature gradient and on materials of construction and storage, general, crevice, and pitting corrosion may occur. The interface between liquid and vapor phases is susceptible to accelerated corrosion due to the oxygen or moisture concentration gradient. Non-metallic tanks are frequently used to store smaller amounts of crude oil, typically up to 5.7 m3 (15,000 gal). The non-metallic materials most commonly used include molded polymers reinforced with fiberglass and high-density polyethylene (HDPE). HDPE can be used up to 122 F (50 C)

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97

and fiberglass reinforced polymer (vinyl ester or epoxy) tanks can be used between 50 and 200 C. At temperatures above 392 F (200 C) non-metallic tanks cannot be used. Non-metallic storage tanks may undergo cracking or may develop pinholes. Before non-metallic tanks are chosen to store crude oil, their compatibility to the ingredients should be evaluated. For example, fiberglass tanks are not suitable for storing crude oil with methanol or ethanol. Standards providing guidelines for constructing and operating tanks include: • • • • • • • • • •

API 12B, ‘Specification for Bolted Tanks for Storage of Production Liquids’ API 2000, ‘Venting Atmospheric and Low Pressure Storage Tanks’ API 12D, ‘Specification for Field-Welded Tanks for Storage of Production Liquids’ API 620, ‘Recommended Rules for Design and Construction of Large, Welded Low Pressure Storage Tanks’ API 650, ‘Welded Steel Tanks for Crude Storage’ API 2610, ‘Design, Construction, Operation, and Maintenance of Terminal and Tank Facilities’ API 2003, ‘Protection against Ignitions Arising out of Static, Lightning, and Stray Currents’ API 2015, ‘Safe Entry and Cleaning Petroleum Storage Tanks’ API 653, ‘Tank Inspection, Repair, Alteration, and Reconstruction’ BS 2654, ‘Welded Steel Welded Storage Tanks for the Petroleum Industry’

2.31 Refineries For most of the 19th century, crude oils were refined by burning them in a pit to remove all light hydrocarbons and to produce materials that were used for heating, lighting, and lubricant purposes. The discovery of internal combustion engines requiring gasoline, however, changed forever the profile and purpose of petroleum refining. Modern refineries are very sophisticated and efficient. Crude oils from the transmission (midstream) pipelines are separated and refined in the refineries into various products. The three main outputs of modern refineries are gasoline, diesel, and furnace oil. Oil refineries are typically large sprawling industrial complexes with extensive piping running throughout, carrying streams of fluids between large processing units. The complexity of refineries depends on the type of crude oil available and the type products required. Oil refineries typically process from a thousand to several hundred thousand barrels of crude oil per day. Because of their high capacity, many of the units are operated continuously. This high capacity makes process optimization and advanced process control very desirable. Crude oil can be used in many different ways because it contains hydrocarbons of varying molecular masses, forms, and lengths. Refining expensive crude oils (lighter, sweet) requires fewer processes in the refineries; whereas refining cheaper crude oils (heavier, sour) requires more processes. The lower the API gravity of a crude oil, the lower its value to a refiner because it requires more processing and yields a larger percentage of lower-valued byproducts. With growing oilsands production and the declining production of conventional light sweet crudes, refineries have had to make several modifications. Alternatively some processes are moved upstream (see section 2.17 – upgraders) to pre-process the crudes so that they can be refined in the existing refineries.

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100

80

60 Percent

Residue

Cat feed

Distillate

Gasoline

C3/C4

40

20

0 Condensate (42)

Light Low S (39)

Synthetic (32)

Light High S (31) Heavy High S (27)

Very Heavy (21)

Crude Oil Type (API Gravity)

FIGURE 2.21 Comparison of Refinery Yields Depending on the Type of Crude Oils.46

FIGURE 2.22 Comparison of Refined Products for the Same Input Crude Oils as a Function of Refinery Type.47

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Figure 2.21 illustrates the product yield for six typical types of crude oil processed in Canada.46 The main products obtained from a simple refinery may be grouped into: gasoline, propane and butane, cat-feed (a partially processed material that requires further refining to make usable products), distillate (including diesel oil and furnace oil), and residual fuel (for producing heavy fuel oil and asphalt). Thus the type of crude oil used as feedstock influences the types of refined products obtained. Figure 2.22, on the other hand, illustrates that by changing the configuration of the refinery, different products can be obtained using the same crude oil as the feedstock.47 The number and nature of the process units in a refinery determine its complexity index. In general, refineries are classified into simple refinery consisting of crude distillation, catalytic reforming and distillate hydrotreating units; complex refinery consisting of catalytic cracker, alkyl plant and gas processing units, in addition to the simple refinery units; and very complex refinery consisting of a coker, in addition to the complex refinery units. Figure 2.23 presents a schematic diagram of a complex refinery.

Gas

Fuel gases

Polymeriztion feed (9) Crude oil (0)

GAS PLANT

GAS SEPARATION

POLYMERIZATION Alkylation feed (11)

HYDRODESULFURDESALTING

Iso-naphtah (14)

CATALYTIC ISOMERIZATION

Lt SR naphtha (3)

Light SR naphtha (3) Heavy SR naphtha (4) ATMOSPHERIC DISTILLATION

HYDRODESULFURIZATION/TREATING

Reformate (15)

CATALYTIC REFORMING

SR Middle distillate (6)

CATALYTIC HYDROCRACKING

SR mid distillate (6) HDS mid distillate (6A)

Lt vacuum distillate (19)

Kerosene Solvents Distillate fuel oils Diesel fuel oils

Hvy vacuum distillate (20)

Hvy vacuum distillate (20)

Hvy cat cracked distillate (26)

Cat cracked clarified oil (27)

Lt thermal cracked distillate (30)(Gas oil) SOLVENT DEASPHALTING

COKING

VISBREAKING

Asphalt

SOLVENT EXTRACTION

Thermally cracked residue (31)

RESIDUAL TREATING AND BLENDING

Residual fuel oils

Vacuum residue (21) Atmospheric tower residue (8)

HYDROTREATING

Courtesy of Lube feedstock (20) OSHA www.osha-slc.gov

Jet fuels DISTILLATE SWEETENING TREATING AND BLENDING

Lt cat cracked distillate (24) CATALYTIC CRACKING

Vacuum tower residue (21)

Solvents

SR kerosene (5)

SR Gas oil (7)

Atmospheric tower residue (8)

Automotive gasoline

HDS hvy naphtha (4A) Hydrodesulfurization/Treating

VACUUM DISTILLATION

GASOLINE (NAPHTHA) SWEETENING, TREATING AND BLENDING

Lt hydrocracked naphtha (18) Lt cat cracked naphtha (22)

SR Kerosene (5)

Desalted crude oil (1)

Aviation gasoline

Alkylate (13)

ALKYLATION

Light crude oil distillate (2)

Liquified petroleum gas (LPG)

Polymeriztion naphtha (10) n-Butane (12)

Raffinate (3)

SOLVENT DEWAXING

Dewaxed oil (Raffinate) Dcoiled wax

HYDROTREATING AND BLENDING

Lubricants Greases Waxes

FIGURE 2.23 Schematic Diagram of a Typical Complex Refinery.48 Reproduced with permission from Occupational Safety & Health Administration.

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Table 2.20 Typical Piping and Instrumentation Diagram (P&ID) of Refineries49 P&ID Category

P&ID Sub-Category

Description

System

Process

Shows all process equipment, piping and controls. This drawing describes reaction type, purification, materials handling, separation, and other unit operations. Shows utility systems such as boilers, cooling towers, heat-transfer units, refrigeration, and compressors. Shows pollution-control processes such as scrubbing, incineration, and wastewater treatment plants. Shows how steam, cooling water, and other utilities are distributed. Shows the depressurizing and safety-relief systems, piping network from relieving devices through blowdown drums, gas holders to vents, stacks, and other destinations. Lists chemicals handled in the utilities. Shows compressor lubrication and cooling systems, hydraulic systems, pump seals, and other auxiliaries related to major equipment.

Utility-generation Environmental Distribution

Utility-distribution Safety-system

Auxiliary-system

Chemicals-distribution Auxiliary-system

In order to manage the complex structure, Piping and Instrumentation Diagrams (P&ID) are developed to design, construct, and operate the refineries. Tables 2.20 and 2.21 respectively present different sub-categories included in the P&ID and the type of information available in a P&ID.49 Carbon steel is the most common material used in the refinery. It is relatively inexpensive and has a good track record. The process streams containing H2S can cause corrosion. Refinery equipment handling these streams is constructed from steel having an increasing Cr content. When Cr steels (with Cr content typically up to 9%) do not resist corrosion in refinery streams, they may be coated with metallic coatings. When Cr-steels with metallic coating do not resist corrosion, the components are constructed using CRAs such as stainless steels. Stainless steels have been successful at most operating temperatures of petroleum refining. Before a material is selected for constructing a refinery component, its suitability under the relevant operating conditions is evaluated. Standards providing guidelines for selecting materials for refineries include: • • • •

ASME B31, ‘Standards of Pressure Piping’ API 942, ‘Controlling Weld Hardness of Carbon Steel Refinery Equipment to Prevent Environmental Cracking’ NACE RP 0472, ‘Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments’ NACE MRO175/ISO 15156: Petroleum and Natural Gas Industries – Materials for Use in H2S-containing Environments in Oil and Gas Productions (Parts 1, 2, and 3)

Most external surfaces of refineries operate at elevated temperatures and are protected with insulation to retain heat. Corrosion under insulation (CUI) (see section 5.20) and SCC under insulation may occur if moisture permeates through the insulator and reaches the metal surface. For this reason, the

2.31 Refineries

Table 2.21 Typical Information in a P&ID of a Refinery49 Major Components

Contents

Equipment

Spares Drivers Numbers Names Materials of construction Sizes Types Motor horse power Packaged-equivalent details Vendor-drawing details Piping specifications Materials of construction Sizes Numbers Tie-in designations Detailed design Functional designation Panel vs. local Numbers Detailed design Bypasses Equipment drains, vents Instrument block valves Control valve sizes Nonline-size valve sizes Detailed design Relief valves Line sizes Valve sizes Detailed design Detailed design Numbers Connections Controls Detailed design Vendor input Sloped lines Critical elevations Barometric legs Detailed design Line designation tables Emissions/discharge summary Utility summary Specialty-items summary Tie-in index Instrument data sheets Interlock description Steam-trap summary

Process lines

Instrumentation

Valves

Safety systems

Insulation/tracing Piping specialties Utilities

Special notations

Related documents

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insulation should be properly selected, applied, and maintained. In addition, some external surfaces may be further protected with organic coatings (typically epoxy and silicone). Standards providing guidelines for selecting insulation to avoid CUI include: • •

ASTM C795, ‘Standard Specification for Thermal Insulation for Use in Contact with Austenitic Stainless Steel’ ASTM G189, ‘Standard Guide for Laboratory Simulation of Corrosion under Insulation’

The following sections describe characteristics of various refinery components and their corrosion characteristics.

2.31.1 Desalter unit Desalting is usually the first process in crude oil refining. A desalter unit is normally installed when crude oil containing more than 75 ppm of salt is processed. However, in some refineries a desalting unit is installed irrespective of the salt content of the crude oil. The main purpose of the desalter unit is to reduce the salt content of the crude oil down to 4 ppm or less. The salts present in crude oils include chlorides of calcium, sodium, magnesium and arsenic. If these salts are not removed, they hydrolyze at higher temperatures to form corrosive hydrochloric acid; deposit and foul heat exchangers; reduce vaporization of water and thereby reduce heat capacity of crudes; and poison catalysts. The salts preferably dissolve in water over crude oil. Therefore the crude oil is thoroughly mixed with water, heated to 248 to 302 F (120 to 150 C) and feed into the desalting unit. The salts in the crude oil dissolve in the water producing hydrochloric acid. Water and oil may form a stable emulsion; in such situations de-emulsifiers are added or an electric field is applied to separate the emulsion. The hydrochloric acid is neutralized with caustic soda (NaOH) to produce NaCl which is removed from the desalter unit as bottom residue. The desalted crude oil is sent to the ADU (see section 2.31.2). Desalter units are normally constructed using carbon steel. Because of the presence of water with high salt content as well as sediments and silts, the bottom of the desalter suffers localized corrosion. The bottom of the desalter unit is therefore either reinforced with a cement lining or constructed with thicker carbon steel, i.e., constructed with increased corrosion allowance.

2.31.2 Atmospheric distillation unit (ADU) Crude oil is a mixture of hydrocarbons with different boiling points. Distillation is a common process to separate them into various fractions. The principle behind the distillation is as follows. When a liquid is heated to its boiling range, it vaporizes. As a vapor is less dense (lighter) than liquid, it rises to the top. When the vapor is passed through a condenser, it cools and turns back into the liquid state. Figure 2.24 presents typical processes in an atmospheric distilling unit.50 A pump transports the crude oil from the storage tank or from a desalter unit to a furnace (where it is heated to temperatures up to 750 F (399 C) and then to the distilling column. The distilling column has several trays with perforations. The perforations permit the vapors to rise through the column. The lighter hydrocarbons, with lower boiling points, rise as vapors to the top of the column, whereas heavier hydrocarbons with higher boiling points collect as liquids at the bottom of the column. The perforations in the trays are fitted with bubble caps, which force the vapor coming up through the trays to bubble through the liquid collected in the trays. Heat is transferred from the vapor to the liquid during the bubbling, turning the

STABLIZER

ATMOSPHERIC DISTILLATION

VACUUM LUBE DISTILLATION

VACUUM FLASHER

TO VACUUM SYSTEM

TO VACUUM SYSTEM

GAS

GAS OIL NAPHTHA KEROSENE LPG

LT. DIESEL

LT. LUBE MED. LUBE HVY. LUBE

HVY. DIESEL CATALYTIC CRACKER FEED STABILIZED GASOLINE

ASPHALT PROPANE DEASPHALTER FEED

START

FIGURE 2.24 Schematic Diagram of Distillation Units.50 Reproduced with permission from NACE International.

2.31 Refineries

DESALTER

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hydrocarbon vapor into liquid. The lighter hydrocarbon vapors move to the upper tray where the process is repeated. The liquids collected in various trays are drawn out through the side-draws – with lighter products from the top columns and the heavier liquids from the lower columns. The products from the ADUs of refineries can be broadly divided into gas (sent to the gas separation unit), straight run light naphtha (sent to a gasoline blending unit), straight run heavy naphtha (sent to a hydrodesulfurization unit), straight run kerosene (sent to a distillate blending unit), straight run middle distillate (sent to CCUs), and straight run gas oil (sent to CCUs), and residue (sent to a VDU or to a residue blending unit). The materials used to construct an ADU depend on the type of crude oil and on the temperature of operation. For processing crude oils with a sulfur content lower than 0.2 wt % and up to an operating temperature of 550 F (288 C), carbon steel is used, and for processing crude oils with sulfur contents higher than 0.2 wt %, 5Cr-0.5 Mo steel is used up to 550 F (288 C) and 9 Cr-1 Mo steel is used above 550 F (288 C). The furnace tubes, pipes, and exchanger tubes are constructed from 5Cr-0.5 Mo alloy. In the refinery the temperatures are reported in terms of process temperature. The process temperature may be lower than the temperature experienced by the metal. For the same process temperature the corrosion rate of furnace tubes is higher than that of the piping because of the higher temperatures experienced by the furnace tubing metal surface. The higher corrosion rate in the furnace tubes is also due to the higher velocity, i.e., flow-accelerated corrosion. The materials used to construct overhead condensers depend on several factors, including the quality of cooling water, concentration of salts, presence of H2S, and ability to control process parameters (e.g., velocity and pH). The regions where water condenses are protected by liners; when using brackish water or salt water titanium is used; when the velocity of water can be controlled below 7.9 feet/s (2.4 m/s) and when ammonia is absent, brasses are used; in the presence of ammonium chloride, copper-nickel alloys are used (brasses may crack during downtime if ammonium chloride is present); and in the presence of H2S, stainless steels are used (copper-nickel alloys corrode in the presence of H2S). When welding dissimilar metals, filler materials are used to avoid galvanic corrosion. In addition, the welded area is overlaid or clad to avoid SSC in the presence of H2S. Materials used to construct heat exchangers are similar to those used to construct the columns. Typically 5 Cr-0.5 Mo steel or materials clad with 12-Cr are used. In designing the heat exchangers care is taken to avoid dead legs and crevices (see section 5.9). Pumps and valves are constructed with materials which are resistant to wear. Typically 12-Cr is used to construct pumps and valves. In the presence of naphthenic acid, the pumps and valves are constructed using stainless steel. Overhead corrosion due to the condensation of hydrochloric acid and naphthenic acid (see section 4.3.1c) and due to plugging caused by ammonium chloride are the major problems in ADUs. To a large extent, corrosion is controlled by proper material section. Further control is achieved by the addition of caustic solution, neutralizing agents (e.g., amines and ammonia), or corrosion inhibitors as well as by frequent inspection. Standards providing guidelines for inspecting the ADUs include: •

API 570, ‘Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems’

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2.31.3 Vacuum distillation unit (VDU) The temperature of the ADU does not exceed about 900 F (482 C), because above this temperature the hydrocarbons break down to smaller molecules. This breakdown is known as cracking. Although the cracking process is extensively used during upgrading and refining the crude, it is avoided during distillation. To avoid cracking during distillation, a vacuum is created in the VDU. The principle of vacuum distillation is as follows. When a liquid is heated it changes into a gas. The temperature required to transform from the liquid to the gaseous state depends on the pressure of air about it; if this is lower, a lower temperature is required. (It is for the same reason water boils at temperature below 212 F (100 C) at higher elevations [lower pressure]). Therefore in the VDUs a vacuum is created to distill the hydrocarbons without cracking them. The residue from the ADU is pumped into the VDU where the pressure has been lowered below atmospheric pressure. At reduced pressure, the lighter portions of the residue from the ADU vaporize without cracking. The other units of the VDU are similar to those in the ADU. The vacuum pump maintains the lower pressure and also draws out vapors of smaller hydrocarbons and water. The vapors at the top of the VDU are condensed into heavy and LGOs, kerosene, and naphtha. The residue from the VDU is used as feedstock in catalytic cracking, thermal cracker, hydrotreating, or coker units. Vacuum distillation columns are typically 14 meters (46 feet) in diameter and about 50 meters (164 feet) tall, and they process about 25,400 cubic meters of crude oils per day (160,000 barrels per day). The materials of construction and corrosion characteristics of VDU are similar to those of ADU (see section 2.31.2).

2.31.4 Hydrotreating unit Hydrotreating units (HTU) are used at various stages in refineries. Depending on which stream undergoes treatment, the hydrotreating unit can be identified as jet fuel hydrotreating, distillate hydrotreating, pyrolysis gas hydrotreating, catalytic feed hydrotreating, reformer feed hydrotreating, or residue hydrotreating units. The basic objective of all hydrotreating units is the same: to remove chemically bound sulfur compounds from hydrocarbons. Hence, the hydrotreating unit is also known as the hydrodesulphurization (HDS) unit or the hydroprocessing unit. The reasons for removing the sulfur compounds are many, including reducing SO2 emissions; to prevent the poisoning of metal catalysts (platinum and rhenium); and to meet sulfur limits in kerosene and diesel. In the HTU, the stream of hydrocarbons is mixed with hydrogen, heated to 500 to 800 F (260 to 427 C), pressurized up to 1,900 psi (13 MPa), and passed over a catalyst. Commonly used catalysts are cobalt and molybdenum oxides on alumina. Using ethanethiol (C2H5SH) as an example of sulfur compound present in the crude, the reaction taking place in the HTU can be written as: C2 H5 SH þ H2 / C2 H6 þ H2 S

(Eqn. 2.4)

During the hydrotreating process, the organic nitrogen compounds are also converted into ammonia and ammonium salts. The products from the hydrotreating unit are cooled using a series of heat exchangers and are then charged into a high pressure separator. Gas rich in H2S is removed from the top of the separator and hydrotreated (free of sulfur compounds) liquid hydrocarbon is drawn from the bottom.

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HTUs operating below 550 F (288 C) are constructed from C-0.5 Mo; 1 Cr-0.5 Mo; 2.25 Cr-1 Mo-V; and 3 Cr-1 Mo-V-Ti-B carbon steels; the carbon steels may be clad with stainless steels. HTUs operating above 550 F (288 C) in the presence of hydrogen and H2S are constructed from 5 Cr0.5 Mo or 12 Cr clad steel, or 18Cr-8Ni stainless steel. Standards providing guidelines for selecting materials include: • • • •

API 941, ‘Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants’ ASME Code Case 2098 ASME Code Case 2151 ASME Code Case 1961

Due to the presence of large amounts of hydrogen gas, H2S, sulfurous acid (H2SO3) and polythionic acid (H2SxO6) (formed by the reaction between iron sulfide, moisture, and air during the shutdown operation), the components of HTU may undergo hydrogen induced disbondment (HID) (also known as hydrogen flaking) (see section 5.18.6), HIC, SSC, and SCC. The coolers, where water from the HTU condenses, the steel may suffer general corrosion, pitting corrosion, and hydrogen blistering. The extent of corrosion depends on the concentration of hydrochloric acid, ammonia, and H2S in the condensing water. By diluting the water between the heat exchangers and the coolers, both corrosion and plugging can be controlled. Plugging by ammonium chloride and ammonium bisulfide is also an issue in high pressure air coolers. Addition of water to dilute ammonium salts and to maintain the flow regime in the annular region controls the plugging. However the water should be removed, to prevent corrosion in the equipment downstream. Standards providing guidelines for selecting materials for HTU include: •

NACE RP 170, ‘Recommended Practice on the Protection of Austenite Stainless Steel during Downtime’

2.31.5 Catalytic cracking unit (CCU) In a catalytic cracker, heavy gas oil is broken (cracked) into smaller hydrocarbons in the presence of a catalyst under high temperature and high pressure. The main objective of CCU is to convert the heavy oil into gasoline. The feedstock of the CCU is usually heavy gas oil from a VDU. During the cracking (breaking away) a range of smaller molecules including methane, olefins, aromatics, naphthenes, residue, and coke are formed. A typical CCU consists of four components: a reaction section, catalysts, regenerators, and a fractionating column (Figure 2.25).51 The reaction section consists of the heater and riser. The heater raises the temperature of the feedstock to 900–1000 F (482–538 C), mixes with catalyst, and pumps it into the reaction section. Due to the high temperature and the intimate contact with a catalyst, some cracking may happen in the riser. The reaction chamber may contain cyclones (mechanical devices that spin the mixture vigorously). The heavier catalysts and heavier hydrocarbons slide through the side of the reaction chamber, while smaller hydrocarbons exit through the top of the reaction chamber as vapors or as liquid droplets. Natural alumina-based clay and synthetic zeolytes are used as catalysts. Synthetic zeolytes are used increasingly because they possess fluidity (they swill around like a fluid). It is for this reason sometimes catalytic cracking process is called fluid catalytic cracking); large surface area (i.e., the particles

2.31 Refineries

CRACKED PRODUCTS

107

C4 & LIGHTER

CAT GASOLINE

DISENGAGING VESSEL CAT LGO

CO/CO2

FRACTIONATOR

CAT HGO

SPENT CATALYST

REGENERATOR

CYCLE OIL

RISER

FRESH CATALYST

FEED

FRESH FEED

STEAM

FIGURE 2.25 Schematic Diagram of Catalytic Cracking Unit.51 Reproduced with permission from PennWell Corporation.

have large number of pores); and selectivity (i.e., they can be synthesized with exact dimensions and mineral contents so that the catalytic reaction can be controlled). During cracking some hydrocarbons crack all the way to coke. When the catalyst surface is covered with coke, it loses its catalytic ability, i.e., the catalyst is considered to be spent. Spent catalyst is heated to 1100 F (593 C) in the regenerator unit and the regenerated catalyst is sent to the reaction section for reuse. The cracked products from the reaction chamber are sent to a fractionating column, where they are fractioned into gases, gasoline, LGO, heavy gas oil, and cycle oil. The products from CCU may include unsaturated hydrocarbons (such as ethylene, propylene, and butylene); on the other hand the products from distillation units (sections 2.31.2 and 2.31.3) are only saturated hydrocarbons. The cycle oil is fed back into the reaction chamber and other products are sent to gas plants for purification. CCUs are typically 25 to 30 feet (7.6 to 9.2 m) in diameter and 80 to 100 feet (24.5 to 30.5 m) high and are typically constructed using carbon steel of thickness 0.5 to 1 inch (12.5 to 25 mm). To protect

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the carbon steel surface from heat and from erosion-corrosion (caused by the motion of fluid catalyst), it is protected with a refractory lining (see section 7.9.3). The lining performs two functions: it acts as a thermal insulator and as an erosion resistant material. Smaller CCUs may be constructed without refractory linings, but their operating temperature is limited to 842 F (450 C). The components (e.g., piping between the units) of the CCU are constructed from CRAs and may be susceptible to pitting corrosion, SCC, and embrittlement. Corrosion is controlled by proper material selection and operation (e.g., SCC of stainless steel pipes during shutdown is avoided by purging it with nitrogen or ammonia gas).

2.31.6 Thermal cracking unit (TCU) In a TCU, the hydrocarbons are cracked (broken down) using high temperatures in the absence of catalyst. The TCUs consists of a furnace and reactor chambers. The furnace is heated to a temperature between 960 and 1020 F (515 and 549 C). The heated feedstock is charged into the reaction chamber, which is normally pressurized to about 100 psi (689 kPa) to enable cracking. The products from the reaction chamber are quenched to arrest the reaction. The TCUs produce products that are similar to those produced by the CCUs, and the products undergo similar treatment to those from CCUs. The construction materials and corrosion characteristics of TCUs are similar to those of CCUs.

2.31.7 Hydrocracking unit (HCU) Cracking carried out in the presence of hydrogen is known as hydrocracking. A hydrocacking unit (HCU) may also be known as a catalytic hydrocracking unit (CHU). HCUs are commonly used in countries where diesel and kerosene are in high demand, e.g., India. The HCU may have one or two or more reactors in which catalysts are laid in a fixed bed. Catalysts used in the HCU include platinum, rhenium, cobalt, molybdenum, nickel, titanium oxide, or alumina. The heavy gas oil from CCUs and TCUs is mixed with hydrogen, heated to 550 to 750 F (288 to 399 C), pressurized between 1,200 and 2,000 psi (8.2 and 14 MPa), and charged onto catalysts. The catalysts break (crack) the rings of larger molecules containing nitrogen and sulfur compounds. Hydrogen then combines with these compounds to produce H2S and NH3. These processes convert 40–50% of heavy oil into gasoline-type products. The products are then cooled and any remaining hydrogen is separated. The separated hydrogen is recycled into the first reactor. The products are fed into fractionating columns where they are separated into diesel, kerosene, LPG, gasoline, jet fuel, and gas oil. The residue from the fractionating column is heated and fed to the second reactor. The operating conditions of the second reactor are more severe than that of the first reactor. As a consequence even heavier compounds are cracked to produce gasoline-type products. From the materials selection perspective, the hydrocracker units are treated as HTUs. The major difference between them is their operating pressures. HCUs operate at higher pressures (up to 2,000 psi (14 MPa)) than HTUs. Carbon steel is used to construct HCUs operating below 550 F (288 C). Above 550 F (288 C), the carbon steel is clad with 5 Cr-0.5Mo steel or CRA (stainless steels), or 5 Cr-0.5Mo steel or CRAs (stainless steels) are used directly. The selection of an appropriate material depends on operating temperatures, the sulfur content of the hydrocarbons, and operating pressure. The presence of sulfur in

2.31 Refineries

109

various forms including aromatic mercaptans, aliphatic sulfides, disulphides, polysulfides, and H2S causes severe localized pitting corrosion.

2.31.8 Steam cracking unit (SCU) In the steam cracking process, saturated hydrocarbons are broken into smaller, often unsaturated, hydrocarbons. It is the principal industrial method for producing lighter alkenes (olefins) including ethene (or ethylene) and propene (propylene). In a steam cracking unit (SCU), gaseous or liquid hydrocarbons are mixed with steam and then heated in the absence of oxygen to 850 C for a very short time (milliseconds). Light hydrocarbons (ethane, LPGs, or light naphthenes) crack to produce ethylene, propylene, and butadiene whereas heavy hydrocarbons (e.g., heavy naphthas) crack to produce aromatic hydrocarbons and hydrocarbons suitable for inclusion in gasoline or fuel oil. Higher temperatures favor the production of ethene and benzene whereas lower temperatures produce higher amounts of propene, butene, and liquid products. The material of construction is primarily carbon steel which may be protected by refractive coatings. The components of a SCU are susceptible to high temperature corrosion.

2.31.9 Mercaptan oxidation unit (Merox) Crude oil may contain mercaptans, such as methyl mercaptan or methanethiol (CH3SH); ethyl mercaptan or ethanethiol (CH3CH2SH); and propyl mercaptan or propanethiol (CH3CH2CH2SH). In a mercaptan oxidation (Merox) unit, these mercaptans are removed from the crude oil in a two-step process. Using ethyl mercaptan as an example, the processes are presented in Eqns. 2.5 and 2.6: 2CH3 CH2 SH þ 2NaOH / 2NaSCH2 CH3 þ 2H2 O 4NaSCH2 CH3 þ O2 þ 2H2 O / 2CH3 CH2 SSCH2 CH3 þ 4NaOH

(Eqn. 2.5) (Eqn. 2.6)

The disulfide formed is water insoluble and is removed as a solid. The regenerated caustic solution is reused to continue extracting more mercaptans. The hydrocarbon entering the Merox unit must be free from H2S; otherwise this would react with the caustic solution, hence decreasing its ability to react with mercaptans. Therefore, the hydrocarbons entering the Merox unit are first ‘prewashed’ with aqueous caustic to remove H2S according to the following reaction: H2 S þ NaOH / NaSH þ H2 O

(Eqn. 2.7)

The Merox unit is typically constructed from carbon steel. It is susceptible to localized corrosion due to the presence of sulfur compounds.

2.31.10 Catalytic reforming unit (CRU) In the catalytic reforming process, hydrocarbons (e.g., naphtha) with low octane number are converted into hydrocarbons with high octane number (e.g., gasoline). The octane number is a measure of whether a gasoline will “knock” in an automobile engine. In the internal combustion process, the gasoline and air vapor are first injected into the cylinder of an automobile and compressed with a piston. Then a spark plug ignites the mixture. If the gasoline and air mixture self-ignites without the

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sparkplug triggering it, then the engine will knock; pushing the piston in the wrong direction. The tendency of a mixture to “knock” is represented by the octane number. Four commonly occurring catalytic reforming reactions are: 1. Dehydrogenation of naphthanes into aromatic compounds, e.g., conversion of methylcyclohexane (a naphthane) to toluene (an aromatic); 2. Dehydrogenation of paraffins into aromatic compounds, e.g., conversion of normal heptane to toluene; this process is also known as dehydrocyclization; 3. Isomerization of normal paraffins to isoparaffins, e.g., conversion of normal octane to 2,5-dimethylhexane; and 4. Hydrocracking of paraffins into smaller molecules, e.g., conversion of normal heptane into isopentane and ethane. The first two processes produce hydrogen, the third process does not lose or gain hydrogen; and the fourth process consumes hydrogen. Overall, hydrogen gas is produced during the catalytic reforming process. Liquid naphtha is pressurized (75 to 660 psi (517 to 4,550 kPa)), mixed with a stream of hydrogenrich gas, heated to temperatures of 923 to 968 F (495 to 520 C) and flowed through a catalyst bed. The catalysts commonly used are platinum, rhenium, alumina, silica, and palladium. The operating conditions of various catalysts are different; accordingly the pressure, temperature, and residence time are adjusted. These catalysts are susceptible to poisoning by sulfur and nitrogen compounds, so the liquid naphtha is pre-processed in the HTU to remove them. The CRU typically consists of three or more reactors. The dehydrogenation of naphthenes to aromatic compounds is endothermic, i.e., it absorbs heat; consequently the temperature decreases. Therefore the stream is reheated before it flows through the second reactor. The temperature decreases in the second reactor and again the stream is reheated before going through the third reactor. As the feedstock proceeds through the three reactors, the reaction rates decrease and the reactors therefore become larger. Usually three reactors are sufficient for catalytic reformation. The materials used for constructing CRUs should be resistant to hydrogen. Chromium and molybdenum containing carbon steels are commonly used. Because of the very high operating temperatures (in excess of 1000 F (540 C)), the catalytic reformer units are often protected with a refractory lining. The components of CRUs are constructed from CRAs including stainless steel, Alloy 600 and Alloy 625. Standards providing guidelines for selecting materials for CRUs include: •

API 941, ‘Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants’

Some commonly experienced failure modes in the CRUs include metal dusting, cracking or spalling of refractory liners, and localized pitting corrosion. The catalysts break down organic chlorides and nitrogen compounds in the crude oils to produce HCl and NH4Cl. Caustic may be added to neutralize these acids.

2.31.11 Visbreaker unit As the name suggests, this unit reduces the viscosity of hydrocarbons. The unit simply reduces the viscosity of the product by heating the feedstock in a furnace, and it does not use any other means such

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as a catalyst. This unit is normally located downstream of the VDU. Its material of construction is carbon steel, which may be protected with refractory liners. Corrosion in this unit may be caused by high temperature and spalling of refractory liners.

2.31.12 Coker The coker unit converts the residual oil from the VDU and ADU into hydrocarbon gases, naphtha, gas oils, and petroleum coke. Basically in this process, the long chain hydrocarbon molecules in the residual oil feed are thermally cracked into shorter chain molecules. There are three types of cokers: delayed coker, fluid coker and flexi-coker. The delayed coker is the most commonly used type. The residual oil from the VDU and ADU is rapidly heated to about 1,000 F (538 C) in the furnace and charged to the coke drum. The cracked lighter product rises to the top in the vapor form, where it is collected and sent to a fractionator. The naphtha from the coker is hydrotreated and reformed before being blended to form gasoline. The coker gas oil is mixed with gas oil from CCU to form fuel oil. The heavier product remains in the bottom of the coke drum and continues to crack until all hydrocarbons are cracked off, leaving only carbon behind as a solid residue. This is removed by high pressure water jet (at 2,000 psi(13.9 MPa)). The residual coke can either be fuel grade (high in sulfur and metals) or anode grade (low in sulfur and metals). The raw coke directly out of the coker is often referred to as green coke; i.e., unprocessed coke. This is further processed at 2,375 F (1,302 C) to produce anode coke which is mainly used in the aluminum and steel industry. Coke drums are typically installed in pairs so that coking and decoking take place alternatively, making the whole process continuous. The fluid coking process is similar to catalytic cracking in which a cyclone is used to separate the hydrocarbons from the coke. However the process is difficult to control. Fluid coking is principally used to produce fuels for steam generators. In a flexi-coking process, the coke is converted into carbon monoxide (CO) and mixed with ethane and other lighter hydrocarbon byproducts to produce low quality fuel gas for use in power plants. Coker drums are typically constructed from carbon steel with a nominal thickness of 1 inch (w25 mm). Most materials are clad with CRAs (stainless steel) to protect them from high temperature sulfur attack. The main failure mode of coker drums is thermal fatigue due to the large thermal cycling. Normally the coke that forms protects the coker surface, but in the absence of coke the cladding material may undergo sulfidation (see section 5.15b).

2.31.13 Gas plants Refinery gas plants are similar to the gas dehydration facilities (see section 2.14). In refineries two kinds of gases are processed: saturated gases and unsaturated gases. The gases produced in the ADU known as saturated gases; i.e., they mostly consist of alkanes and are typically processed in the gas plants in two steps. First a compression and phase separation unit pressurizes the gases, typically to 200 psi (1,379 kPa), when the volatile gases (NGLs) liquefy and separate out as liquids. The gases from the compression and phase separation unit are then introduced into an absorption unit. A hydrocarbon liquid, typically naphtha is introduced from the top of the absorption unit. Naphtha absorbs most of the propane, butane, and other lighter liquids from the gases. From the top of the absorption unit gases – mostly ethane and methane – are collected.

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The naphtha collected at the bottom of the absorption unit is further processed in the debutanizing (to separate butanes), depropanizing (to separate propane), and deisobutanizing (to separate butane and isobutane) units. These separating units are tall columns containing trays, chillers, and compressors. Separation of butane and isobutane is most difficult because their boiling points are close together. For this reason, the deisobutanizer is normally the tallest column in a gas plant. Heptane and octane are absorbed using hydrocarbons which are heavier than naphtha. This heavier hydrocarbon is commonly known as a sponge oil. The naphtha is then reused in the absorption tower. Gases produced in the CCU and other cracking units contain, in addition to saturated hydrocarbons, ethylene, propylene, and butylenes. Hence these gases are known as unsaturated gases. Ethylene is normally not separated from ethane. The gas mixture containing ethane and ethylene is used as refinery fuel. Propylene and butylene are separated from ethane and from each other in fractionating columns. Propylene and butylene are normally sent to the alkylation units for further processing. Gas plants are mostly constructed from carbon steels. Because of the relatively pure, dry nature of the gases, corrosion is not a major issue. However localized corrosion may take place when the gases are saturated with water, and when water is allowed to accumulate.

2.31.14 Alkylation unit The alkylation process converts isobutane into isopentane and isooctane by the addition of an alkyl group (e.g., a methyl or an ethyl group). The process of alkylation is carried out in the presence of acid catalysts, such as sulfuric acid or hydrofluoric acid at temperatures between 32 and 86 F (0 and 30 C). This unit may also be referred to as a sulfuric acid alkylation unit (SAAU) or a hydrofluoric alkylation unit (HFAU) – or simply an alkyl unit. Large volumes of sulfuric acid (H2SO4) are needed to carry out the alkylation process. For this reason a sulfuric acid production plant is operated by the side of the alkylation plant. In addition, facilities are needed to safely dispose of the spent acid. The required volume of hydrofluoric acid (HF) is much lower than that of sulfuric acid, but this acid is more hazardous. Most of the alkylation plants are constructed using carbon steel, as long as the concentration of sulfuric acid is above 80% and the velocity is less than 2 feet/s (0.6 m/s). At velocities higher than 2 feet/s (0.6 m/s), CRAs are used. The SAAU may undergo corrosion in the dead legs (the units are designed to avoid dead legs); corrosion and fouling in the overheads in the presence of wet SO2 (the effluents are treated to remove SO2); and hydrogen grooving (see section 5.18.7) (the liquid velocity is maintained above 1 feet/s (0.3 m/s) to avoid hydrogen grooving). The alkylation plant is primarily constructed using carbon steel when the concentration of acid is above 70%. The acid reboiler and the bottom of the acid regenerator are normally constructed from CRAs. Most of the corrosion of carbon steel occurs when the acid is diluted; therefore thoroughly drying the equipment after shutdown is critical in order to prevent corrosion. To facilitate drying, most equipment is slopped to facilitate draining of the acid. In addition hydrogen blistering and cracking may occur. Carbon steel may undergo galvanic corrosion (especially around welds area), crevice corrosion (in the presence of sockets and around welded areas) and hydrogen embrittlement and hydrogen blistering (especially if the HF contains more than 25 ppm of arsenic). The CRAs may undergo SCC in hydrofluoric acid in the presence of oxygen.

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Standards providing guidelines about acids used in alkylation units include: • •

NACE RP 0391, ‘Materials for Handling and Storage of Concentrated (90 to 100%) Sulfuric Acid at Ambient Temperature’ NACE 5A171, ‘Materials for Receiving, Handling, and Storing HF Acid’

2.31.15 Isomerization unit The CRU (see section 2.31.10) converts hydrocarbons with low octane rating to a high octane rating. An isomerization unit is additionally installed in the refineries that produce fuels that do not meet the octane number of gasoline. Conversion of normal hydrocarbons (i.e., straight chained) to isohydrocarbons (i.e., branched) increases their octane number; this process is carried out in the isomerization unit. Here, normal hydrocarbons are mixed with hydrogen and chloride, and the mixture is heated and charged into a reactor containing a platinum catalyst. Under the reaction conditions, normal butane isomerizes into isobutane; similarly normal pentane and normal hexane isomerize into isopentane and isohexane respectively. The products of the isomerization unit are either blended with gasoline or fed to an alkylation unit for further processing. The isomerization unit is mainly constructed from carbon steel. The presence of chloride and high temperatures may cause localized pitting corrosion.

2.31.16 Gas treating unit Acid gases (H2S and CO2) present in natural gases are removed in the gas treating unit. This process is similar to that described in section 2.14.

2.31.17 Water stripper Several refinery units produce water contaminated with H2S and other chemicals. This is collected and sent to a water stripper unit, where the water is purified. The most common contaminant removed is H2S, and hence the water stripper may commonly be known as the sour water stripper. The purified water may be reused or discharged into the environment. The contaminated water enters into the unit from the bottom and is heated by a coil placed at the bottom of the stripper. The heat strips the gases from the water. The gases (mostly sour) are collected from the top of the stripper and are either burned off or sent to the Claus sulfur plant (section 2.31.18) for further processing. The liquid collected at the bottom of the stripper is further purified in a reflux drum. Depending on the extent of purification, the water may be recycled back into the stripper or discharged into the environment. The sour water stripper towers are constructed from carbon steel, as long as the temperature is controlled above 175 F (w80 C). The carbon steel may suffer localized corrosion in the feed and bottom sections; SSC (to avoid it the materials not susceptible to SSC are used); FILC (to avoid it the velocity of carbon steel piping is limited to 20 feet/s (6 m/s) in two-phase flow and 50 feet/s (w15 m/s) in single-phase gas flow); and erosion-corrosion in the overhead section. The piping between the condenser and the reflux drum is typically constructed using stainless steel. The reflux drum and pump are constructed from carbon steel with CRA cladding. The overhead condensers and tubes are constructed from titanium.

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Standards providing guidelines for selecting materials for sour-strippers, as well as for controlling corrosion in the sour environment include: • • • • • •

NACE MRO175/ISO 15156: Petroleum and Natural Gas Industries – Materials for Use in H2S-containing Environments in Oil and Gas Productions (Parts 1, 2, and 3) NACE RP 0472, ‘Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments’ NACE 8X194, ‘Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service’ NACE RP0296, ‘Guidelines for Detection, Repair, and Mitigation of Cracking of Existing Petroleum Refinery Pressure Vessels in Wet Hydrogen Sulfide Environments’ API 944, ‘Survey of Materials Experience and Corrosion Problems in Sour Water Strippers’ API 950, ‘Survey of Construction Materials and Corrosion in Sour Water Strippers’

2.31.18 Claus sulfur plant This process was developed by Claus. This process produces sulfur from sour natural gas and from the sour gas produced as a byproduct during refining crude oil. The Claus process consists of two steps. In the first step, H2S is burned at 1,562 F (850 C) the ratio of air to H2S is controlled so that one third of the H2S is converted to SO2: 2H2 S þ 3O2 / 2SO2 þ 2H2 O

(Eqn. 2.8)

In the second step, the H2S and SO2 are reacted in the presence of an activated alumina or titanium dioxide catalyst to produce solid sulfur: 2H2 S þ SO2 / 3S þ 2H2 O

(Eqn. 2.9)

A Claus sulfur plant is constructed using various materials depending on the temperature of operation. Stainless steels are used for operation at temperatures above 500 F (260 C), and carbon steels are used for operations at temperatures below 500 F (260 C). Carbon steel or aluminum is used for handling molten sulfur. The acid gases (H2S, CO2, and SO2) are kept above their dew points to control corrosion. The ends of pipes that discharge sulfur may suffer severe corrosion due to presence of oxygen. For this reason, the end portion of the discharge pipe is constructed from CRA.

2.31.19 Heat exchangers Many refinery processes require high temperatures. Boilers are used to provide the heat, hot water, or steam for this purpose. The heat generated in the boilers is transferred to the process fluids by a series of heat exchangers. The most common heat exchangers consist of shell and tube, air coolers, and plate. Boilers are mainly constructed using copper, steel, stainless steel, and wrought iron. Materials for heat exchangers are selected based on their corrosion, erosion, hydrodynamics and heat exchanging properties. Historically, copper was used for their better thermal conductivity. In non-corrosive environments the heat exchangers are constructed from carbon steel materials. As the corrosivity of

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the environment increases progressively the following corrosion control measures are implemented: application of plastic coating, CRA cladding of material, and finally, CRA materials. The physical size of the heat exchanger also plays a role in material selection. For example, small vessels are economically constructed using CRAs, whereas larger diameter vessels are more suitable for cladding. The heat exchanger tubes carry seawater or chloride-containing water and the flow rate is kept high to minimize contact of the fluid with the tube wall. In addition, the tubes are thin-walled so that they exchange heat efficiently. CRAs, especially, stainless steels or nickel alloys are commonly used to fabricate exchanger tubes. In the presence of H2S, stainless steel and nickel alloy tubes may be replaced with titanium tubes.

2.31.20 Cooling towers Many refinery units operate at high temperatures. After completing the process in the unit, the heat should be absorbed from the process fluids. Cooling towers are used for this purpose. Cooling towers use the evaporation of water to reduce the temperatures of process fluids. The cooling towers vary in size from small roof-top units (of 6 barrel (w1 cubic meter)) to very large structures (1,000 barrels (w160 cubic meter)). Water is collected from several sources for use in cooling towers, including ponds, lakes, rivers, production wells, and the ocean. The water may be used once (once-through system) or repeatedly (re-circulating system). Normally salt water is used in a once-through system and fresh water is used in both systems. The corrosivity of water depends on several parameters including the oxygen concentration, pH, temperature, microbial content, salt content, and velocity. The corrosivity of the recirculating water may be controlled by adjusting the pH as well as by the addition of corrosion inhibitors. pH is typically maintained below 7; above this, scaling becomes a problem (see section 7.6). Some commonly used corrosion inhibitors include chromates, phosphates, molybdates, and organics. The choice of corrosion inhibitor depends on pH, dissolved solids, hardness of water and environmental regulations. Chromates are the most effective inhibitors, but are toxic to marine species. Addition of corrosion inhibitors may not be economically feasible in once-through water system. The corrosivity of water used in a once-through system is primarily controlled by the removal of oxygen by de-aeration and by the addition of oxygen scavengers (e.g., sodium sulfite). To the maximum extent possible, the components of cooling water towers handling fresh water are constructed from carbon steel. Carbon steel may be protected with organic coatings or corrosion inhibitors. Copper alloys may also be used to construct cooling water systems. However at higher velocity the copper alloys may undergo erosion-corrosion and dezincification (see section 5.7). Under conditions where copper alloys are unsuitable, stainless steels are used in freshwater systems. However use of stainless steels is restricted to certain conditions (e.g., pH above 6, temperature below 140 F (60 C), and chloride concentration less than 1,000 ppm) which do not result in pitting corrosion. The heat exchanger tubes may be constructed using copper-nickel alloys. However, when the concentration of sulfides exceeds 0.007 ppm, these alloys are susceptible to corrosion. Under these conditions, titanium alloys may be used.

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FRPs are increasingly being used for handling salt water at temperatures below 180 F (82 C) and at pressures below 150 psi (w1 MPa).

2.31.21 Solvent extraction unit Hydrocarbons may contain very complex polyaromatic compounds with high carbon to hydrogen ratios and with the number of carbons in a molecule exceeding 50. Such compounds include waxes and asphaltenes. These high molecular weight contaminants are removed in the solvent extraction units. Depending on the contaminant removed, the units may also be identified either as a dewaxing unit (for removing wax) or a deasphalting unit (for removing asphalt). Solvents are used to remove these contaminants from hydrocarbons. The solvents used depend on the type of constituents to be removed and on the type of hydrocarbons being treated. For example, to dissolve asphalt, either propane or butane is used; to treat lubricating oil, phenol, cresol, or furfural is used; to treat kerosene, liquid SO2 or furfural is used; and to treat gasoline, phenol, acetonitrile, or liquid SO2 is used. Most of the solvents used in the solvent extraction unit are non-corrosive and hence typically carbon steel is predominantly used. When phenol is used, carbon steels clad with CRAs, or CRAs (typically stainless steel) are used. Units handling furfural dissolved in water are typically constructed from stainless steels. Stainless steel suffers SCC in the presence of chlorides. In these conditions, brass or 70 Cu-30Ni alloy is used.

2.31.22 Steam reforming unit Steam reforming unit (SRU) produces hydrogen from natural gas for use in hydrotreaters and the hydrocracker units. This unit can also be known as a steam methane reforming (SMR) unit. It should be noted that a SRU is different from CRU (see section 2.31.10) of naphtha, which also produces significant amounts of hydrogen as a byproduct during the reformation of hydrocarbons. In the SRU, steam reacts with methane at 1300 to 2000 F (w700 to 1100 C) in the presence of nickel to produce carbon monoxide and hydrogen: CH4 þ H2 O / CO þ 3H2 Carbon monoxide further reacts with steam at lower temperatures (typically additional hydrogen: CO þ H2 O / CO2 þ H2

(Eqn. 2.10) 820 C)

to produce (Eqn. 2.11)

The equipment handling dry steam operating up to 1,000 F (w540 C) is constructed from carbon steel. Above this temperature carbon steel undergoes high temperature oxidation (see section 5.15). Addition of chromium (up to 9%) and molybdenum (up to 1%) increases the temperature limit of carbon steel up to 1,200 F (650 C). The carbon steel components are further protected by refracting liners. In addition, the materials are susceptible to erosion-corrosion. Facilities handling boiler feed-water are constructed from carbon steel. Corrosion due to condensation of water is controlled by minimizing the solid (including carbonates and bicarbonates) and oxygen contents of water. When the oxygen concentration in the water exceeds 100 ppb (0.1 ppm), the components are constructed from stainless steel. However the presence of solids may cause alkaline SCC of stainless steel.

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The de-aeration chambers where oxygen is removed may undergo corrosion and cracking. Therefore their operation is properly controlled. Standards providing guidelines to control cracking of de-aeration chambers include: •

NACE RP0590, ‘Recommended Practices for Prevention, Detection, and Corrosion of De-aerator Cracking’

2.31.23 Methyl tertiary butyl ether (MTBE) unit Due to environmental reasons, lead in gasoline has been replaced with methyl tertiary butyl ether (MTBE). MTBE is produced by mixing isobutylene and methanol in the presence of a catalyst at a moderate temperature. MTBE is non-corrosive and hence the MTBE unit is constructed using carbon steel, but it does degrade common elastomers (e.g., VitonÔ and NitrileÔ), so specially formulated urethane seals are used in the MTBE unit and storage tanks.

2.31.24 Polymerization unit In this unit, gaseous hydrocarbons (e.g., propane and butane) polymerize to produce higher molecular weight liquid hydrocarbons. The polymerization reactions are of two types: thermal polymerization and catalytic polymerization. During thermal polymerization, the propane or butane is heated and held at temperatures between 950 and 1,100 F (w510 and 590 C) for polymerization to complete. During catalytic polymerization, the propane or butane reacts in the presence of an acid catalyst at temperatures between 300 and 450 F (w150 and 230 C) and at pressures between 150 and 1,200 psi (|1,000 and 8, 000 kPa). Phosphoric acid in the solid state is commonly used as a catalyst. The components of thermal polymerization unit are constructed from carbon steel clad with refractory materials. When solid phosphoric acid is used, the components of catalytic polymerization units are constructed from carbon steel. But liquid phosphoric acid is corrosive to carbon steel. Therefore, when liquid phosphoric acid is used the polymerization unit is constructed from CRAs.

2.31.25 Hydrogen plant Hydrogen gas produced in the SRU and CRU is purified in the hydrogen plant. The gas from these units is cooled to 700 F (w370 C) and fed into the absorption tower. The tower removes CO2 from hydrogen gas using potassium carbonate or ethanolamine. The materials used to construct the components of hydrogen plant depend on the operating temperatures; carbon steel is used up to 800 F (w425 C) 1 Cr-0.5 Mo carbon steel up to 850 F (455 C) 2 Cr-1 Mo up to 1,200 F (w650 C) and CRAs above 1,200 F (w650 C). The components of the hydrogen plant are susceptible to high temperature corrosion, including green rot (see section 5.15.1g) and high temperature hydrogen induced cracking (HTHIC) (see section 5.18.5).

2.31.26 Ammonia plant In the ammonia plant, hydrogen and nitrogen combine to form ammonia. The synthetic gas (hydrogen and CO2) produced in various reforming units is used to produce ammonia. Synthetic gas is fed into a secondary reformer which is heated to 1,800 F (w980 C) with the addition of hot air. The hot synthetic gas then passes through a series of units to remove CO2 and to convert residual oxides into

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methane. Then the hydrogen gas is mixed with nitrogen, pressurized to 3,000 psi (20,700 kPa), and charged onto a catalyst bed where ammonia is produced. The ammonia is then cooled and refrigerated to remove the impurities. Most material requirements of an ammonia plant are similar to those for a hydrogen plant. An additional feature of the ammonia plant is the presence of a secondary reformer with operating temperatures reaching as high as 2,000 F (1,090 C). The secondary reformer is constructed from carbon steel with a refractory lining. The materials used to construct the components of ammonia plant are evaluated for their resistance to hydrogen attack, nitridation (see section 5.15.1c), and localized corrosion (in the presence of oxygen and CO2). Standards providing guidelines for the selection of materials for ammonia plant include: •

API 941, ‘Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants’

2.31.27 Methanol plant The feedstock for the methanol plant is the same as that for hydrogen and ammonia plants; i.e., synthetic gas from the reforming units. This is compressed to 1,500 psi (10.3 MPa), heated to 600 F (315 C), and passed onto a catalyst when methanol is produced. The methanol is cooled and fractioned to purify it. Material requirements of methanol plant are similar to an ammonia plant. Most of the materials used are carbon steel. At around 500 F (260 C), carbon steel suffers higher corrosion in the methanol plant due to the presence of CO, CO2, and hydrogen. Under these conditions, CRAs are used. In addition, the boiler of a methanol plant may suffer metal dusting.

2.31.28 Other units The units described in sections 2.31.1 through 2.31.27 are only a few of the hundreds of different oil refinery units. Several other units such as separators, gas dehydration facilities, recovery centers, wastewater pipelines and other units are also present. Their materials of construction should be selected on the basis of their corrosion resistance under the operating conditions of these units.

2.32 Product pipelines Products are transported from the refineries to the product distribution centers or terminals. The product terminals are more widely distributed than refineries. Pipelines are the safest, most reliable, and cost effective method of transporting the large volume of petroleum products. However, the capital cost associated with constructing pipelines limits their use to locations where very large volumes of products are to be transported for an extended period of time, typically over 15 to 20 years. Where the volume of petroleum products cannot justify the construction of a pipeline, petroleum products are transported to product terminals over land by trucks and rail cars and over water by marine tankers. The quality of the products is checked before they enter into the pipelines and just before they leave the pipelines. Petroleum products are generally transported in a pipeline in ‘batches’; i.e., at any given

2.33 Terminals

Regular Midgrade Premium Midgrade Regular Diesel Gasoline Gasoline Gasoline Gasoline Gasoline Diesel

End of Cycle

Direction of Flow

Jet Fuel

119

Diesel

Beginning of Cycle

FIGURE 2.26 Transportation of Refined Products.52 Reproduced with permission from PennWell Corporation.

time a specific section of pipeline may contain different petroleum products such as gasoline, diesel fuel, heating oil or kerosene. Figure 2.26 presents a typical batching sequence of refined petroleum products in a pipeline.52 New batching cycles may occur at fixed time frames, such as every 5, 7, or 10 days. Transportation in batches results in mixing of products. If the products are similar, such as different grades of gasoline, the contaminated gasoline is mixed with lower grade gasoline. If the products are different, the contaminated product (often referred to as ‘transmix’) is typically trucked back to the refinery for re-processing. Physical separators (e.g., pigs) may be used between products when sensitive products (e.g., jet fuel) are transported. The requirements of materials are similar to the oil transmission pipelines (see section 2.21.2). Because all impurities causing corrosion are removed before the products are pumped into the pipelines, the probability of internal corrosion is low. Internal corrosion may occur in locations where water accumulates, and if corrosive species dissolve in the water phase. Similar to oil transmission pipelines, the external surface of the product pipeline is protected with coatings and CP and is susceptible to external pitting corrosion and SCC when the coatings and CP fail.

2.33 Terminals Petroleum products are stored in terminals for final distribution to customers. Only one terminal may exist in a city and all petroleum producers store at that terminal. Before the gasoline leaves the terminal, some retailers may add performance enhancing chemicals to distinguish their brand from others. The formula of the chemicals is confidential and unique to a specific brand/company. Each product has a different delivery system to and from the terminal depending on the customer base. For example, jet fuel is often transported by pipeline directly to the airport, and petroleum and diesel are transported by pipes or trucked to retail outlets (gas stations). The material requirements and corrosion characteristics of terminals are similar to oil storage tanks (see section 2.30). Because the products stored in the terminals are closer to the customers, they are present in their purest form. Consequently corrosion is not an issue in terminals.

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2.34 City gate and local distribution centers Local distribution centers are the link between gas transmission pipelines and customers. The point at which the local distribution center connects to the natural gas transmission pipeline is known as the city gate. At the city gate a mainline is connected to the transmission pipeline and the gas pressure is progressively reduced to allow distribution of gases to the customers through service lines. Several service lines are connected to the mainline and they serve individual consumers including residences, commercial buildings, and small industries. A sour-smelling chemical (ethyl or methyl mercaptan) is added at the city gates to the gas to facilitate detection of leakage if it occurs. The characteristic and sometimes offensive smell that consumers often associate with natural gas actually comes from these chemicals (natural gas is in fact odorless). Local natural gas distribution pipings are usually smaller in diameter than natural gas transmission pipelines. They are normally installed underground, usually along or under streets and roadways. New residential and commercial service lines are routinely added to local distribution systems. The method of connecting new pipings is called hot-tapping. In this method, a fitting, with a shutoff valve, is first welded onto the pipe. A cutting machine is connected to the fitting. A hole is then made in the pipe with a steel or plastic cutting blade inside the hot tapping machine. The blade is retracted and the valve is closed to prevent gas flow. New pipe is then connected to the fitting. At the city gate, the natural gas is depressurized, typically from as high as 1,300 psi (w9,000 kPa) (in the transmission pipeline) to as low as 3 psi (20 kPa). The depressurized gas is scrubbed and filtered to ensure low moisture and particulate content. As a consequence, corrosion is not a concern in the local distribution pipes, so they are traditionally constructed from carbon steel. However, flexible plastic and stainless steel tubing are increasingly being used, further reducing corrosion probability.

2.35 Compressed natural gas (CNG) Compressed natural gas (CNG) is created by compressing natural gas (mostly methane) to less than 1% of its volume at standard atmospheric pressure. Typically CNG is distributed in cylindrical or spherical tanks at pressures between 2,900 and 3,200 psi (20 and 22 MPa) The natural gas from the CNG tank is directly used as fuel in automotives or in households. The CNG tanks are different from LNG tanks. The key difference is that CNG tanks store natural gas in the compressed gaseous form whereas the LNG tanks store natural gas in the liquid form. CNG production and storage is relatively less expensive (when compared to LNG) because it does not require cooling process and cryogenic tanks. For same size of CNG and LNG tanks, the mass of gas stored in CNG tank is less. CNG tanks are typically constructed from steel, aluminum, plastic, or lightweight composite materials (fiber-wrapped thin metal). Standards providing guidelines for constructing CNG tanks include: •

ISO 11439, ‘Gas Cylinders – High Pressure Cylinders for the On-Board Storage of Natural Gas as a Fuel for Automotive Vehicles’

Because the natural gas is stored in a clean form, and the CNG tanks are small, corrosion is not an issue.

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2.36 Diluent pipelines Bitumen is too viscous to be transported by pipeline, so it is blended with light hydrocarbons to reduce its viscosity. In the refinery, the diluents are separated from bitumen and re-transported back to the recovery center (see section 2.16). The pipeline transporting diluent is known as diluent pipeline. The material requirements for it are similar to oil transmission pipelines (see section 2.21.2). Internal corrosion may become an issue if the quality of the diluent is not properly maintained. The corrosivity of the diluent will increase if it is exposed to atmospheric air (oxygen) or it is contaminated with water.

2.37 High vapor pressure pipelines Hydrocarbons such as ethane, ethylene, propane, and butane have high vapor pressure (HVP), i.e., their vapor pressure exceeds 35 psi (240 kPa) at 100 F (38 C).53 Pipelines transporting these commodities are known as HVP pipelines. Such pipelines transport hydrocarbons in the liquid state, since this eliminates difficulties associated with two-phase transportation (liquid and gas) and with thermal changes associated with phase change. Maximum operating pressures are generally 1,480 psi (10.2 MPa) for most HVP pipelines. Materials requirements of HVP pipelines are similar to those of oil and gas transmission pipelines (see section 2.21), except that the pipelines are maintained at a minimum pressure to keep the products in the liquid state. The internal corrosion risk in these pipelines is very low as long as the commodities are free from water.

2.38 CO2 pipelines Carbon dioxide is predominantly transported in pipelines from underground CO2 wells and fossil fuel burning facilities, e.g., power generation plants. It is transported to recover more oil (see section 2.7) and to decrease environmental impact. There is growing worldwide recognition that global warming may be caused by excessive greenhouse gas emissions. Because fossil fuels are likely to remain the primary source of energy for some decades to come, capturing CO2 and storing it safely (CO2 sequestration) is becoming increasingly important.54,55 In power generation plants, CO2 is processed (i.e., impurities are removed), dried, and compressed. Dry CO2 is then transported in pipelines and injected into underground oil wells for EOR or into depleted wells (or aquifiers) for long-term storage. Depending on pressure and temperature, CO2 can exist as a solid, liquid, vapor (gas) or supercritical fluid.56 The term ‘dense phase’ is used to represent CO2 in the supercritical or liquid state. Pipelines transport CO2 in its dense phase because of the volume reduction that occurs in the dense phase. Transmitting CO2 in the vapor phase requires larger diameter pipelines than are required to transmit in dense phase. The pipelines are maintained at a high enough pressure to ensure that the CO2 is in a supercritical state. Table 2.22 presents examples and operating conditions of some CO2 transporting pipelines.57 Typical compositions of CO2 pipelines are 98% CO2, 0.15 to 1.5% nitrogen, and 0.11 to 1.5% methane. The presence of water in CO2 pipeline produces carbonic acid (which is corrosive) and

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Table 2.22 Some Examples of CO2 Transmission Pipelines57 Maximum Operating Pressure (MOP), psi

Capacity, MMSCF/day

Diameter, Inches

Length, Miles

Cortez to Denver city, USA Bravo Dome to Denver city, USA Gardner to Denver city, USA

2140 2500 2625

700 600 480

30 24 20 24

Weyburn, Canada

2175

250

508 219 108 300 200

Pipeline

hydrate (which blocks the flow). For this reason the water content is kept low and is continuously monitored. Typical water content is less than 10 pounds of water per MMSCF of CO2. CO2 pipelines are constructed using carbon steel and are operated under high pressure so that the CO2 is in the dense (supercritical) phase. Under these conditions corrosion is not an issue. However when the water content increases and when pressure decreases – mainly due to operational deficiencies – the susceptibility to corrosion and hydrate formation increases. CO2 from the pipelines is collected in a terminal and then injected through a downhole tubular into the well (for EOR or for long-term storage). Most of the surface pipeline in the terminal operates under gaseous phase conditions, and the downhole tubular operates under dense phase conditions. These pipelines and tubulars are constructed using carbon steel, if the purity of CO2 is high (typically above 98%) or from stainless steel if the purity of CO2 is low. When oil is recovered it brings CO2 up to the surface, where it is separated and recycled for more oil recovery. The purity of CO2 separated from oil is typically lower, requiring the use of stainless steel material. CO2 may decompose sealing materials made from petroleum products when the pressure is reduced. Therefore sealants specially made from inorganic materials and grease are used.

2.39 Hydrogen pipelines Hydrogen is used in various processes during the refining of hydrocarbons (see section 2.31). The bulk of it is produced at the site itself, but hydrogen is also transported from further locations. It is transported (either in the gaseous or liquid phase) in high pressure steel cylinders by railroad cars, tankers, and ships. Hydrogen is also transported in pipelines and currently there are over 1,900 miles (3,000 km) of operating hydrogen pipelines (Table 2.23).58 The material requirements of hydrogen pipelines are similar to those for gas transmission pipelines (see section 2.21.1). Standards providing guidelines for designing and constructing hydrogen pipeline as well as converting an existing oil or gas pipeline to hydrogen pipeline include: •

ASME B31.12, ‘Hydrogen Piping and Pipelines’

A hydrogen pipeline may suffer hydrogen embrittlement (see section 5.18.3) if proper material is not selected.

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Table 2.23 Some Examples of Existing Hydrogen Pipelines58 Location Canada USA USA USA Canada USA USA Canada Canada USA UK France Belgium USA Germany

Years of Operation

Diameter (mm)

Length (Km)

Pressure, kPa

20

273 3’ to 14’ 50e450 101.6e304.8 150e300 50 and 100 150e250 5 168 152

3.7 390 357 163 9 3.5 17.4 06 16 3.2 15 879 6.4 6 1.6e3.2

3,800 5100 1,825e10,030 5,514 4,238e10,030 1,136 6,651e15,407 30,000

40 25 28 30 33 44 3 43 8

305 25.4 30

2,757 30,000 6,484e10,000 13,788 13,790

Gas Purity 99.9 99.999

100 100 93.5 (bal.methane) 100 100 100

2.40 Ammonia pipelines Ammonia pipelines have been transporting liquid ammonia for the fertilizer industry for a long time. Ammonia pipelines are used in the oil and gas industry to transport hydrogen. Ammonia gas turns into a liquid at 125 psi (862 kPa) and liquid ammonia is transported in pipelines. At the delivery point, hydrogen gas is liberated from ammonia. Currently there are about 3,000 miles (4,828 kilometer) of 6–8 inch (152-203 mm) diameter carbon steel pipelines in the US which transport about 2 million tons of ammonia per year. This is equivalent to transporting w350,000 tons of hydrogen per year. Ammonia pipelines normally operate at 250 psi (1,723 kPa) pressure. Liquid ammonia is noncorrosive and hence internal corrosion is not an issue.

2.41 Biofuel infrastructure Many new and alternative fuels are being developed as a substitute for fossil-based fuels or as materials to blend with them. Bioethanol and biodiesel appear to be the most promising options. These biofuels may be obtained from various sources including corn, sugar beets, sugar cane, brewing wastes, soy beans, animal fat, and algae. Due to the relatively recent development of alternative fuels, our knowledge and experience of potential corrosion issues with these fuels are just emerging.

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2.41.1 Bioethanol Bioethanol is a renewable fuel because it is produced from biomass. Bioethanol burns more cleanly and completely than gasoline or diesel. Bioethanol reduces greenhouse gas (GHG) emissions because the grain or other biomass used to make the ethanol absorbs carbon dioxide as it grows. Although the conversion of the biomass to ethanol and the burning of the ethanol produce emissions, the net effect is a reduction in GHG emissions compared to the use of fossil fuels such as gasoline. The extent of GHG reduction depends on the feedstock and the production processes used to make the ethanol. Ethanol is also added to the gasoline as a replacement for MTBE (see section 2.31.23).59 There are two processes for producing ethanol from grains: wet milling and dry milling. The main difference between the two is in the initial treatment of the grain. In the dry milling process, the entire corn kernel or other starchy grain is first ground into flour (meal) and processed without separating out the various component parts of the grain. The meal is mixed with water to form a ‘mash’ and enzymes are added to convert the starch to simple sugars. Ammonia or another nitrogen source is added as a nutrient to the yeast and as a pH controller. The mash is cooked, cooled, and transferred to fermenters where yeast is added to convert the sugar into ethanol and CO2. After fermentation, the resulting mixture is transferred to distillation columns where the ethanol is separated. The ethanol is concentrated using distillation and then dehydrated. The anhydrous ethanol is then blended with up to 5% denaturant to render it undrinkable. In the wet milling process, the grain is soaked in dilute sulfurous acid. This process facilitates the separation of the grain into the following components: • • • •

The corn slurry which is processed through a series of grinders to separate the corn germ. The fiber, gluten, and starch components which are further segregated using a centrifugal screen and separators. The steeping liquor which is concentrated in an evaporator. This concentrated product is co-dried with the fiber component and is then sold for other uses. The starch and any remaining water from the mash which are fermented into ethanol. The fermentation process for ethanol is very similar to the dry mill process previously described.

Once fermentation is complete, the product or mash is distilled using steam to produce hydrous ethanol. The hydrous ethanol or hydrated ethanol has about 5–7 volume percent water. Hydrated ethanol is used as a fuel in Brazil. The Brazilian automotive market has evolved over time to include flex-fuel vehicles that can run on ‘gasohol’ (gasoline-ethanol blends), or hydrous ethanol. In the US and other countries ‘anhydrous ethanol’ is used, which contains up to 1% water. Anhydrous ethanol is produced from hydrated ethanol either by distilling it with a solvent or by using molecular sieve. Table 2.24 presents the specifications of bioethanol in the USA and Brazil.49 Standards providing specifications of bioethanol include: • • •

ASTM D4806, ‘Standard Specification for Denatured Fuel Ethanol for Blending with Gasolines for Use as Automotive Spark-Ignition Engine Fuel’ ASTM D6423, ‘Standard Test Method for Determination of pHe of Ethanol, Denatured Fuel Ethanol, and Fuel Ethanol’ Fuel Ethanol – Industry Guidelines, Specifications and Procedures, RFA Publication #960501 Renewable Fuels Association, available online at: www.ethanolrfa.org.

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Table 2.24 Specifications of Bioethanol2,59 Country Product Ethanol, v% min. Methanol, v% max. Water Chloride, ppm max. Copper, ppm max. Acidity (measured as acetic acid), ppm max. Denaturant, v% min. Conductivity, mS/m Sulfate, ppm max. pH (or pHe) Gasoline, v% max.

USA

USA )

))

Brazil

Brazil

Bioethanol 92.1 0.5 1.0 v% max. 40 0.1 70

E85 70e79 0.5 1 m% max. 2 0.07 50

Anhydrous Ethanol 99.3 e 0.3 v% max. 2 0.07 30

Hydrous Ethanol 92.6 e 7.4 m% max. 1 NA 30

1.96 e e 6.5 e 9.0

e e e e e

e 500 e e e

))) 500 4 6 to 8 3.0

)))

)

Commonly known as fuel grade ethanol (FGE) 85% ethanol and balance gasoline ))) Gasoline is the usual denaturant ))

Bioethanol is blended with gasoline in refineries. It is transported by railcar or truck from the production location to the refinery. Limited amounts of ethanol pipelines do exist in USA and Brazil. Because of their ability to pick up water, several precautions are taken while transporting ethanol and ethanol-blended gasoline. Dedicated tanks, trucks, and service station pumps are used to handle the ethanol and the gasoline blending components. Most of the equipment used in the bioethanol infrastructure is constructed using carbon steel. The corrosivity of bioethanol is related to three parameters: the solubility of oxygen, the pH and the conductivity. Table 2.25 compares these properties for bioethanol and water.49 The solubility of oxygen in ethanol is about 10 times greater than that in water and, therefore, can provide the driving force for corrosion. The conductivity of ethanol is about an order of magnitude less than that of water, but is enough to sustain corrosion. In addition, ethanol is hygroscopic in nature; i.e., it absorbs water from moist air. Common impurities in bioethanol are organic acids and inorganic acids, with acetic acid being the most common. The presence of acetic acid in ethanol increases the tendency of steel and other materials to corrode. Trace amounts of sulfuric acid present in bioethanol produced by wet milling process also increases the corrosivity of bioethanol. Field experience from about 25 cases of the performance of carbon steel equipment in bioethanol meeting the requirements of ASTM D4806 can be summarized as follows:60 1. Stress-corrosion cracking has occurred on the internal surface of ethanol handling equipment. 2. Most cases of SCC occurred in end-user storage and blending facilities (steel tanks, rack piping and related vessels and equipment) with some failures in midstream, fuel ethanol distribution storage tanks, and in a short segment of pipeline. No case of SCC was reported in fuel ethanol

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Table 2.25 Comparison of Oxygen Solubility, pH, and Conductivity of Bioethanol, Methanol, and Water at Neutral Solution49 Solution Water Methanol Ethanol

Dielectric Constant (25 C)

pH of Neutral Solution

78.5 32.6 24.3

7 8.35 9.55)

Oxygen Solubility (cm3, 1 atm and 25 C) 0.0227 0.227 0.221

Specific Conductivity (ohmL1cmL1) 5.6 x 10 1.6 x 10 4.3 x 10

1 1 2

)

As determined by ASTM D6423 method

manufacturer facilities, tanker trucks, railroad tanker cars or barges, or following blending of the ethanol with conventional gasoline. 3. The majority of SCC in steel equipment was intergranular in nature, although transgranular SSC has also occurred. 4. SCC has occurred in locations of higher stresses, including non-post-weld heat-treated (PWHT) welds, fillet welds at lap seams and roof springs. 5. The SCC failures experienced in the USA were not experienced in Brazil, even though the latter has a longer history of producing and using bioethanol. Laboratory studies have indicated that influences on the corrosivity of ethanol decreased in the order: oxygen concentration > chloride concentration > methanol concentration, and other parameters including denaturant, sulfate, acetic acid (pHe), and corrosion inhibitor had little or no influence on the corrosivity.61

2.41.2 Biodiesel Biodiesel is the generic name of diesel fuel produced from renewable resources (i.e., biological organisms). It was produced 40 years before the invention of the diesel engine (see section 1.5). Currently over 20 countries produce over 30 million barrels (3.5 billion liters) of biodiesel commercially. Biodiesel is produced from rapeseed, soy bean, yellow grease, canola, algae, jatropha, and pongamia.62–65 The ingredient is mixed with an alcohol (methanol or ethanol) in the presence of a catalyst (sodium or potassium hydroxide) to produce esters. Hence this process is also known as transesterification (Figure 2.27). Figure 2.28 presents the processes involved in the production of biodiesel. In addition to the esters (biodiesel), glycerol (also referred to as glycerine) is produced. These two products are then separated, and the biodiesel is washed – usually with water – to remove excess methanol, unreacted oil, and remaining glycerol. The biodiesel produced should meet certain standards before it can be mixed with petroleum diesel. Standards providing specifications for biodiesel include: • •

ASTM D6751, ‘Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels’ ASTM D7467, ‘Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)’

2.41 Biofuel infrastructure

CH2OCOR'

CH2OCOR''

CH2OH

+ 3 ROH

CH2OCOR' Vegetable oil

Alcohol

Catalyst

CH2OH

127

R'COOR

+

R''COOR

CH2OH

R'COOR

Glycerin

Biodiesel

FIGURE 2.27 Chemical Reaction Scheme for the Production of Biodiesel. (R0 , R00 , and R000 indicate the fatty acid chains in the vegetable oil which are mostly palmitic, stearic, oleic, and linoleic acids).62–65

FIGURE 2.28 Production of Biodiesel.62–65

• • •

ASTM D975, ‘Standard Specification for Diesel Fuel Oils’ EN 14214, ‘Automotive Fuels: Fatty Amino Acid Methyl Esters (FAME) for Diesel Engines. Requirements and Test Methods’ Canadian General Standards Board (CGSB) CAN/CGSB-3.520, ‘Automotive Diesel Fuel Containing Low Levels of Biodiesel’

Biodiesel is blended with diesel by four methods: splash blending, in-tank blending, in-line blending, and rack blending (the biodiesel is injected directly at the rack into the tank truck). A biodiesel pipeline network has not emerged, basically because most of the biodiesel produced is consumed closer to where it is produced, and because transportation of the smaller volumes by truck appears to be economic. The components of the biodiesel network are constructed from carbon steel, stainless steel, or aluminum. Biodiesel and biodiesel blends are non-corrosive unless they are contaminated with water. However, biodiesel and its blends may degrade rubbers (both natural and synthetic), polypropylene, polyvinyl, and TygonÔ. SCC associated with bioethanol has not been reported in biodiesel transportation and storage systems.

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59. Kane RD, Papavinasam S. Corrosion and SCC issues in Fuel Ethanol and Biodiesel. Corrosion 2009, Paper #9528. Huston, TX: NACE; 2009. 60. API Bulletin 939E. Identification, Repair, and Mitigation of Cracking of Steel Equipment in Fuel Ethanol Service. Washington, D.C.: American Petroleum Institute; 2008 in Publication. 61. Beaver J, Gui F, Narashi S. Recent Progress in Understanding and Mitigating SCC of Ethanol Pipelines. CORROSION 2010, Paper #10072. Houston, TX: NACE; 2010. 62. Ghadge SV, Raheman H. Biodiesel production from mahua (Madhuca indica) oil having high free fatty acids. Biomass Bioenergy 2005;25:601–5. 63. Meenakshi HN, Anisha A, Shyamala R, Saratha R, Papavinasam S. Corrosion of metals in biodiesel from Pongamia pinnata. Corrosion; 2010. Paper No.10076, NACE Corrosion Conference. 64. Rahimi H, Ghobadian B, Yusaf T, Najafi G, Khatamifar M. Diesterol: An Environment-friendly IC Engine Fuel. Renewable Energy 2008;34(1):335–42. 65. Cvengros J, Povazanec F. Production and Treatment of Rapeseed Oil Methyl Esters as Alternative Fuels for Diesel Engines. Bioresour Technol 1996;55(2):145–50.

CHAPTER

3

Materials

3.1 Introduction The oil and gas industry uses various materials, including metals and non-metals. Over 90% of the materials used are metals, but non-metals serve critical functions in the industry and they are increasingly replacing metals in some key areas. The properties of materials required to construct components for the oil and gas industry are relatively well established, and various standards are available to ensure that the materials possess the properties required for the application. This chapter discusses the basic properties of metals and non-metals, the types of materials used in the oil and gas industry, the classification of materials, and the standards used to evaluate and select them.

3.2 Properties of metals and alloys The properties of metals depend on their crystal structure, which can be defined by its unit cell. The unit cell is a pattern in which the atoms in the solid matrix are arranged. In the crystal structure is the periodic arrangements of unit cells. The commonly observed unit cells are the face-centered cubic (FCC) (Figure 3.1)1 the body-centered cubic (BCC) (Figure 3.2),2 and hexagonal-close packed (HCP)

a

a

Origin

FIGURE 3.1 Schematic Diagram of Face-Centered Cubic Crystal Structure.1 Reproduced with permission from ASM International. Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00003-0 Copyright Ó 2014 Elsevier Inc. All rights reserved.

133

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a

a

c

Origin

FIGURE 3.2 Schematic Diagram of Body-Centered Cubic Crystal Structure.2 Reproduced with permission from ASM International.

a

a

c

Origin

FIGURE 3.3 Schematic Diagram of Hexagonal-Close Packed Crystal Structure.3 Reproduced with permission from ASM International.

(Figure 3.3).3 Other unit cells such as orthorhombic, and body-centered tetragonal unit cells also exist. Metals exhibiting a FCC crystal structure include copper, nickel, aluminum, gold, and silver; metals exhibiting BCC include iron, molybdenum, chromium, and vanadium; and metals exhibiting HCP include magnesium, zinc, cobalt, and titanium. Some metals display different crystal structures under different conditions. These different structures are called allotropes. For example, the crystal structure of titanium at room temperature is HCP whereas it is BCC at high temperature. Metals are not one large crystal made up of periodic arrangement of unit cells, but rather are made up of several crystals randomly oriented with respect to one another. These clusters of crystals are known as grains. The boundaries between the grains are known as grain boundaries. The atoms are not in their proper places in grain boundaries because the periodic nature of the grain formation has been

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disrupted. Because of this different orientation of the atomic structures, the properties of grain boundaries are different from those of grains. The study of the structure of metals, i.e., the study of grains and grain boundaries by optical microscopy is called metallography. Standards providing guidelines on terminology related to metallography include: •

ASTM E7, ‘Terminology Relating to Metallography’

In general, as the number of grain boundaries increases (consequently as the grain size decreases) the mechanical properties (strength, ductility, and toughness) improve, but chemical and corrosion resistance decrease. Grain boundaries have higher energy than the grains, hence are preferentially attacked by chemicals. Most pure metals do not possess the properties (mechanical strength, chemical resistance, and corrosion resistance) necessary for engineering applications. Therefore other elements are introduced into the metal to provide these. A combination of two or more elements in which at least one of the elements is a metal is called an alloy or solid solution. In an alloy, the parent metal is the solvent and the alloying element is the solute. If the solute element is small (e.g., carbon, nitrogen, or hydrogen) the energetically favorable situation is one in which the solute element occupies the interstitial positions; i.e., the alloying elements occupy the interstitial holes between the parent metal atoms (Figure 3.4 (A)).4 The resulting alloy is known as interstitial solid solution. If the solute element is large (e.g., chromium, nickel, or manganese) then it will substitute the atom of the parent metal. The resulting alloy is known as substitutional solid solution (Figure 3.4 (B)).4 Before a metal or an alloy is selected, its suitability for an application is established by investigating its mechanical properties, phase diagram, microstructure, and corrosion resistance.

3.2.1 Mechanical properties The mechanical properties of a material decide how much pressure the material can withstand. They are defined by the yield strength, tensile strength, hardness, impact resistance, and fatigue resistance.

3.2.1a Yield strength Yield strength describes the stress-strain relationship of a metal. It is used to describe elastic behavior of the metal. Below the elastic behavior limit, stresses or strains applied when relaxed will cause no permanent deformation in the metal. The yield strength of the metal is used for calculating allowable or design stresses of structures constructed from the it. The elastic constant is expressed as the modulus of elasticity or Young’s Modulus, YM, and is given by: s ¼ YM:ε

(Eqn. 3.1)

where s is the stress in psi, YM is the Young’s Modulus (elastic constant) in psi (or kPa), and ε is the strain. Strain has no units but is commonly presented as a percentage. The Young’s Modulus of steel is typically 30  106 psi (206,842 MPa).

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FIGURE 3.4 Schematic Diagram of Interstitial Solid Solution and Substitutional Solid Solution.4 Reproduced with permission from ASM International.

3.2.1b Tensile strength The tensile strength is determined in a laboratory test in which the metal is pulled apart at a constant rate by a tensile machine. The stress is calculated at each point by dividing the load applied by the original cross-sectional area: Ps (Eqn. 3.2) s¼ A where s is the stress in psi (kPa), Ps is the applied load in pounds (kg), and A is the original crosssectional area in in.2 (mm2) Commonly a round bar with a reduced section is used (Figure 3.5).5 A known length (gauge length) is marked on the reduced section of the bar. The change in gauge length of the sample in comparison to its original length is considered to be the measure of strain (ε): DL L where DL is the change in length in in.(mm) and L is the original length in in.(mm) ε¼

(Eqn. 3.3)

FIGURE 3.5 Schematic Diagram of Tensile Test.5 A is the length of the reduced section; D is the diameter; R is the radius of the fillet; and G is the gauge length. Reproduced with permission from ASTM International.

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FIGURE 3.6 Stress-Strain Curve.6 A is the yield strength and B is the tensile strength. Reproduced with permission from MetCorr.

A typical stress-strain curve (Figure 3.6)6 can be used to determine two mechanical properties: the elastic limit and the plastic limit. In Figure 3.6, until Point A the relationship between stress and strain is linear. The stresses or strains applied until this point when relaxed will cause no permanent deformation in the metal. Application of stress beyond point A results in a permanent deformation in the metal, i.e., the strain becomes plastic. A further increase in stress results in necking down, i.e., the cross section of the sample is reduced. Subsequently the sample fractures. The maximum stress sustained by the metal prior to the necking divided by the cross-sectional area is defined as its tensile strength; i.e., Point B in Figure 3.6. The extent of necking is a measure of the ductility of a metal: the greater the necking, the higher the ductility of the metal. The percent reduction in area (RA%) calculated from the original cross-sectional area of the tensile specimen and the final cross-sectional area after fracture is a measure of ductility. The change in length of the specimen after testing compared to its original length is the percentage elongation and may also be used as a measure of ductility.

3.2.1c Hardness The hardness of a metal is measured by its resistance to an applied load. The higher the hardness strength of the metal, the smaller is the deformation due to the applied load. The hardness of materials may be measured in the laboratory or in the field (see section 8.2.1a for a description of hardness tests). Table 3.1 presents the approximate correlation between hardness scales and tensile strength.7 When obtaining accurate tensile strength is difficult, the approximate values from Table 3.1 may be used.

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Table 3.1 Correlation Between Tensile Strength and Hardness of Metals7 Rockwell Scale B

97.8 90.7 85.0 80.8 74.0 69.8 65.7

Vickers Hardness

Vickers Hardness

Brinell Hardness

Tensile Strength

C

10 kg

500 g and over

3,000 Kg

w1,000 psi

55 50 45 40 35 30 25 20

598 513 446 393 343 301 264 240 196 171 156 137 122 117

630 542 466 402 351 311 278 251 205 178 163 140 129 124

547 484 426 372 322 283 255 227 187 163 149 126 116 111

301 255 214 182 157 136 120 108 90 79 73 63 58 56

3.2.1d Impact resistance Impact resistance is a measure of the resistance of materials to mechanical impact without undergoing any physical changes. BCC materials normally exhibit ductile behavior, but when the temperature decreases, their behavior changes to brittle. The temperature at which the ductile material becomes brittle is known as the transition temperature. Metals with FCC and HCP unit cells, however, do not exhibit such a transition. The Charpy impact test is commonly used for evaluating the resistance of a metal to brittle fracture and for determining its transition temperature. Figure 3.7 presents a typical specimen geometry used in Charpy tests, and Figure 3.8 presents a typical ductile-to-brittle transition curve.8,9 Standards providing guidelines for conducting a Charpy impact test include: •

ASTM E23, ‘Standard Test Methods for Notched Bar Impact Testing of Metallic Materials’

3.2.1e Fatigue resistance When a metal is subjected to cycles of stress it eventually cracks. This phenomenon is known as fatigue cracking. Fatigue may be caused by several factors, including thermal fluctuations, ocean waves, wind, and mechanical vibrations. The fluctuating stress may be below the tensile strength of metal, but repeated cycles of stress will cause failure by fatigue. As the stress level increases, the number of cycles before failure occurs decreases. The stress level below which no fatigue failure occurs even with an infinite number of cycles is known as the ‘endurance limit’. As a rule of thumb, the threshold stress or fatigue limit of metal is assumed to be approximately half of its tensile strength. (See section 5.16 for more discussion on fatigue resistance and methods to evaluate the fatigue resistance of materials).

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139

10 mm 10 mm

L/2 45º 55 mm

FIGURE 3.7 Typical Specimen Geometry for Charpy Test.8

FCC

BCC

Energy Absorbed in the Impact Test

Reproduced with permission from ASTM.

HCP

RT Temperature

FIGURE 3.8 Schematic Diagram showing Typical Ductile-to-Brittle Transition (RT is the Transition Temperature).9 Reproduced with permission from MetCorr.

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Standards providing guidelines on fatigue resistance include: •

API RP 2A, ‘Planning, Designing and Constructing Fixed Offshore Platforms – Working Stress Design’

3.2.2 Phase diagram A phase diagram is a graph of the temperature and composition limits of various phases in an alloy. These phases actually exist at specific temperatures. Formation of phases at room temperature may be

FIGURE 3.9 Phase Diagram of Carbon Steel.10 Reproduced with permission from ASM International.

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141

predicted from the phase diagram. To that extent the phase diagram is the best way to understand the metallurgy. The diagram may only be applied to materials that have been cooled very slowly from an elevated temperature, but not to materials that have been cooled rapidly (e.g., quenched steel). The phases that develop during rapid cooling are not represented in the phase diagram. Figure 3.9 presents the phase diagram of an iron-carbon binary phase as an example. This diagram represents the phases which exist in steel as a function of carbon content and temperature.10

3.2.3 Metallography The study of the constitution and microstructures (grains and grain boundaries) of metals, alloys, and materials is called metallography. Even single phase systems can produce characteristic microstructures. The shapes, sizes and configuration of the constituents in a multiphase system produce a variety of microstructures. The microstructural features can be investigated over a wide range of scales or magnification. For example, a sample can be magnified 100,000 times (normally expressed as 100,000x) using microscope. A variety of microscopes, with various ranges of magnifications, is available. The magnification of light microscopes may range between 50x and 1000x; that of scanning electron microscopes (SEM) may be between 10x and 10,000x; and that of transmission electron microscopes (TEM) may range between 1,000x and 100,000x. Figure 3.10 presents some techniques commonly used to investigate microstructure and their observation limits.11 Both macro-level and micro-level examinations are essential to characterize the microstructure of metals. The examination of the microstructure of metals starts at a macro-level. For example, cross section of a component or sample may be examined by light microscopy to reveal important macrostructural features. Macro-level examination may reveal information on macro defects in the materials, weld characteristics, fabrication imperfections, gas and shrinkage porosity, depth and uniformity of a hardened layer, fracture initiation, crack propagation, surface roughness, extent and location of wear, plastic deformation, and forms of corrosion. Microscopes with progressively higher magnifications may be used. Metallographic analysis may also include an examination of the crystal structure using, for example, X-ray diffraction (XRD), energy dispersive X-ray (EDX), and energy dispersive spectrometry (EDS) techniques.

Surface topography Surface topography Composition

Electron microprobe Scanning electron microscopy (EDS) Electron difraction Microhardness Optical microscopy X-Ray topography Human vision

Composition Composition Crystal structure Mechanical properties Microstructure Crystal defects Macrostructure

Diameter of the atom

Precipitates

.

.

Optical interferometry Scanning electron microscopy Scanning transmission electron microscopy

Structural feature (scale range)

Micro cracks

2 µm 10 µm 100 µm 1 mm

Features detected Structure and composition Microstructure

Grain size

1 µm

Technqiues Atom probe field-ion microscope Transmission electron microscopy

Surface finish .

Scale 0.1 nm 0.5 nm 1 nm 2 nm 4 nm 7 nm 10 nm 100 nm

FIGURE 3.10 Correlation Between the Sizes of Structural Features of Metals and Techniques to Observe them.11

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3.3 Types of metals and alloys In the oil and gas industry several metals and alloys are used. Brief descriptions of metals and alloys commonly used in the oil and gas industry are provided in the following paragraphs.

3.3.1 Carbon steels Carbon steel is an alloy in which iron is the principal element, with a carbon content typically up to 2.5%. Carbon steel is the work-horse material in the oil and gas industry. At least 80% of all components in the oil and gas industry are made from carbon steel because it is inexpensive, readily available, and easily fabricated. Every effort is made to use it, even if process changes are required to obtain satisfactory service from carbon steel.

3.3.1a Microstructure12 The crystal structure of iron is BCC. The addition of small amounts of carbon produces an interstitial solid solution without changing the crystal structure, but addition of other elements and processes produce carbon steels with various microstructures (Table 3.2).13 Table 3.2 Microstructure of Carbon Steels13 Microstructure

Crystal Structure

Remarks

Ferrite (a-iron)

BCC

d-ferrite (d-iron)

BCC

Cementite (Fe3C) Pearlite Martensite

Complex orthorhombic Hexagonal Body-centered tetragonal

Austenite (g-iron)

FCC

Relatively soft low temperature phase; stable equilibrium phase Isomorphous with a-iron; high temperature phase; stable equilibrium phase Hard metastable phase Stable equilibrium phase Supersaturated solution of carbon in ferrite; Hard metastable phase: lath morphology when the carbon content is less than 0.6 wt %; plate morphology when the carbon content is greater than 1.0wt%; and mixture of both these morphologies between 0.6 and 1.0wt%. Relatively soft medium-temperature phase; stable equilibrium phase Hard metastable microconstituent; nonlamellar mixture of ferrite and cementite on an extremely fine scale; upper bainite formed at higher temperatures has a feathery appearance; lower bainite formed at lower temperatures has an acicular appearance. The hardness of bainite increases with decreasing temperature of formation

Bainite

Reproduced with permission from ASM International.

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143

i. Ferrite The ferrite microstructure is the major constituent of carbon steels. It is essentially iron, containing less than 0.005% of carbon at room temperature. Because of the low carbon content, ferrite microstructure is soft and can easily be deformed. Ferrite may however contain other alloying elements such as manganese or silicon. Figure 3.11A presents a typical ferrite microstructure.14 Dimensionally the ferrite appears equal in all directions (equiaxed morphology). This form of ferrite may also be known as polygonal ferrite. In cold-rolled carbon steels the ferrite may have an elongated morphology (Figure 3.11B). In heat-treated carbon steels the ferrite may have an epitaxial morphology (Figure 3.11C), i.e., the new ferrite phase grows epitaxially on the existing ferrite grains. In some very low carbon containing steels, veins of iron may appear within the ferrite microstructure (Figure 3.11D).

(A)

(B)

(C)

(D)

FIGURE 3.11 Ferrite Microstructures of Carbon Steel.14 (A) Equiaxed morphology; (B) Elongated morphology; (C) Epitaxial morphology; and (D) Morphology with veins. Reproduced with permission from ASM International.

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ii. Cementite The iron carbide phase is known as cementite. Any carbon exceeding the solubility limit in the ferrite phase precipitates in the form of iron carbide (Fe3C). Cementite may appear in the ferrite microstructure as a massive, medium, or dispersed phase (Figure 3.12).15 Cementite is hard, brittle, and detrimental to formability of carbon steel, hence the formation of this phase is not preferred in low carbon steel.

iii. Pearlite The pearlite phase is another common constituent in carbon steel. Pearlite consists of alternating phases of ferrite and cementite phases (Figure 3.13).16 Ferrite and cementite may form a plate-like, lamellar morphology.

iv. Martensite The martensite phase in essence is ferrite supersaturated with carbon. It is a hard constituent. It is not desired in low carbon steel, but may be a desirable in some special low carbon steels. Martensite islands are commonly found in dual-phase steel (Figure 3.14).17

v. Austenite Austenite is not a commonly occurring microstructure in low carbon steel at room temperature. However, it may appear in special, high strength, carbon steels and in dual-phase steels (Figure 3.15).18 The presence of an austenite phase improves ductility.

FIGURE 3.12 Cementite Microstructure of Carbon Steel.15 Reproduced with permission from ASM International.

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145

FIGURE 3.13 Pearlite Microstructure of Carbon Steel.16 Reproduced with permission from ASM International.

vi. Bainite Bainite also consists of two phases: ferrite and cementite, but its appearance is entirely different from that of pearlite (Figure 3.16).19 Bainite may be classified into upper and lower bainite because they respectively form at upper and lower temperatures during the transformation from austenite. The upper bainite microstructure consists of needles or laths of ferrite with carbides at the lath boundaries, and in lower bainite the carbides are present within the ferrite lath itself. Sophisticated equipment such as TEM may be required to differentiate the forms of bainite.

3.3.1b Production Carbon steel is produced as ingots, or flat plate or sheet. Until the 1960s carbon steels were produced with strengths up to X-52 (where X indicates the yield strength of carbon steel; X-52 means the yield strength of the carbon steel is 52,000 psi) (see section 3.4.2 for specification) and were delivered in the as-rolled or normalized condition. The process of controlled rolling was discovered in the early 1960s and was applied to X-56 carbon steel upwards. Subsequently, higher strength steels (currently up to X-120) were produced. Figure 3.17 presents the development of various grades of carbon steel.20 However, currently only up to X-80 strength steels are commercially used.

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FIGURE 3.14 Martensite Microstructure of Carbon Steel.17 Reproduced with permission from ASM International.

FIGURE 3.15 Austenite Microstructure of Carbon Steel.18 Reproduced with permission from ASM International.

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147

FIGURE 3.16 Bainite Microstructure of Carbon Steel.19 Reproduced with permission from ASM International.

FIGURE 3.17 Advancement of Carbon Steel Production.20

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In general the properties of carbon steel are optimized by two methods: micro-alloying and heat treatment. During the production of carbon steel, impurities such as oxygen, sulfur, phosphorous, nitrogen, tin, antimony, and arsenic may be incorporated. Some of these elements diminish the properties of steel. Some other elements are intentionally added to enhance the properties of steel. Table 3.3 presents the effect of various alloying elements.21 Carbon steel is often heat-treated into the austenite region (see section 3.3.1) and then cooled to room temperature. If the steel is cooled in the heating furnace itself, then the process is known as ‘annealing’ (annealing normally produces soft steel with cementite or pearlite microstructures which are not the preferred microstructure phases); if the steel is removed from the furnace and allowed to cool in air, then the process is known as ‘normalization’; and if the steel is rapidly cooled by forcing air or by immersion in water or oil, then the process is known as ‘quenching’. Steel is often reheated and

Table 3.3 Effect of Micro-Alloying Elements on the Properties of Carbon Steel21 Element

Primary Effect

Silicon

• • • • • • • •

Aluminum Titanium Molybdenum

Nickel Manganese

Chromium Tungsten

Columbium and Vanadium Copper Vanadium

Niobium )

Improves mechanical properties Increases strength Improves hardenability Improves corrosion resistance Strengthens the matrix Improves corrosion resistance Improves hardenability Improves high temperature strength

• Improves toughness • Improves hardenability • Increases hardenability

• • • •

Improves corrosion resistance Improves oxidation resistance Increases strength Increases resistance to softening

Improves hardenability Improves resistance to softening Increases hardenability Improves corrosion resistance in the presence of chromium) • Increases yield strength • Improves corrosion resistance in the presence of chromium)

• • • •

Secondary Effect • Improves corrosion resistance

• Deoxidizer • Resistance to softening. • Improves corrosion resistance in the presence of chromium) • Promotes localized corrosion • Prevents formation of free sulfur and FeS by forming MnS. But MnS may become location for pit initiation • Increases high temperature strength • Increases abrasion resistance • Contributes to increase in hardenability • Improves high temperature strength

• May promote localized corrosion

These elements combine with carbon to form their respective carbides; consequently Cr remains uncombined increasing the corrosion resistance of the alloy

3.3 Types of metals and alloys

149

this process is referred to as ‘tempering’. The steel is tempered at a temperature below a temperature known as ‘critical temperature’. This temperature depends on the alloy and the rate of heating, but mostly it is below 1,360 F (738 C). Micro-alloying, tempering, and microstructure are all interrelated and are optimized to produce steel with desired properties.

3.3.1c Fabrication Most infrastructures used in the oil and gas industry are in the form of pipe, i.e., a structure that can be defined by pr2L where r is the radius and L is the length. Pipe may be produced from flat plate (by welded pipe) or round ingots (seamless pipe). To produce welded-pipe, flat plates (known as skelp) are pressed into a U-shape by a U-press, then into an O-shape by an O-press, and then longitudinally welded. Some common methods of welding include electric resistance welding (ERW), submerged arc welding (SAW), and double-submerged arc welding (DSAW). The resultant pipe is normally 40 feet (12 meters) in length. Pipe may also be fabricated by a spiral welding process. Spiral welding process facilitates the manufacture of large diameter pipe from narrower plates or skelp. The spiral welding technology has been used extensively in Canada and Europe for high pressure gas pipelines in grades up to X70. Pipes can also be fabricated without welding. Such pipes are known as seamless pipes, and are homogeneous in the circumferential direction. Seamless pipe can be manufactured by three processes: plug mill, mandrel mill, and extrusion. In all three processes, the ingot of steel (weighing in tons) is heated typically to 2,370 F (1,300 C). In the plug mill process, a hole is pierced into the center of the ingot and expanded by a rotary elongator. This process typically produces pipe between 6 and 16 inches (150 and 400 mm) in diameter. In the mandrel process, a mandrel is used instead of a rotary elongator. This process typically produces pipe of diameter between 1 and 6 inches (25 and 150 mm). In the extrusion process the steel ingot is extruded by a steel die. The extrusion process is used to produce high alloy steel pipe, heavy-wall pipe, and large diameter pipe. These line pipes (produced by longitudinal welding, spiral welding, or without welding [seamless] processes) are joined in the field by girth welding to produce a pipeline. Several codes and standards have been developed to manufacture line pipes for various applications (see sections 3.4.1 and 3.4.2). The maximum allowable operating pressure (MAOP) depends on the material and the operating temperature. Table 3.4 presents MAOPs for carbon steel pipes.22 Coiled tubing is increasingly being used in the oil and gas industry. Small diameter (typically between 235 and 750 mil (6 and 19 mm)), thin walled, low pressure, coil tubings are used as subsea umbilicals. The larger diameter (between 0.75 and 7 inch (19 and 178 mm)) coil tubings are used in drilling operations and in flow lines. They are manufactured by the same process that is used to manufacture line pipe by the ERW process. Almost all coil tubing are manufactured from carbon steel of various yield strengths including 70,000, 80,000, 90,000, and 100,000 psi (483, 552, 621, and 689 MPa). Unlike line pipe, coil tubing is not cut at specific lengths but is produced as a reel. Standards providing guidelines for using coil tubing include: • •

API RP 5C7, ‘Coiled Tubing Operations in Oil and Gas Well Services’ and Industry recommended practice (IRP), Vol. 22, ‘Coiled Tubing Operations’, Canada

Flexible pipes are also increasingly being used in applications such as offshore flowlines, risers, jumpers, expansion joints, production pipes, gas lift pipes, gas injection lines, and water injection

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Table 3.4 Maximum Allowable Operating Pressure for Carbon Steel Pipe22 Maximum Allowable Operating Pressure (psi)) Nominal Pipe Size (in.)

Schedule 40

Schedule 80

Schedule 160

4830 3750 2857 2112 1782 1948 1693 1435 1258 1145 1006

6833 5235 3947 3000 2575 2702 2394 2074 1857 1796 1587

e 6928 5769 4329 4225 3749 3601 3370 3191 3076 2970

¼ ½ 1 1½ 2 2½ 3 4 5 6 8 Based on allowable stress of 15,000 lb/in.2

)

lines. Flexible pipes can be easily installed; laid following the contours of the seabed; have no field joints; and are tolerant to misalignments during installation without losing integrity. The installed pipes are retrievable and reusable. However the material cost is higher than equivalent strength of carbon steel pipe and they cannot withstand external pressure beyond depths of about 6,562 feet (2,000 m). Typical layers of flexible pipes (Figure 3.18) include carcass, inner liner, pressure armor, tensile armor, outer sheath, and additional layers.23 The carcass is manufactured from a metallic strip. It has a spirally wound, interlocking structure. It provides mechanical strength to protect the inner layer from collapse, pigging tools, and abrasive particles. The inner liner is an extruded polymer layer. It confines the fluids being transferred. Pressure armor consists of several layers of helically wound metallic wires and metallic strips. It provides resistance to radial loads from both internal and external sources. Tensile armor also consists of layers of helically counter wound metallic wires. It provides resistance to axial tension loads. Similar to the inner liner, the outer sheath is an extruded polymer layer. It shields the metallic parts of the pipe from corrosion. Flexible pipe may also contain anti-wear and insulation layers. The common end fittings of flexible pipe are flanges and hydraulic subsea connectors. The ends of the flexible pipes are also fitted with bend restrictors to prevent excessive bending. Flexible pipes have an allowable bend radius, bending beyond this will compromise its integrity. Standards providing guidelines for the design and operation of flexible pipe include: • • • • •

API API API ISO API

RP 17B, ‘Recommended Practice for Flexible Pipe’ RP 17J, ‘Specification for Unbonded Flexible Pipe’ RP 17K, ‘Specification for Bonded Flexible Pipe’ 10420, ‘Flexible Pipe Systems for Subsea and Marine Riser Applications’ RP 2RD, ‘Design of Risers for Floating Production Systems and Tension-Leg Platforms’

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151

FIGURE 3.18 Schematic Diagram of Typical Flexible Pipes (1. Carcass; 2. inner liner; 3. Pressure armor; 4. Tensile armor; and 5; Outer sheath).23 Reproduced with permission from Elsevier.

3.3.2 Cast irons24 Cast irons are alloys of iron, carbon (greater than 2.0 or 2.5%) and silicon. Because of the presence of three phases (Fe, C, and Si), cast iron is a ternary system (carbon steel is a binary system). Other commonly added elements include manganese, phosphorous, nickel, cerium, and magnesium. The microstructure of cast irons is heterogeneous, and as a consequence there is no relationship between the hardness and the tensile strength. Cast irons are less forgiving than carbon steel; therefore selection and application of cast iron should be performed carefully. Because of their excellent fluidity and relatively low melting points, cast irons can be used to develop intricate shapes. In the oil and gas industry, cast irons are used for assembling materials including valves, pumps, packers, and plugs. The major classes of cast iron are gray, white, malleable, and ductile. Table 3.5 presents the general properties of different classes of cast iron.25 The corrosion properties of cast iron depend on the alloying element present. With a proper alloying element, the corrosion resistance of cast iron can be equal to that of stainless steel and nickel alloys. Some elements used to increase the resistance of cast Table 3.5 Mechanical Properties of Different Classes of Cast Iron25 Cast Iron Gray White Malleable Ductile

Tensile Strength, ksi 20e80 13e90 50e100 55e175

Hardness, (Brinell) 140e350 600 110e270 130e300

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iron are silicon, nickel, chromium, copper, and molybdenum. Table 3.6 presents the influence of these elements on the corrosion of cast iron.26

3.3.2a Gray This cast irons exhibit a characteristic gray appearance when fractured, due to the presence of flakes of graphite in a ferrite matrix (Figure 3.19).27 Gray irons have lower ductility, but higher machinability. When the carbon content is less than 4.3%, the gray alloys are known as hypoeutectic, and when the carbon content is higher than 4.3% they are known as hypereutectic. The microstructure of gray cast irons is predominantly pearlite, but gray cast irons with pearilite-ferrite or ferrite structures also exist.

3.3.2b White Unlike other cast irons, the white cast irons do not contain graphite (Figure 3.20),28 but they do contain higher concentration of iron carbide and smaller concentrations of nickel and chromium. The typical microstructure of white cast irons is martensite or cementite. White cast irons are hard, wear-resistant, but brittle.

3.3.2c Malleable Malleable cast irons are produced from white cast iron by heating it and holding it at 1,500–1,750 F (816–954 C) and then slowly cooling through a temperature range of 1,300–1,400 F (704–760 C). Malleable cast irons may be produced with three microstructures; ferritic, pearlitic (martensitic) and ferritic-pearlitic. Malleable case irons have high strength and high wear resistance.

3.3.2d Ductile Addition of magnesium or cerium to molten gray iron produces cast iron with high ductility. This process produces spherical shaped graphite flakes (Figure 3.21).29 The microstructure of ductile irons is pearlite or pearlite-ferrite. Ductile cast irons have higher impact resistance and have higher elastic behavior. They can be heat-treated to increase tensile strength.

3.3.3 Alloy steels Alloy steel is a type of steel alloyed with several elements such as molybdenum, manganese, nickel, chromium, vanadium, silicon, and boron. These alloying elements are added to increase strength, hardness, wear resistance, and toughness. The amounts of alloying elements may vary between 1 and 50%. Alloy steels may be classified into two groups: low alloy steel and high alloy steel. The boundary between low alloy and high alloy steel is commonly accepted as 5% alloying element. For all practical purposes in the oil and gas industry, alloy steel means low alloy steel.

3.3.4 Copper alloys30 Alloys containing more than 99.3% copper are designated as copper. Other alloys of copper include high-copper alloys, brasses, bronzes, copper-nickel alloys, nickel-silver alloys, and brazing alloys. Table 3.7 presents typical compositions of copper alloys.31 Corrosion protection of copper and copper alloys is due to the formation of adherent surface layers, predominantly cuprous oxide (Cu2O).

3.3 Types of metals and alloys

153

Table 3.6 Effect of Alloying Elements on the Corrosion Property of Cast Irons26 Alloying Element

Amount

Effect

Silicon

• Addition of silicon between 3 to 14% drastically increases corrosion resistance. • Beyond 14e16% silicon makes the cast iron brittle.

Nickel

• Nickel up to 4% in combination with chromium increases the corrosion resistance. • Addition of nickel alone up to 12% or more is required to increase the corrosion resistance. • High nickel cast irons (between 13.5 to 36%) have high resistance to wear, corrosion, and heat. • Chromium alone or in combination with nickel and/or silicon increases the corrosion resistance. • Addition of chromium between 15 to 35% improves the corrosion resistance of cast iron in oxidizing environments. • Higher concentration of chromium reduces the ductility of cast iron. • Addition of copper between 0.25 and 1% increases the corrosion resistance of cast iron. • In some high nickel-chromium cast irons the copper content may be up to 10%. • Molybdenum is added mainly to increase the strength and structural uniformity, but 3 to 4% molybdenum also increases the corrosion resistance. • In some high-silicon cast irons, 1% molybdenum is enough to decrease the corrosion rate.

• Silicon promotes formation of adherent surface films on cast iron which decreases the corrosion rate. • Corrosion rate may be relatively high initially until the surface layer is formed. • Nickel facilitates the formation of a protective oxide layer on the surface.

Chromium

Copper

Molybdenum

• Chromium increases the corrosion resistance of cast iron by refining the microstructure and by forming protective oxide layer. • Chromium oxide resists corrosion in the oxidizing environment only, but not in the reducing environment because of the destruction of these oxides. • Exact mechanism by which copper reduces the corrosion rate of cast iron is not known.

Copper and its alloys have high electrical and thermal conductivity, as well as good resistance to corrosion by steam. Therefore they are used for fabricating heat exchangers and condensers. Copper-nickel alloys are extensively used for fabricating components for application at elevated temperatures and pressures. Table 3.8 presents general applications of copper alloys in the oil and gas industry and their corrosion behavior.32

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FIGURE 3.19 Microstructure of Gray Cast Iron.27 Reproduced with permission from ASM International.

FIGURE 3.20 White Cast Iron.28 Reproduced with permission from ASM International.

3.3 Types of metals and alloys

155

FIGURE 3.21 Ductile Cast Iron.29 Reproduced with permission from ASM International.

Table 3.7 General Classes of Copper Alloys31 Classes

UNS #

Example

Typical Composition

Copper High-copper alloy Brass Bronze

C10100 C17200

Oxygen-free electronic copper Beryllium copper

C26800 C63000

Yellow brass Aluminum bronze

Copper-nickel

C71900

Copper-nickel

Nickel-silver

C74500

Nickel-silver, 65e10

Brazing alloys

C55284

BCuP-5 brazing alloy

99.3% min copper 1.9% beryllium, 0.4% cobalt, and balance copper 66% copper and 34% zinc 82.2% copper, 10% aluminum, 3% iron, and 4.8% nickel 30.5% nickel, 2.6 chromium, and balance copper 65% copper, 10% nickel, and 25% zinc 80% copper, 15% silver, and 5% phosphorus

3.3.5 Stainless steels33 Stainless steels contain a minimum of 12% chromium. They also contain nickel in excess of 6% and molybdenum. Chromium increases corrosion resistance, nickel improves mechanical and fabricating properties, and molybdenum increases pitting resistance and high temperature strength of stainless steels. The corrosion resistance of stainless steels is due to the formation of a barrier of true oxide separating the metal from the surrounding environment. The extent of protection depends on the thickness, coherence, and adhesion onto the metal surface of the oxide layer, as well as on the diffusion rate of corrosive species and metal irons across it. The presence of oxygen is essential for the corrosion resistance of stainless steels. Depletion of oxygen weakens the oxide layer, making stainless steel susceptible to corrosion.

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Table 3.8 Some Typical Application of Copper and Copper Alloys in the Oil and Gas Industry32 Copper Alloy

UNS Number

Copper-nickel (70e30)

C71500

Copper-nickel (70e30)

C71640

Copper-nickel (85e15)

C72200

Copper-nickel (90e10)

C70600

High-copper alloy (Beryllium copper)

C17200

Application • For fabrication of refinery condenser tube in high-heat flux and low-water-velocity application • For fabrication of many components exposed to seawater • For fabrication of many components exposed to seawater • For fabrication of tubes and pipes for transporting ammonia, amines, water (containing nitrates, oxides of sulfur, or mercury) and water vapor. • For fabrication of heatexchanger tubes. • For fabrication of gauges used in downhole pressure and temperature measurement

Type of Corrosion (see Chapter 5) Preferential dissolution of nickel (denickelfication)

Crevice corrosion

Crevice corrosion

Stress-corrosion cracking

General corrosion

Based on their microstructure, stainless steels can be broadly classified into austenitic, ferritic, martensitic, duplex, and precipitation hardened stainless steels. In addition, several secondary phases may also be observed (Table 3.9).34

3.3.2a Austenitic stainless steel The minimum chromium content of austenitic stainless steels is 16%. Other elements added to stabilize the austenitic microstructure at room temperature include carbon, nitrogen, nickel, and manganese. Austenitic stainless steel may also contain minor amounts of ferrite microstructure, because those elements that stabilize the austenitic microstructure also stabilize the ferritic microstructure. Austenitic stainless steels cannot be hardened by heat treatment, but their properties can be altered by cold-work. Austenitic stainless steels are classified into four categories on the basis of their mechanical properties (Table 3.10).35 The austenitic stainless steels have higher corrosion resistance than ferritic and martensitic stainless steels. Commonly used austenitic stainless steels used in the oil and gas industry are American Iron and Steel Institute (AISI) 302, 304, and 316.

3.3.2b Ferritic stainless steel Ferritic stainless steels have a ferritic microstructure and small amounts of other secondary phases such as M23C6 (Table 3.9). They contain enough chromium and other alloying elements to stabilize the ferritic phase at room temperature. The carbon and nitrogen content is kept to a minimum. Similar to

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157

Table 3.9 Secondary Phase Constituents in Stainless Steels34 Phase

Remarks

M23C6 M6C M7C3 MC

Most commonly observed carbide in austenitic stainless steels Observed in austenitic stainless steels containing substantial molybdenum or niobium Observed in martensitic stainless steels Stable carbide with some nitrogen. Observed in stainless steels with additions of titanium or niobium Rapidly formed from sigma-ferrite and also from austenitic stainless steels Observed in stainless steels containing substantial molybdenum

Sigma (s) Chi (c) (various compositions) Laves (h)

Observed in austenitic stainless steels with substantial amounts of molybdenum, titanium, or niobium

Table 3.10 Classes of Austenitic Stainless Steel35

Classification

Tensile strength, psi

Minimum yield strength, psi

Minimum

Maximum

¼ hard ½ hard ¾ hard Fully hard

75,000 110,000 135,000 140,000

125,000 150,000 175,000 185,000

austenitic stainless steel, ferritic stainless steel cannot be hardened by heat treatment. They are used either in the annealed condition or in the cold-work condition. The ferritic stainless steels are susceptible to embrittlement when heated to 400 to 540 C (750 to 1005 F). This phenomenon may also be known as 475 C- (885 F-) embrittlement.

3.3.2c Martensitic stainless steel Martensitic stainless steels contain more than 10.5% chromium, along with other minor elements such as carbon, nitrogen, nickel, and manganese. Martensitic alloys can be hardened by heat treatment. They have both strength and corrosion resistance, and are increasingly used to manufacture downhole tubulars and pipelines.

3.3.2d Duplex stainless steel Stainless steel with 22% Cr is commonly known as duplex stainless steel. Typical amounts of chromium may vary between 22 and 25%. Duplex stainless steel may also contain approximately 5% Ni, 3% Mo, and nitrogen. Duplex stainless steels have 50% each of ferrite and austensite phases – hence the term ‘duplex’. Those containing higher percentages of Ni and Mo may be known as super duplex stainless steels. The fine microstructure of duplex stainless steels provides strength (70,000 to 80,000 psi) and toughness. Duplex stainless steels exhibit better corrosion resistance than both ferritic and austentitic stainless steel. They cannot be hardened further by heat treatment. When they are

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Table 3.11 Some Commonly Used Nickel Alloys36 Composition Alloy

Ni

C

Fe

Mn

Nickel Nickel 270Ô Monel 400Ô Hastelloy BÔ

99.5 99.98 66.5 63.5

0.08 0.01 1.0

0.2

0.18

1.25 5.0

1.0

Incoloy 901Ô

42.7

0.05

34.8

200Ô

Others

Cu 31.5 Co 2.5 Cr 1.0 Mo 28.0 Cr 13.5 Ti 2.5 Mo 6.2 Al 0.25

improperly heat-treated or thermally processed, they precipitate several detrimental phases. They are widely used in the oil and gas industry.

3.3.2e Precipitation hardened stainless steel The precipitation hardened stainless steels are produced by an aging treatment that precipitates very fine secondary phase particles. The secondary phases used to produce precipitates include aluminum, copper, titanium, molybdenum, and niobium. The parent phase may be austenitic, semiaustenitic, and martensitic. Commonly used precipitation hardened stainless steels include 17–4 Precipitation Hardened (PH) (containing nominally 17% Cr–4% Ni), 15–5 PH, and 17–7 PH.

3.3.6 Nickel alloys Nickel alloys cover a wide range of chemical compositions, microstructures, and mechanical properties. In general, they have higher corrosion resistance than the stainless steels. Table 3.11 presents some commonly used nickel alloys.36 Most Ni alloys are not heat-treatable but can be strengthened by cold-work. The nickel alloys may possess non-metallic inclusions (principally oxides) and numerous secondary phases including Nig, Nih, Nig’, Nim, and Nis, carbide and carbo-nitride. Some phases of nickel alloys are too small to observe using the light optical microscope and are observable only using TEM. Nickel itself possesses only moderate resistance to corrosion, but its resistance increases when alloying elements such as copper, molybdenum, chromium, iron, and tungsten are added. Nickel alloys are more resistant than stainless steels in many environments including reducing environments and chloride-induced pitting (see Chapter 5).

3.3.7 Titanium alloys37 Titanium is allotropic in nature. At room temperature, its crystal structure is HCP (commonly referred to as the alpha phase) and at 883 C (1,621 F) its crystal structure is BCC (commonly referred to as the beta phase). The common alloying elements of Ti are aluminum, nickel, vanadium, molybdenum, chromium, platinum, and tin. Elements such as aluminum, tin, and oxygen increase the temperatures at

3.4 Classification of metals and alloys

159

which the alpha phase is stable, whereas elements such as vanadium and molybdenum decrease the temperatures at which the beta phase is stable. Titanium may also exist as a mixture of alpha and beta forms. In general, titanium alloys are classified as alpha, near alpha, alpha þ beta, near-beta, and beta. Unlike Ni alloys, the strength of Ti alloys can be increased by heat treatment. Titanium alloys of yield strengths as high as 180,000 psi (1,241 MPa) can be produced by heat treatment. However, it should be noted that only alpha þ beta, near-beta, and beta alloys can be heat-treated. Alpha and near alpha alloys cannot be heat-treated. Titanium offers higher strength at a lower weight than steel. Titanium is very reactive and has great affinity for oxygen. Fortunately, the resultant titanium oxide (TiO2) forms as a stable, continuous, highly adherent, and protective layer on the titanium surface. As a result the corrosion resistance of titanium is very high. Even if the protective layer is removed, it can reform, i.e., the titanium oxide layer can self-heal, provided there are sufficient amounts of oxygen. The nature, composition, and thickness of the surface layer depends on the titanium alloy and the environment. In most environments the titanium oxide consists of TiO2, Ti2O3, and TiO.

3.3.8 Corrosion resistant alloys The copper alloys (section 3.3.4), stainless steels (section 3.3.5), nickel alloys (section 3.3.6), and titanium alloys (section 3.3.7) are collectively known in the oil and gas industry as corrosion resistant alloys (CRAs). The CRAs are used in environments where the corrosion rate of carbon steel is high even with implementation of mitigation strategies (see Chapter 7).

3.4 Classification of metals and alloys There are thousands of metals and alloys within the groups discussed in section 3.3. It would be extremely difficult to identify all of them without a tracking or classification system, so various standard-making organizations have developed guidelines for classifying and identifying metals and alloys. Some commonly used standards in the oil and gas industry have been developed by: American Iron and Steel Institute (AISI); American Petroleum Institute (API); American Society of Testing and Materials (ASTM); American Society of Mechanical Engineers (ASME); Association Franc¸aise de Normalisation or French National Organization for Standardization (AFNOR); British Standards Institute (BSI); Canadian Standards Association (CSA); Chinese National Standards (GB); Deutsches Institut fu¨r Normung (DIN) (Germany Standard); European Committee for Standardization (CEN); International Organization of Standardization (ISO); Japanese Standard (JIS); and Unified Numbering System (UNS). Some numbering systems are discussed in the following sections as illustrations of designations to use to track metals and alloys. The designation by other associations should be consulted as appropriate.

3.4.1 AISI In AISI, a four-number designation is used for the alloys. The first two numbers represent the major alloying elements, and the last two numbers represent the nominal weight percent of carbon

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(in increments of 0.01%). For example, AISI 1018 is the designation for carbon steel containing 0.18 wt% carbon. Table 3.12 presents the designation of alloys in the AISI system. Because the AISI numbers allow easy recognition of the basic chemistry of the alloy, they are commercially popular. In many instances, the AISI designation is used without reference to AISI.

3.4.2 API In the API system, the materials are classified on the basis of their applications. Table 3.13 presents some API specifications. API also identifies several “product specification levels” (or grades) within each specification. For example, under API 5CT there are several grades including H40, J55, K55, N80, R95, M65, L80, C90, T95, C110, P100, and Q125 and under API 5L there are several “X” grades

Table 3.12 AISI Classification of Metals and Alloys Metal or Alloy

AISI Classification

Plain carbon steel Free cutting steel Free cutting steel: high sulfur and/or phosphorus Manganese steel: Mn 1.75% Plain carbon steel: Mn 0.75e1.65% Nickel steels: Ni 3.5e5.0% Nickel steels: Ni 3.5e5.0% Nickel-Chromium steels: Ni 1.25e3.5%, Cr 0.65e1.57% Nickel-Chromium steels: Ni 1.25e3.5%, Cr 0.65e1.57% Nickel-Chromium steels: Ni 1.25e3.5%, Cr 0.65e1.57% Molybdenum steels: Mo 0.20e0.30% Chromium-molybdenum steels: Cr 0.8e1.1%, Mo 0.15e0.25% Ni 1.65e2.00, Cr 0.40e0.90, Mo 0.20e0.30 Ni 0.90e1.20, Cr 0.35e0.55, Mo 0.15e0.25 Ni 0.20e0.40, Cr 0.35e0.55, Mo 0.08e0.15 Ni 0.40e0.70, Cr 0.40e0.60, Mo 0.15e0.25 Ni 0.40e0.70, Cr 0.40e0.60, Mo 0.20e0.30 Ni 0.30e0.60, Cr 0.30e0.50, Mo 0.08e0.15 Ni 0.85e1.15, Cr 0.70e0.90, Mo 0.20e0.30 Nickel-Molybdenum steels: Ni 1.55e3.5%, Mo 0.20e0.30% Nickel-Molybdenum steels: Ni 1.55e3.5%, Mo 0.20e0.30% Chromium steels: Cr 0.25e1.05% Chromium steels: Cr 0.25e1.05% Chromium-Vanadium steels: Cr 0.8e0.95%, V 0.1e0.15% Tungsten-Chromium steels: W1.75%, Cr 0.75% Silicon-manganese steels: Si 1.2e2.2%, Mn 0.65e0.87% Boron steels Leaded steels

10XX 11XX 12XX 13XX 15XX 23XX 25XX 31XX 32XX 33XX 40XX 41XX 43XX 47XX 81XX 86XX 87XX 94XX 98XX 46XX 48XX 50XX 51XX 61XX 72XX 92XX XXBXX XXLXX

3.4 Classification of metals and alloys

161

Table 3.13 API Specifications of Materials API Specification

Description/Title

2B 2C 2F 2H

Structural Steel Pipe Offshore Cranes Mooring Chain e Flash Welded Chain; Forged Connecting Links Carbon Manganese Steel Plate for Offshore Platform Tubular Joints e Grade 42 Steel Plate; Grade 50 Steel Plate As-Rolled Carbon Manganese Steel Plate with Improved Toughness for Offshore Structures e Steel Plate, Grade 2MT1 Rolled Shapes with Improved Notch Toughness e Steel Rolled Shapes Steel Plates for Offshore Structures Produced by Thermo-Mechanical Control Processing e Grade 50 Steel Plate; Grade 60 Steel Plate Steel Plates, Quenched-and-Tempered, for Offshore Structures e Grade 50 Steel Plate; Grade 60 Steel Plate Drilling and Well Servicing Structures e Derricks; Masts; Crown Block Assemblies; Substructures; at PSL 1 and 2 Threading, Gauging, and Thread Inspection of Casing, Tubing and Line Pipe Threads e Thread Gauges Casing and Tubing e Manufacture of Casing or Tubing Plain End; Manufacture of Casing or Tubing Threaded and Coupled; Manufacture of Casing or Tubing Pup Joints; Manufacture of Casing or Tubing Couplings; Manufacture of Accessories; Process of Casing or Tubing Plain End; Process of Casing or Tubing Threaded and Coupled; Threading at Groups 1, 2, 3 and 4 Drill Pipe - Drill Pipe Body; Tool Joints; Drill Pipe (Assembly) Line Pipe e Manufacture of Line Pipe e Plain End at PSL 1; Manufacturer of Line Pipe e Plain End at PSL 2; Manufacturer of Line Pipe e Threaded and Coupled; Manufacturer of Line Pipe Couplings; Processor of Line Pipe e Plain End at PSL 1; Processor of Line Pipe e Plain End at PSL 2; Processor of Line Pipe e Threaded and Coupled; Threader CRA Line Pipe e Manufacture of Alloy Pipe; Processor of Alloy Pipe Coiled Line Pipe e Coiled Line Pipe CRA Clad or Lined Steel Pipe e Manufacture of Clad Steel Pipe; Manufacture of Lined Steel Pipe; Process of Clad Steel Pipe; Process of Lined Steel Pipe Wellhead and Christmas Tree Equipment e Manufacture of: Casing and Tubing Heads; Cross-Over Connectors; Tubing Head Adapters; Top Connectors; Tees and Crosses; Fluid-Sampling Devices; Adapter and Spacer Spools; Casing and Tubing Hangers; Valves; Chokes; Surface and Underwater Safety Valves; Surface and Underwater Safety Valve Actuators; Back Pressure Valves; Flanged Connectors; Threaded Connectors; Other End Connectors; Bullplugs; Valve Removal Plugs; Actuators; Ring Joint Gaskets at PSL 1 through 4 Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Use e Testing Agency Pipeline Valves (Steel Gate, Plug, Ball, and Check Valves) e Gate Valves; Plug Valves; Ball Valves; Check Valves

2MT1 2MT2 2W 2Y 4F 5B 5CT

5DP 5L

5LC 5LCP 5LD 6A

6AV1 6D

Continued

162

CHAPTER 3 Materials

Table 3.13 API Specifications of Materials Continued API Specification

Description/Title

6DSS

Subsea Pipeline Valves e Subsea Gate Valves; Subsea Plug Valves; Subsea Ball Valves; Subsea Check Valves End Closures, Connectors and Swivels e Pipeline Closures; Connectors; Couplings; Misalignment Devices (Swivels); Split Mechanical Fittings Rotary Drilling Equipment e Kelly Valves; Kellys; Drill Stem Subs; Drill Collars; Heavy Weight Drill Pipe; Roller Bits; Blade Drag Bits; Diamond Bits; Precise Drilling Component (PDC) Bits; Threading for Rotary Shouldered Connections Threading and Gauging of Rotary Shouldered Thread Connections e Rotary Shouldered Connection Gauges Internal-Combustion Reciprocating Engines for Oil Field Service Oil Field Chain and Sprockets e Roller Chain Drilling Equipment e Rotary Tables, Kelly Bushings, Master Bushings, Rotary Slips, Rotary Hoses, Slush Pump Components, Draw-works Components, Spiders Not Capable of Use as Elevators, Manual Tongs, Safety Clamps Not used as Hoisting Devices, Power Tongs Drill String Non-Return Valves, Non-Return Valve Subs, Non-Return Valve Landing Nipples, Non-Return Valve Equalizing Heads Drilling and Production Hoisting Equipment e Hoisting Sheaves, Traveling Blocks; Block-to-Hook Adapters, Connectors and Link Adapters, Drilling Hooks, Tubing and Sucker Rod Hooks; Elevator Links, Casing, Tubing and Drill Pipe Elevators, Spiders, Sucker Rod Elevators; Rotary Swivel Bail Adapters, Rotary Swivels; Deadline TieDowns; Sheave Compensators; Kelly Spinners, When Used as Tension Member; Tension Members of Subsea Handling Equipment Drilling and Production Hoisting Equipment e Hoisting Sheaves, Traveling Blocks and Hook Blocks; Block-to-Hook Adapters, Connectors and Link Adapters, Drilling Hooks, Tubing and Sucker Rod Hooks; Elevator Links, Casing, Tubing and Drill Pipe Elevators, Spiders (when capable of being used as elevators), Sucker Rod Elevators; Rotary Swivel Bail Adapters, Rotary Swivels; Power Swivels, Power Subs; Wireline Anchors; Heave Compensators; Kelly Spinners (when capable of being used as hoisting equipment); Pressure Vessels and Piping Mounted onto Hoisting Equipment at PSL 1 and 2 Wire Rope e Bright or Drawn-Galvanized Wire Rope; Mooring Wire Rope; Torpedo Lines; Well-Measuring Wire; Well-Measuring Strand; Wire Guy Strand; Structural Rope and Strand Well Cements e API Well Cement Class A, Type [O]; Class B, Type [MSR, HSR]; Class C, Type [O, MSR, HSR]; Class D, Type [MSR, HSR]; Class E, Type [MSR, HSR]; Class F, Type [MSR, HSR]; Class G, Type [MSR, HSR]; Glass H, Type [MSR, HSR] Bow-Spring Casing Centralizers e Casing Centralizers Subsurface Sucker Rods, Pumps and Fittings e Pump and Pump Parts; Pump and Pump Parts without Tubing or Sucker Rod Threads; Seating Cups Sucker Rods e Steel Sucker Rods; FRP Sucker Rods; Couplings, Subcouplings and Polished Rod Connections; Polished Rods; Polished Rod Clamps; Stuffing Box and Pumping Tees; Sinker Bars; Threads; Thread Gauges

6H 7e1

7e2 7B-11C 7F 7K

7NRV 8A

8C

9A

10A

10D 11AX 11B

3.4 Classification of metals and alloys

163

Table 3.13 API Specifications of Materials Continued API Specification

Description/Title

11D1 11E 11IW

Downhole Equipment e Packers; Bridge Plugs Pumping Units e Pumping Unit Structure; Pumping Unit Gear Reducer Independent Wellhead Equipment e Independent Wellheads; Top Connectors; Tubing and Casing Slip Hangers; Tubing and Casing Mandrel Hangers; Packoffs; Belled Nipples; Connector Flanges; Stripper Adapters Gas Lift Valves, Orifices, Reverse Flow Valves and Dummy Valves e Gas Lift Valves; Reverse Flow (Check) Valves; Orifice Valves; Dummy Valves; Wireline Retrievable Valve Mandrels Bolted Tanks for Storage of Production Liquids e Storage Tanks Field Welded Tanks for Storage of Production Liquids e Storage Tanks Shop Welded Tanks for Storage and Production Liquids e Storage Tanks Oil and Gas Separators e Separators Indirect Type Oilfield Heaters e Heaters; Shells; Coils Vertical and Horizontal Emulsion Treaters e Treaters Fiberglass Reinforced Plastic Tanks e FRP Tanks Oil-Well Drilling-Fluid Materials e Barite; Hematite; Bentonite; Attapulgite; Sepiolite; Starch; Drilling-Grade Xanthan Gum Subsurface Safety Valve Equipment e Subsurface Safety Valves; Testing Agency Lock Mandrels and Landing Nipples e Lock Mandrels; Landing Nipples High Pressure Fiberglass Line Pipe e Line Pipe; Couplings; Fittings; Flanges; Reducers and Adapters Polyethylene Line Pipe (PE) e (PE) Line Pipe Low Pressure Fiberglass Line Pipe Drill Through Equipment e Ram Blow-out Preventer (BOP); Ram Blocks, Packers, and/or Top Seals; Annular BOP; Annular Packing Units; Hydraulic Connectors; Drilling Spools; Adapters; Loose Connections; Clamps Choke and Kill Systems e Actuated Valve Control Lines; Articulated Choke & Kill Line; Drilling Choke Actuators; Drilling Choke Control Line exclusive of BOP Control Lines and Subsurface Safety Valve Control Lines; Drilling Choke Controls; Drilling Chokes; Flexible Choke and Kill Lines; Union Connections; Rigid Choke and Kill Lines; Swivel Joints; Choke and Kill Manifold Assemblies Control Systems for Drilling Well Control Equipment e Control Systems for Surface Mounted BOP Stacks; Hydraulic Control Systems for Subsea BOP Stacks; ElectroHydraulic/Multiplex Control Systems for Subsea BOP Stacks; Diverter Control Systems; Emergency Backup BOP Control Systems; Auxiliary Equipment Control Systems and Interfaces Marine Drilling Riser Equipment Drill through Equipment (Rotating Control Devices) Marine Drilling Riser Couplings e Marine Drilling Riser Couplings Recommended Practice for Flexible Pipe

11V1

12B 12D 12F 12J 12K 12L 12P 13A 14A 14L 15HR 15LE 15LR 16A

16C

16D

16F 16RCD 16R 17B

Continued

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CHAPTER 3 Materials

Table 3.13 API Specifications of Materials Continued API Specification

Description/Title

17D

Subsea Wellhead and Christmas Tree Equipment e Subsea Tree Equipment, Subsea Wellhead Equipment, Mudline Suspension System Equipment, Other Equipment at PSL 2, 3 Subsea Production Control Umbilicals e Hose Umbilicals; Electrical Umbilicals; Electro-Hydraulic Umbilicals Subsea Production Control Systems Unbonded Flexible Pipe Bonded Flexible Pipe General-Purpose Form-Wound Squirrel Cage Induction Motors - 250 Horsepower and Larger Check Valves Metal Plug Valves Bolted Bonnet Steel Gate Valves e Bolted Bonnet Steel Gate Valves Compact Steel Gate Valves, Globe Valves and Check Valves Corrosion Resistant Bolted Bonnet Gate Valves Metal Ball Valves Butterfly Valves Welded Tanks for Oil Storage e Steel Plates and Shop Built Tanks

17E 17F 17J 17K 547 594 599 600 602 603 608 609 650

including X52, X60, X70, and X80. In many instances, the API grades are used without reference to API specifications (e.g., X52, J55 etc.) The API system does not specify chemical requirements, but only mechanical requirements for specific applications. For example, many materials meet the mechanical requirements of API J55, but their chemistry may vary considerably.

3.4.3 ASTM Table 3.14 presents the ASTM designations of materials. The ASTM numbering system is not intuitive. The ASTM also publishes online a ‘Passport to Steel’ tool.38 This online database compares steel product specification standards by several standard-developing organizations.

3.4.4 ASME The ASME system of numbering follows ASTM numbering. The ASME numbering system assigns an ASTM number, then a prefix ‘S’ is added. Table 3.15 presents a comparison between ASME and ASTM standards for pipeline steels. ASME also standardizes pipe dimensions by schedule numbers. These schedule numbers indicate approximate values for 1,000 times pressure-stress ratios. The schedule is thus a measure of the pressure a pipe can withstand without deformation or failure. In general, thicker pipe would be able to withstand higher pressures. Therefore the schedule may appear synonymous with thickness, but it is not a direct measure of thickness (see Table 3.4). In this system, schedule number 10 (S.10) through schedule number 160 (S.160) are used for steel pipe.

3.4 Classification of metals and alloys

165

Table 3.14 ASTM Specifications for Materials ASTM Standard

Title

A53- 53M A-53B A105-A105M A106

Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless Standard Specification for Carbon Steel Forgings for Piping Applications Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service Standard Specification for Pipe, Steel, Electric-Fusion (Arc)-Welded (Sizes NPS 16 and Over) Standard Specification for Electric-Resistance-Welded Steel Pipe Standard Specification for Electric-Fusion (Arc)-Welded Steel Pipe (NPS 4 and Over) Standard Specification for Electric-Resistance-Welded Carbon Steel and CarbonManganese Steel Boiler and Superheater Tubes Standard Specification for Seamless Cold-Drawn Low-Carbon Steel HeatExchanger and Condenser Tubes Standard Specification for Carbon Steel Forgings, for General-Purpose Piping Standard Specification for Forged or Rolled Alloy-Steel Pipe Flanges, Forged Fittings, and Valves and Parts for High-Temperature Service Standard Specification for Seamless Carbon Steel Boiler Tubes for High-Pressure Service Standard Specification for Alloy-Steel and Stainless Steel Bolting Materials for HighTemperature Service Standard Specification for Carbon and Alloy Steel Nuts for Bolts for High-Pressure or High-Temperature Service, or Both Standard Specification for Seamless Carbon-Molybdenum Alloy-Steel Boiler and Superheater Tubes Standard Specification for Seamless Medium-Carbon Steel Boiler and Superheater Tubes Standard Specification for Seamless Ferritic and Austenitic Alloy-Steel Boiler, Superheater, and Heat-Exchanger Tubes Standard Specification for Electric-Resistance-Welded Carbon Steel HeatExchanger and Condenser Tubes Standard Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Moderate and High Temperature Service Standard Specification for Welded Austenitic Steel Boiler, Superheater, HeatExchanger, and Condenser Tubes Standard Specification for Electric-Resistance-Welded Ferritic Alloy-Steel Boiler and Superheater Tubes Standard Specification for Welded and Seamless Steel Pipe Piles Standard Specification for Copper-Brazed Steel Tubing Standard Specification for Seamless and Welded Ferritic and Martensitic Stainless Steel Tubing for General Service Standard Specification for Seamless and Welded Austenitic Stainless Steel Tubing for General Service

A134 A135 A139 A178/A178M A179/A179M A181/A181M A182/A182M A192/A192M A193/A193M A194/A194M A209/A209M A210/A210M A213/A213M A214/A214M A234/A234M A249/A249M A250/A250M A252 A254 A268/A268M A269

Continued

166

CHAPTER 3 Materials

Table 3.14 ASTM Specifications for Materials Continued ASTM Standard

Title

A270

Standard Specification for Seamless and Welded Austenitic Stainless Steel Sanitary Tubing Standard Specification for Seamless and Welded Austenitic Stainless Steel Pipes Standard Specification for Alloy/Steel Bolting Materials for Low Temperature Service Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service Standard Specification for Seamless and Welded Carbon and Alloy-Steel Tubes for Low Temperature Service Standard Specification for Seamless Ferritic Alloy-Steel Pipe for High-Temperature Service Standard Specification for Carbon and Low Alloy Steel Forgings, Requiring Notch Toughness Testing for Piping Components Standard Specification for Electric-Fusion-Welded Austenitic Chromium-Nickel Alloy Steel Pipe for High-Temperature Service Standard Specification for Carbon and Ferritic Alloy Steel Forged and Bored Pipe for High-Temperature Service Standard Specification for Seamless Austenitic Steel Pipe for High-Temperature Central-Station Service Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems Standard Specification for Wrought Austenitic Stainless Steel Piping Fittings Standard Specification for Welded Large Diameter Austenitic Steel Pipe for Corrosive or High-Temperature Service Standard Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Low Temperature Service Standard Specification for Seamless and Electric-Welded Low Alloy Steel Tubes Standard Specification for Centrifugally Cast Ferritic Alloy Steel Pipe for HighTemperature Service Standard Specification for Alloy-Steel Turbine-Type Bolting Material Specially HeatTreated for High-Temperature Service Standard Specification for General Requirements for Carbon, Ferritic Alloy, and Austenitic Alloy Steel Tubes Standard Specification for Centrifugally Cast Austenitic Steel Pipe for HighTemperature Service Standard Specification for High-Temperature Bolting Materials, with Expansion Coefficients Comparable to Austenitic Stainless Steels Standard Specification for Seamless and Welded Carbon, Ferritic, and Austenitic Alloy Steel Heat-Exchanger Tubes with Integral Fins Standard Specification for Cold-Formed Welded and Seamless Carbon Steel Structural Tubing in Rounds and Shapes Standard Specification for Hot-Formed Welded and Seamless Carbon Steel Structural Tubing

A312/A312M A320/A320M A333/A333M A334/A334M A335/A335M A350/A350M A358/A358M A369/A369M A376/A376M A381 A403/A403M A409/A409M A420/A420M A423/A423M A426/A426M A437/A437M A450/A450M A451 A453/A453M A498 A500 A501

3.4 Classification of metals and alloys

167

Table 3.14 ASTM Specifications for Materials Continued ASTM Standard

Title

A511 A512 A513

Standard Specification for Seamless Stainless Steel Mechanical Tubing Standard Specification for Cold-Drawn Buttweld Carbon Steel Mechanical Tubing Standard Specification for Electric-Resistance-Welded Carbon and Alloy Steel Mechanical Tubing Standard Specification for Seamless Carbon and Alloy Steel Mechanical Tubing Standard Specification for Forged or Rolled 8 and 9% Nickel Alloy Steel Flanges, Fittings, Valves, and Parts for Low Temperature Service Standard Specification for Plain End Seamless and Electric-Resistance-Welded Steel Pipe for High-Pressure Pipe-Type Cable Circuits Standard Specification for Seamless Carbon Steel Pipe for Atmospheric and Lower Temperatures Standard Specification for General Requirements for Specialized Carbon and Alloy Steel Pipe Standard Specification for Electric-Resistance-Welded Coiled Steel Tubing for Gas and Fuel Oil Lines Standard Specification for Alloy-Steel Bolting Materials for Special Applications Standard Specification for Welded Stainless Steel Mechanical Tubing Standard Specification for Seamless Cold-Drawn Carbon Steel Feedwater Heater Tubes Standard Specification for Electric-Resistance-Welded Low-Carbon Steel Pipe for the Chemical Industry Standard Specification for Seamless and Welded Carbon Steel Water-Well Pipe Standard Specification for Steel Tubes, Low-Carbon, Tapered for Structural Use Standard Specification for Centrifugally Cast Iron-Chromium-Nickel High Alloy Tubing for Pressure Application at High Temperatures Standard Specification for Hot-Formed Welded and Seamless High-Strength Low Alloy Structural Tubing Standard Specification for Seamless and Welded Austenitic Stainless Steel Tubing (Small-Diameter) for General Service Standard Specification for Centrifugally Cast Carbon Steel Pipe for HighTemperature Service Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures Standard Specification for Welded Austenitic Stainless Steel Feedwater Heater Tubes Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures Standard Specification for Carbon and Alloy Steel Forgings for Pipe Flanges, Fittings, Valves, and Parts for High-Pressure Transmission Service

A519 A522/A522M A523 A524 A530/A530M A539 A540/A540M A554 A556/A556M A587 A589 A595 A608 A618 A632 A660 A671 A672 A688/A688M A691 A694/A694M

Continued

168

CHAPTER 3 Materials

Table 3.14 ASTM Specifications for Materials Continued ASTM Standard

Title

A707/A707M

Standard Specification for Forged Carbon and Alloy Steel Flanges for Low Temperature Service Standard Specification for High-Strength Low Alloy Welded and Seamless Steel Pipe Standard Specification for Carbon Steel Forgings for Piping Components with Inherent Notch Toughness Standard Specification for Welded and Seamless Carbon Steel and Austenitic Stainless Steel Pipe Nipples Standard Specification for Wrought-Carbon Steel Butt-Welding Piping Fittings with Improved Notch Toughness Standard Specification for Seamless Austenitic and Martensitic Stainless Steel Tubing for Liquid Metal-Cooled Reactor Core Components Standard Specification for As-Welded Wrought Austenitic Stainless Steel Fittings for General Corrosive Service at Low and Moderate Temperatures Standard Specification for Welded, Unannealed Austenitic Stainless Steel Tubular Products Standard Specification for Electric-Resistance-Welded Metallic-Coated Carbon Steel Mechanical Tubing Standard Specification for Seamless and Welded Ferritic/Austenitic Stainless Steel Tubing for General Service Standard Specification for Seamless and Welded Ferritic/Austenitic Stainless Steel Pipe Standard Specification for Black and Hot-Dipped Zinc-Coated (Galvanized) Welded and Seamless Steel Pipe for Fire Protection Use Standard Specification for Welded Ferritic Stainless Steel Feedwater Heater Tubes Standard Specification for Single- or Double-Welded Austenitic Stainless Steel Pipe Standard Specification for Cold-Worked Welded Austenitic Stainless Steel Pipe Standard Specification for Wrought Ferritic, Ferritic/Austenitic, and Martensitic Stainless Steel Piping Fittings Standard Specification for Seamless Cold-Drawn Carbon Steel Tubing for Hydraulic System Service Standard Specification for Seamless Austenitic and Martensitic Stainless Steel Duct Tubes for Liquid Metal-Cooled Reactor Core Components Standard Specification for Titanium-Stabilized Carbon Steel Forgings for GlassLined Piping and Pressure Vessel Service Standard Specification for Cold-Formed Welded and Seamless High Strength, Low Alloy Structural Tubing with Improved Atmospheric Corrosion Resistance Standard Specification for High-Frequency Induction Welded, Unannealed, Austenitic Steel Condenser Tubes Standard Specification for Heat-Treated Carbon Steel Fittings for Low Temperature and Corrosive Service Standard Specification for Wrought High-Strength Low Alloy Steel Butt-Welding Fittings

A714 A727/A727M A733 A758/A758M A771/A771M A774/A774M A778 A787 A789/A789M A790/A790M A795 A803/A803M A813/A813M A814/A814M A815/A815M A822 A826/A826M A836/A836M A847 A851 A858/A858M A860/A860M

3.4 Classification of metals and alloys

169

Table 3.14 ASTM Specifications for Materials Continued ASTM Standard

Title

A865

Standard Specification for Threaded Couplings, Steel, Black or Zinc-Coated (Galvanized) Welded or Seamless, for Use in Steel Pipe Joints Standard Specification for Centrifugally Cast Ferritic/Austenitic Stainless Steel Pipe for Corrosive Environments Standard Specification for Stainless Steel Needle Tubing Standard Specification for Ferritic/Austenitic (Duplex) Stainless Steel Pipe ElectricFusion-Welded with Addition of Filler Metal Terminology Relating to Steel, Stainless Steel, Related Alloys, and Ferroalloys Standard Specification for Spray-Formed Seamless Austenitic Stainless Steel Pipes Standard Specification for Spray-Formed Seamless Ferritic/Austenitic Stainless Steel Pipe Standard Specification for Austenitic Chromium-Nickel-Silicon Alloy Steel Seamless and Welded Tubing Standard Specification for Austenitic Chromium-Nickel-Silicon Alloy Steel Seamless and Welded Pipe Standard Guide for Specifying Harmonized Standard Grade Compositions for Wrought Stainless Steels Standard Specification for Common Requirements for Wrought Steel Piping Fittings Standard Specification for Common Requirements for Steel Flanges, Forged Fittings, Valves, and Parts for Piping Applications Standard Specification for Common Requirements for Steel Fasteners or Fastener Materials, or Both, Intended for Use at Any Temperature from Cryogenic to the Creep Range Standard Specification for Fusion Bonded Epoxy-Coated Pipe Piles Standard Specification for Steel Line Pipe, Black, Plain-End, Electric-ResistanceWelded Standard Specification for Hot Isostatically-Pressed Stainless Steel Flanges, Fittings, Valves, and Parts for High Temperature Service Standard Specification for Hot Isostatically-Pressed Alloy Steel Flanges, Fittings, Valves, and Parts for High Temperature Service Standard Guide for Editorial Procedures and Form of Product Specifications for Steel, Stainless Steel, and Related Alloys Standard Specification for General Requirements for Alloy and Stainless Steel Pipe Standard Specification for Steel Line Pipe, Black, Plain End, Longitudinal and Helical Seam, Double Submerged-Arc Welded Standard Specification for Steel Line Pipe, Black, Plain End, Laser Beam Welded Standard Specification for Seamless and Welded Ferritic, Austenitic and Duplex Alloy Steel Condenser and Heat Exchanger Tubes With Integral Fins Standard Specification for Precipitation-Hardening Bolting Material (UNS N07718) for High Temperature Service Standard Guide for Videoborescoping of Tubular Products for Sanitary Applications

A872 A908 A928/A928M A941 A943/A943M A949/A949M A953 A954 A959 A960 A961 A962/A962M

A972/A972M A984/A984M A988 A989 A994 A999/A999M A1005/A1005M A1006/A1006M A1012 A1014 A1015

Continued

170

CHAPTER 3 Materials

Table 3.14 ASTM Specifications for Materials Continued ASTM Standard

Title

A1016/A1016M

Standard Specification for General Requirements for Ferritic Alloy Steel, Austenitic Alloy Steel, and Stainless Steel Tubes Standard Specification for Steel Tubes, Carbon and Carbon Manganese, Fusion Welded, for Boiler, Superheater, Heat Exchanger and Condenser Applications Standard Practice for Numbering Metals and Alloys (UNS)

A1020/A1020M E527

Table 3.15 Comparison of ASME and ASTM Standards ASTM

ASME

Remarks

A105 A 106 A 333 A 335 A 530

SA SA SA SA SA

Standard specification for carbon steel forgings for piping applications. Specification for seamless carbon steel pipe for high temperature service. Specification for seamless steel pipe for low temperature service. Specification for seamless ferritic alloy-steel pipe for high temperature service. General specification for carbon and alloy steel pipe including thickness, diameter, length and straightness are provided.

105 106 333 335 530

3.4.5 UNS The UNS provides a method for correlating the metal and alloy numbering systems developed by various technical associations. It has been developed to avoid designating more than one number for the same metal or alloy, and to avoid designating the same number for different metals or alloys, and it has been in use since 1974. Currently there are 5,200 designations for metals and alloys. It should be noted that a UNS designation is not a specification because it does not establish requirements for properties such as mechanical properties and heat treatment. The UNS designates 18 series (Table 3.16) to identify metals and alloys. Each UNS designation consists of a single-letter followed by five digits. To the greatest extent possible, commercially popular numbers are incorporated in the UNS system. For example, the UNS designation for AISI 1018 is G10180. Table 3.17 provides a comparison of equivalent materials in different designations.

3.5 Non-metals Although the use of non-metals is not as extensive as that of metals in the oil and gas industry, they play a pivotal role. In general, the non-metals in the oil and gas industry can be classified into plastics, concrete, and cement.

3.5.1 Plastics Plastics are polymeric materials and can be broadly divided into thermoplastics and thermosets.

3.5 Non-metals

171

Table 3.16 UNS Designation for Metals and Alloys39 Metal or Alloy

UNS Number

Aluminum and aluminum alloys Copper and copper alloys Specified mechanical properties steels Rare earth and similar metals and alloys Cast irons AISI and Society of Automotive Engineers (SAE) carbon and alloy steels AISI and SAE H-steels Cast steels (Except tool steels) Miscellaneous steels and ferrous alloys Low melting metals and alloys Miscellaneous nonferrous metals and alloys Nickel and nickel alloys Precious metals and alloys Reactive and refractory metals and alloys Heat and corrosion resistant steels (including stainless), valve steels, and iron-base ‘superalloys’ Tool steels, wrought and cast Welding filler metals Zinc and zinc alloys

Axxxxx Cxxxxx Dxxxxx Exxxxx Fxxxxx Gxxxxx Hxxxxx Jxxxxx Kxxxxx Lxxxxx Mxxxxx Nxxxxx Pxxxxx Rxxxxx Sxxxxx Txxxxx Wxxxxx Zxxxxx

3.3.2a Thermoplastics Thermoplastics are polymeric materials that soften on heating and harden when cooled. The materials are heated to form liquid and then extruded. Extrusion is a process of confining the polymer in a closed container and then allowing it to flow only through an opening, so that the polymer will take the form of that opening. This process is used to form different shapes such as valves, pump bodies, and pipe flanges. Thermoplastics can be joined by welding provided they are of similar grades. Several additional materials (commonly known as fillers) are used to modify the properties of thermoplastics. Some properties that are changed by the filler materials are colors, stability, and oxidation. Table 3.18 presents different classes of thermoplastics, their characteristics, and their application in the oil and gas industry (see also section 9.2.1d).40

3.3.2b Thermosets The properties of certain polymers are permanently changed by heating or by other chemicals (commonly known as curing elements). Such polymers are called thermosetting polymers or plastics. They are produced by the extension or cross-linking of the polymer chains. The process of crosslinking occurs during or immediately after shaping the final product. This process may require heat or a curing agent. This curing reaction is irreversible; i.e., once the thermoset reaction is complete, it cannot be reversed. Table 3.19 presents common thermoset plastics used in the oil and gas industry and their characteristics (see also section 9.2.1e).

172

Mechanical Properties (minimum)

Chemical Composition (%) C

P

S

Other

Ultimate Stress (lb/in.2)

Maximum Recommended Temperature ( F)

52,500

662

Country

Standard

max

Mn

Si

Max

Max

Maximum

Yield Stress (lb/in.2)

France

GAPAVE-411 A 42 C (Si-killed) DIN 1629 St. 35 Aq 35 UNI 663 C SIS 1233e05

e

e

e

e

e

e

e

0.18 e 0.17

e e 0.5

e e 0.10 to 0.40

0.05 e 0.05

0.05 e 0.05

34,000 30,000 30,000

50,000 50,000 50,000

572 752 752

BS.3601 HFS 22 CDS 22 ASTM A 53 Seamless API 5L Line Pipe Seamless

0.21

0.70 max e

e

0.05

0.05

e e Cr 0.2 Cu 0.3 N 0.009 e

30,000

50,000

850

e

0.048 to 0.11 0.04

e

e

30,000

48,000

110

0.05

e

30,000

48,000

110

Germany Italy Sweden

United Kingdom United States

e 0.22

e

CHAPTER 3 Materials

Table 3.17 Comparison of Properties of Equivalent Materials from Different Associations

3.5 Non-metals

173

Table 3.18 Characteristics and Application of Thermoplastics40 Class

Characteristics

Application

Polyvinyl chloride (PVC)

Good resistance to inorganic media and oxidizing agents but limited resistance to organic solvents Improved chemical resistance and mechanical properties

Piping for water supply and distribution; chemical processing; and wastewater • Valves • Pumps • Pipes and • Liners (for metal and fiberreinforced plastic) • Waste and other water transportation piping • Small structural containers • External anti-corrosion coatings • Lining • Sealants • Gears • Pump impellers • Threaded connections • Plugs • Low temperature piping

Polyvinyl dichloride

Polyolefins)

Fusion welded, most durable

Fluorocarbons))

Chemically inert and resistant to high temperature Dimensional stability and toughness

Polyacetal

Acrylonitrile-ButadieneStyrene (ABS) Polymethylmethacrylate Nylons Polyethylene terephthalate Polycarbonate Polyimides Polyphenyl oxide Polyphenulene sulfide Polyetheretherketone (PEEK) Polystyrene Ionomers Polyoxymethyleneyy

Properties can be varied by changing ratio of acrylonitrile to other two components Good resistance to UV Excellent mechanical properties and easy fabrication High tensile strength and good resistance to abrasion Transparent and excellent impact resistance Excellent creep and abrasion resistance Low water absorption Higher strength with high modulus obtained with fillers and glass High temperature and corrosion resistant Heat resistance Toughness and atmospheric stability is good Semicrystalline thermoplastic

• Protective face shields • Used as threads in machined parts • External coating • External coating • External coating • Pump and valve parts • Filler materials • • • • •

Wire coating Injection molding Composite fabrication Foams Occasionally as coating

• Logging tools

) Sub-classes include polyethylene (low-density polyethylene (LDPE) and high-density polyethylene (HDPE)); polypropylene; and polybutylene )) Sub-classes include polytetrafluoroethylene (PTFE)y; Perfluoroalkoxy; Fluorinated ethylene propylene; Ethylenechlorotrifluoethylene; Chlorotrifluorethylene; and Polyvinylidene fluoride y Commercially known as TeflonÔ yy DelrinÔ

174

CHAPTER 3 Materials

Table 3.19 Characteristics and Application of Thermoset Plastics41 Types Polyesters

y

Vinyl esters Epoxies Fiber-Reinforced Plastics (FRP)

Elastomersyy

Characteristics

Application

Formed by reaction between alcohol (glycol) and organic acids Formed by reaction between methacrylic acid, epoxy resin, and styrene Formed by the polymerization of epoxy resin and amine curing agent Reinforced e usually with glass fibers

• External coatings

They have some degree of cross-linking, but return to original shape once the stress applied is released

• External coatings • • • • • • • • • • •

Internal lining External coatings Storage vessels Injection lines Flowlines Tubing Liners for tubulars O-rings Bonded seals V-packing Packer elements

y

Sub-classes include orthophthalic polyesters; isophthalic and terephthalic polyesters; and bisphenol and chlorendic acid polyesters yy Sub-classes include natural rubber; polybutadiene; polychloroprene; butyl isobutylene; butyl isoprene; nitrile; chlorosulphonated polyethylene; polysulphide; polyealkylene oxide polymers; ethylene propylene; fluoroelastomers; fluorovinyl silane; highly saturated nitrile; flurocarbon terpolymer; tetrafluoroethylene; tetrafluoropropylene; terpolymer of ethylene; tetrafluoroethylene; and perfluoromethylvinyl ether

3.5.2 Concrete Concrete is a widely used construction material, consisting of Portland cement, water, sand, gravel, crushed stone, and other materials such as expanded slag. In the oil and gas industry – as in any industry – concrete is used as construction material in buildings and in offshore platforms. From the perspective of corrosion, concrete is used as an external coating. Concrete coatings are used in the offshore industry as weight coating (as negative buoyancy coating) and in the onshore industry as mechanical protection to anti-corrosion coatings of steel pipe in rocky terrains as well as in road and river crossings.

3.5.3 Cement Cement is made of calcareous (limestone, cement rock, chalk, and alkaline waste) and argillaceous rock (clay, shale, slate, and ash) materials. Chemically they consist of carbonates and silicates. In the oil and gas industry, cement is used to secure steel casings and to fill formations. Cement is used to secure steel casings to its surrounding formation, to support vertical and radial loads on the casing, to isolate porous formations, to seal subsurface fluid streams, and to protect casings from corrosion. This process is commonly known as primary cementing. Cement is also used to fill formations, to seal and to shut wells off. This process is commonly known as secondary cementing. There are two general methods by which the secondary cementing process is carried out: squeezing and plugging. Squeezing is used to repair a faulty primary cementing operation, to stop loss of circulation fluid during drilling

References

175

operations, to repair leaks in the casing and to isolate a production zone by sealing adjacent unproductive zones. Plugging is used to plug abandoned wells.

References 1. ASM Handbook, vol. 13B. In: Cramer SD, Covino BS, editors. Corrosion: Materials, Crystal Structure 2005. Fig. 3(A), p. 653, ASM International, Materials Park, Ohio 44073–0002, ISBN: 0–87170–707–1. 2. ASM Handbook, vol. 13B. In: Cramer SD, Covino BS, editors. Corrosion: Materials, Crystal Structure 2005. Fig. 3(D), p. 656, ASM International, Materials Park, Ohio 44073–0002, ISBN: 0–87170–707–1. 3. ASM Handbook, vol. 13B. In: Cramer SD, Covino BS, editors. Corrosion: Materials, Crystal Structure 2005. Fig. 3(C), p. 655, ASM International, Materials Park, Ohio 44073–0002, ISBN: 0–87170–707–1. 4. ASM Handbook, vol. 13B. In: Cramer SD, Covino BS, editors. Corrosion: Materials, Crystal Structure 2005. Fig. 4, p. 657, ASM International, Materials Park, Ohio 44073–0002, ISBN: 0–87170–707–1. 5. ASTM A370. Standard Test Methods and Definitions for Mechanical Testing of Steel Products. PO Box C700, West Conshohocken, PA, 19428–2959 USA: ASTM International, 100 Barr Harbor Drive. 6. Craig BD. Oilfield Metallurgy and Corrosion. 3rd ed.; 2005. MetCorr, 4600 South Ulster Street, Suite 700, Denver, Colorado 80237, ISBN 0–976–0400–0-X, Fig. 1.9, p. 10. 7. Craig BD. Oilfield Metallurgy and Corrosion. 3rd ed.; 2005. MetCorr, 4600 South Ulster Street, Suite 700, Denver, Colorado 80237, ISBN 0–976–0400–0-X, Based on Table 1.1, p. 14. 8. ASTM E23. Standard Test Methods for Notched Bar Impact Testing of Metallic Materials. 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428–2959 USA: ASTM International. 9. Craig BD. Oilfield Metallurgy and Corrosion. 3rd ed. 2005. MetCorr, 4600 South Ulster Street, Suite 700, Denver, Colorado 80237, ISBN 0–976–0400–0-X, Fig. 1.13, p. 16. 10. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 5, P. 610, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 11. ASM Handbook, vol. 9. Metallography and Microstructures. Voort GFV, editors, based on Fig. 1, p. 24, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3 (2004). 12. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures. Materials Park, Ohio: ASM International; 2004. p. 608. 44073–0002, ISBN 0–87170–706–3. 13. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Table 1, p. 53, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 14. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Figs. 1, 2, and 3, pp. 589–590, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 15. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 7, p. 591, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 16. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 9, p. 591, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 17. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 10, p. 592, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 18. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 11, p. 592, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3.

176

CHAPTER 3 Materials

19. Bramfitt BL, Lawrence SJ. Metallography and Microstructures of Carbon and Low-Alloy Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 14, p. 592, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 20. Gray JM, Fazackerley WJ. Technical Challenges and Metallurgical Aspects of High Strength Linepipe, in Materials for Resource Recovery and Transport. Calgary, Alberta, Canada: Proceedings of the International Symposium on Materials for Resources Recovery and Transport; Aug. 16–19, 1998. pp. 191–218. 21. Revie RW, Uhlig HH. Corrosion and Corrosion Control. Section 7.3, p. 138. John Wiley and Sons; 2008. ISBN 978–0-471–73279–2. 22. ASME Boiler and Pressure Vessel Code, Sec. 1, 1980, p. 184, Table PG23.1 New York, NY 10016-5990: ASME International, Two Park Avenue. 23. Guo B, Song S, Chacko J, Ghalambor A. Offshore Pipelines. Fig. 10.1, p. 120. Gulf Professional Publishing; 2005. 30 Corporate Drive, Suite 400, Burlington, MA 01803, ISBN 978–0-7506–7847–6. 24. Radzikowska JM. Metallography and Microstructures of Cast Iron. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures. Ohio: ASM International, Materials Park; 2004. p. 565. 44073–0002, ISBN 0–87170–706–3. 25. Spence TC. Corrosion of Cast Irons. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures. Ohio: ASM International, Materials Park; 2004. p. 43. 44073–0002, ISBN 0–87170–706–3. 26. Davis JR, editor. ASM specialty Handbook, Cast Irons. Ohio: ASM International Materials Park; 2004. 44073–0002. 27. Radzikowska JM. Metallography and Microstructures of Cast Iron. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 3, p. 566, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 28. Radzikowska JM. Metallography and Microstructures of Cast Iron. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 10, p. 567, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 29. Radzikowska JM. Metallography and Microstructures of Cast Iron. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. Fig. 16, p. 570, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 30. Caron RN, Barth RG, Tyler DE. Metallography and Microstructures of Copper and Copper Alloys. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. p. 775, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 31. Caron RN, Barth RG, Tyler DE. Metallography and Microstructures of Copper and Copper Alloys. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004 based on Table 1, p. 776, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 32. Cohen A. Corrosion of Copper and Copper Alloys. ASM Handbook, vol. 13B. In: Cramer SD, Covino BS, editors. Corrosion: Materials 2005. p. 125, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–707–1. 33. Voort GFV, Lucas GM, Manilova EP. Metallography and Microstructures of Stainless Steels and Maraging Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. p. 670–701, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 34. Voort GFV, Lucas GM, Manilova EP. Metallography and Microstructures of Stainless Steels and Maraging Steels. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004 based on Table 10, p. 681, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 35. Craig BD. Oilfield Metallurgy and Corrosion, Stainless Steel; 2005. p. 41, 3rd ed. MetCorr, 4600 South Ulster Street, Suite 700, Denver, Colorado 80237, ISBN 0–976–0400–0-X, p. 10.

References

177

36. Mankins WL. Metallography and Microstructures of Nickel and Nickel-Copper Alloys. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004 based on Table 3, p. 818, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 37. Gammon LM, Briggs RD, Packard JM, Batson KW, Boyer R, Domby CW. Metallography and Microstructures of Titanium and Its Alloys. ASM Handbook, vol. 9. In: Voort GFV, editor. Metallography and Microstructures 2004. p. 899, ASM International, Materials Park, Ohio, 44073–0002, ISBN 0–87170–706–3. 38. The Handbook of Comparative World Steel Standards. 4th ed. West Conshohocken, PA, 19428–2959 USA: DS67C, ASTM International, 100 Barr Harbor Drive, PO Box C700. 39. Metals and alloy in the Unified Numbering System, SAE HS-1086–2008 and ASTM ds-56J, UNS 11th ed. ISBN: 978–0-7680–1977–3, SAE International, 2008. 40. Davies M, Scott PJB. Oilfield Water Technology. Chapter 7: Nonmetallic Behavior, Section 7.1.1: Thermoplastics, p. 107. Houston, TX: NACE International; 2006. ISBN 1–57590–204–4. 41. Davies M, Scott PJB. Oilfield Water Technology. Chapter 7: Nonmetallic Behavior, Section 7.1.2: Thermosetting Resins, p. 113. Houston, TX: NACE International; 2006. ISBN 1–57590–204–4.

CHAPTER

The Main Environmental Factors Influencing Corrosion

4

4.1 Introduction Chapter 3 discusses the nature of materials and how their properties influence the corrosion tendency and the rate. This chapter discusses the influence of environmental factors on corrosion. The rate at which corrosion takes place depends on several environmental factors including flow, pressure, temperature, oil phase composition, aqueous phase composition (salts and organic acids), gas phase composition (CO2, H2S, O2), solids, microbes, and mercury. Table 4.1 presents the oil and gas sectors in which these factors predominantly influence corrosion. Other factors might have additional effect on the corrosion type and corrosion rate and should be considered in a given operating environment.

4.2 Flow To transport hydrocarbons, the oil and gas industry uses pipes and pipelines operated under pressure. The pressure is the force that moves the hydrocarbons. An important consideration in designing and operating piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Bernoulli’s equation explains the pressure of a pipeline,1 according to which: Static Pressure þ Dynamic Pressure ¼ Constant:

(Eqn. 4.1)

Static pressure is the pressure exerted by a column of standing fluid. Dynamic pressure is the pressure exerted by a moving fluid. Figure 4.1 illustrates Bernoulli’s principle. Fluid velocity is lower in Sections A and C than that in Section B. Therefore the static pressure is higher in Sections A and C than in Section B. It should be noted that the velocities (distance travelled per unit time) of fluids in various sections are different, but the mass transferred per unit time is the same in all sections. The pressure is often indicated in the oil and gas industry by the term ‘head’ (H). This represents the pressure exerted by a column of liquid. A one foot high column of water exerts a pressure of 0.433 psi. In other words, the pressure measured as 1 psi is equivalent to the pressure exerted by a column of water of 2.31 feet high, i.e.: 1 psi=0:433 psi=ft ¼ 2:31 ft of head of water (Eqn. 4.2)

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00004-2 Copyright Ó 2014 Elsevier Inc. All rights reserved.

179

180

Table 4.1 Environmental Factors Influencing Corrosion Environmental Factors

Component

Flow

Oil

Water

CO2

H2S

O2

Solid

Microbe

Pressure

Temperature

pH

acid

Hg

Production

Drill Pipe

No

No

Yes

Yes

Yes

No

Yes

No

No

Yes

No

No

No3

Casing Pipe

No

No

Yes

Yes

Yes

No

No

Yes

Yes

Yes

Yes

No

No

Downhole Tubular

Yes

Yes

Yes

Yes

Yes

No1

Yes

Yes

Yes

Yes

Yes

No

No3

Acidizing Pipe

Yes

No

Yes

No

No

No1

No

No

No

Yes

Yes

No

No

Water Generators

Yes

No

Yes

No

No

No

No

Yes

No

Yes

Yes

No

No

Gas Generators

Yes

No

Yes

No

No

No1

No

No

Yes

Yes

No

No

No

Open Mining

No

No

Yes

No

No

No

Yes

No

No

Yes

No

No

No

In situ Production

Yes

Yes

Yes

Yes

Yes

No1

Yes

No

Yes

Yes

Yes

Yes

No3

Wellhead

No1

Yes

Yes

Yes

Yes

No1

Yes

No

Yes

Yes

Yes

Yes

No3

No

1

Yes

Yes

Yes

Yes

Yes

Yes

No3

No

1

Yes

Yes

No

Yes

No

Yes

No3

Production Pipelines Heavy Crude Oil

Yes

Yes

Yes

Yes

Yes

Yes

Yes

1

No

No

1

1

Yes

Yes

Yes

No2

No2

No1

Yes

No

Yes

Yes

Yes

Yes

No3

No

Yes

Yes

Yes

Yes

No1

No

Yes

No

Yes

Yes

Yes

No3

1

No

No

No

Yes

Yes

No

No3

No

Pipelines Hydrotransport Pipelines Separators Gas Dehydration

No

No

Yes

yes

Yes

No

Yes

Yes

Yes

Yes

Yes

Yes

Yes

No

No

Yes

Yes

Yes

No3

Facilities Recovery Centers (Extraction) Upgraders

See refinery section

Waste Water Pipelines

Yes

No

Yes

No

No

No1

Yes

No

No

No

Yes

No

No

Tailing Pipelines

Yes

No

Yes

No

No

No1

Yes

No

No

No

Yes

No

No

Lease Tanks

No

Yes

No4

No

No

No

No4

No4

No

No

No

No

No

Transmission-

Transmission Pipelines

Yes

Yes

No4

No

No

No1

No4

No4

Yes

Yes

No

No

No

pipeline

(Midstream Pipelines)

TransportationTanker

Compressor Stations

Yes

No

Yes

No

No

No

Yes

No

Yes

Yes

No

No

No3

Pump Stations

Yes

Yes

Yes

No

No

No

Yes

No

Yes

Yes

No

No

No3

Pipeline Accessories

Yes

Yes

Yes

No

No

No

Yes

No

Yes

Yes

No

No

No3

Ships

No

Yes

No4

No

No

No1

No4

No4

No

No

No

No

No

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Org. Sector

Storage

Refineries

LNG Tanks

No

No

No4

No

No

No1

No4

No4

No

No

No

No

No

Railcars

No

Yes

No4

No

No

No1

No4

No4

No

No

No

No

No

Other modes

No

No

No4

No

No

No1

No4

No4

No

No

No

No

No

Gas Storage

No

No

No4

No

No

No

No4

No4

No

No

No

No

No

Oil Storage

No

Yes

No4

No

Yes

No

No4

No4

No

No

No

No

No

Desalter

Yes

Yes

Yes

No

No

No

Yes

No

Yes

Yes

Yes

Yes

No

Atmospheric

No

Yes

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Vacuum distillation

No

Yes

Yes

No

Yes

No

No

No

No

Yes

No

Yes

No

Hydrotreating

No

Yes

No

No

Yes

No

No

No

Yes

Yes

No

Yes

No3

Catalytic reforming

No

Yes

No

No

Yes

No

No

No

Yes

Yes

No

Yes

No3

distillation

Distribution

Visbreaker

No

Yes

No

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Coker

No

Yes

No

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Alkylation

No

Yes

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Gas treating

No

No

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Sour water stripper

No

No

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Hydrodesulfurization

No

No

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Sulfur recovery

No

No

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Heat exchanger

No

No

Yes

No

Yes

No

No

No

Yes

Yes

No

Yes

No

Product Pipelines

No

Yes

No4

No

No

No1

No4

No4

No

No

No

No

No

Terminals

No

Yes

No4

No

No

No1

No4

No4

No

No

No

No

No

1

4

No4

No

No

No

No

No No

City Gates and Local

4

No

No

No

No

No

No1

No4

No4

No

No

No

No

No

No

No

1

4

No4

No

No

No

No

No

Yes

No

No

No

No

No

No

No

No

No4

No

Distribution CNG Tanks Special

4

No

No

Yes

No

CO2 Pipelines

No

No

Yes5

Yes5

Yes5

Yes5

No4

No4

Yes

Biofuel Infrastructure

Yes

Yes6

No4

No

No

No1

No

No4

No

Yes

No

Yes

No

No

No

No

1

No4

Yes

Yes

No

No

No

No

No

No

No

Yes

Yes

No

No

No

High Vapor Pressure

No

No

No

No

No

No

4

No

4

Pipelines Hydrogen Pipelines 1

Unless operational deficiency accidentally lets them inside the system though may present the influence is minimal due to the influence of other components 3 only affect aluminum components 4 unless operational deficiency lets them accumulate at the bottom for prolonged duration 5 if intentionally left in the stream 6 in the form of biofuel

No

4.2 Flow

Diluent Pipelines

2

181

182

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

FIGURE 4.1 Bernoulli Principle.4 Reproduced with permission from PennWell Corporation.

The head of other liquids is estimated by dividing the head of water by the specific gravity of that liquid. Thus:2 H¼

2:31:P SG

(Eqn. 4.3)

where H is the head in feet, P is the pressure in psi, and SG is the specific gravity. H¼

P 9:7928:SG

(Eqn. 4.4)

where H is the head in meters and P is the pressure in kPa. In order to fully understand the effect of flow on corrosion, four parameters should be understood: pressure drop, flow regime, water accumulation, and critical flow rate.

4.2.1 Pressure drop One of the important calculations in designing and operating infrastructure is to determine the pressure drop. This is a combination of the static pressure (static head) due to the difference in elevation between the upstream and downstream locations and the dynamic pressure (dynamic head) due to energy loss from the flow of liquid. The static pressure remains constant once the infrastructure is constructed, but the dynamic pressure varies constantly because the type of phases (oil, water, and gas), number of phases (single, two, and multi), and volumes of different phases change constantly during operation. The combined pressure drop (caused by both static and dynamic heads) is typically represented by a System Head Curve (SHC). Figure 4.2 presents a typical SHC.3 Infrastructures operate over a wide range of SHCs. Appropriate pumps or compressors are selected on the basis of the anticipated SHCs over the entire operating life of the infrastructure. Methods to calculate the pressure drop in various types of flow are described in the following sections.

4.2 Flow

183

FIGURE 4.2 Typical System Head Curve.3 Reproduced with permission from ASME.

4.2.1a Single phase liquid Single phase flow may be laminar flow or turbulent. In general, the Reynolds number is used to differentiate laminar and turbulent flows. If the Reynolds number (Re) is less than 2,000 the flow is laminar, and if it is above 2,000 the flow is turbulent. Sometimes the flow between Re 2,000 and 4,000 is considered as transitional flow, and above 4,000 it is considered as turbulent. Re is defined as: Re ¼

3160  U di $v

(Eqn. 4.5)

where U is the liquid flow rate (gallons per minute [gpm]), di is the inner pipe diameter (inch), and n is the kinematic viscosity (centistokes). Kinematic viscosity, in stokes, is calculated using Eqn. 4.6: v¼

hl $10000 rl

(Eqn. 4.6)

where hl is the liquid viscosity in kg/ms and rl is the liquid density in kg/m3. The downstream pressure, Pd (psi), of a laminar flow with no elevation change, is calculated as: Pd ¼ P u

0:0134 

f $L$SG$U 2 di 5

(Eqn. 4.7)

where Pu is the upstream pressure (psi), f is the friction factor (dimensionless), L is the length of the pipe (ft), SG is the specific gravity of liquid relative to water, U is the liquid flow rate (gpm), and di is the inner pipe diameter (in).

184

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

The friction factor, f, is dimensionless and is calculated using either Eqn. 4.8 (smooth surface) or Eqn. 4.9 (rough surface): 64 (Eqn. 4.8) f ¼ Re 
εpipe 1=3 (Eqn. 4.9) f ¼ 0:0055 þ 0:15 di where εpipe is the surface roughness (m) and di is the inner pipe diameter (m). The friction factor, pipe roughness, pipe diameter, and Reynolds number are interrelated. Moody diagram is commonly used to indicate this relationship (Figure 4.3).4 If the elevation of the pipeline changes, then Eqn. 4.10 is used to calculate the downstream pressure (Pd, kPa) of a laminar flow. U$L$SG$n Pd ¼ Pu DPE;L (Eqn. 4.10) C3 $di4 where Pu is the upstream pressure (kPa), U is the flow rate (m3/hr), L is the length of the pipe (km), SG is the specific gravity of liquid relative to water (dimensionless), n is the kinematic viscosity (centistokes), C3 is a conversion constant (8.61E 06), and di is the inner pipe diameter (mm), and DPE,L is the difference in pressure due to elevation change and is calculated using Eqn. 4.11.   DPE;L ¼ CE $SG$ Hd Hu (Eqn. 4.11)

where CE is the conversion constant to convert the result to kPa/m (0.0999); SG is the specific gravity of liquid relative to water (dimensionless); Hd is the downstream elevation (m); and Hu is the upstream elevation (m). For heavy crude with viscosity higher than 1,000 cP flowing in the laminar region the pressure drop can be determined as:4,5 # " Cu U 2 f CHead ðHd Hu Þ þ Pd ¼ Pu SG:DLpipe (Eqn. 4.12) DLpipe di5

where Pu is the pressure at the upstream end of the segment; Pd is the pressure at the downstream end of the segment; DLpipe is the length of the segment; f is the friction factor; di is the internal diameter of the pipe; SG is the liquid specific gravity; Hu is the elevation at the upstream end of the segment; Hd is the elevation at the downstream end of the segment; Cu is the flow conversion constant; and CHead is the head conversion constant. The downstream pressure of a turbulent liquid flow, Pd in kPa is calculated as: P d ¼ Pu

DPE;L

f $L$SG$U 2 C42 $di5

(Eqn. 4.13)

where Pu is the upstream pressure (kPa); DPE,L the pressure drop due to elevation change (kPa), L is the length of the pipe (km), U is the liquid flow rate (m3/hr); C4 is a conversion constant (19.8072E 06), and di is the inner pipe diameter (mm). For liquid pipelines, the velocity and density do not change significantly along the length of a given pipeline if diameter and temperature are constant. Therefore the pressure loss per length is first

Values of (Vd) for water at 60°F (velocity. ft/s = diameter. m) 0.1

0.2

0.4 0.6 0.8 1

2

4

6 8 10

20

40

60 80 100

200

400 600 800 1000

Values of (Vd) for atmospheric air at 60°F

0.08

5 8 10

20

Laminar Critical flow zone Transition zone

40

60 100

200

400 600 800 1000 2000

4000

80,000 8000 6000 10,000 20,000 40,000 60,000 100,000

Complete turbulence, rough pipes

0.05 0.04

0.07 0.06

0.02 0.015 ε

) Friction factor ƒ =

(

h

L V2 d 2g

0.04

flow inar Lam 64 ƒ = Re

0.05

0.03

0.01 0.008 0.006

0.03 0.025

0.004

Recr

0.002 0.001 0.0008 0.0006 0.0004

0.02

Sm

0.015

oo

th

0.0002

pip

es

0.0001 0.000,05

0.01 0.009 103 2(103) 3

4 5 6

8

104 2(104) 3

4 5 6

8

105 2(105) 3

4 5 6

Reynolds number Re =

8

106 2(106) 3

Vd v

4 5 6

8

107 2(107)

ε = 0.000,001 d

3

4 5 6

0.000,01 108

8

ε = 0.000,005 d

4.2 Flow

0.008

d

0.09

4

2

8000 4000 6000 10,000

Relative roughness

0.10

2000

FIGURE 4.3 Moody Diagram.4

185

Reproduced with permission from ASME.

186

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

calculated, and multiplying this value by the total length produces the total pressure drop for the entire length. When two or more products of different densities and viscosities are transmitted in the pipeline, the weighted average of the densities and viscosities are first calculated. The weighted average values are then used in Eqn. 4.13 to calculate the pressure drop.

4.2.1b Single phase gas The downstream pressure of a single gas pipeline, P2 (psi), is calculated as: !0:5 Ub 2 $Pb 2 $Zave $Tave $SGgas $L 2 . DPE Pd ¼ P u CSPG 2 $Tb 2 $1 f $di5

(Eqn. 4.14)

where Pd is the downstream pressure (psi), Pu is the upstream pressure (psi), Ub is the gas flow rate at base conditions (SCF/d), Pb is the pressure under base conditions (14.7 psi), Zave is the average compressibility factor (dimensionless (see section 4.2.1b.i)), Tave is the average temperature ( R), SGgas is the gas gravity (dimensionless), L is the length of the pipe (miles), CSPG is a constant 38.774, Tb is the temperature at base condition (520  R), 1/f is the transmission factor (dimensionless (see section 4.2.1b.iii)), di is the inner pipe diameter (inches), and DPE is the difference in pressure due to elevation change (see section 4.2.1b.ii).

i. Calculation of Zave Gases are compressible. Therefore the calculation of a pressure drop in the gas phase includes a correction for the compressibility. For an ideal gas, the molecules can be treated as point particles with no interaction between them. For an ideal gas, the relationship between pressure, volume, and temperature is given as: PV ¼ nRT

(Eqn. 4.15)

where P is the pressure, V is the volume, n is the number of moles, R is the constant, and T is the temperature. Under standard pressure and temperature conditions most of the real gases follow Eqn. 4.15, but not at higher pressure and higher temperature. At higher pressures, the gas molecules frequently collide with one another as well as with the walls of the container, and at higher temperatures the molecules move faster. As a consequence, under high pressure and high temperature the molecules interact (attract or repel each other). This behavior can be accounted for by the compressibility factor, Zgas: Zgas ¼

PV nRT

(Eqn. 4.16)

The value of Zgas generally increases with pressure and decreases with temperature. Figures 4.4 and 4.5 present typical values of Zgas for some commonly used gases.6,7 The value of Zgas is a function of the reduced pressure, Pr and the reduced temperature Tr. The reduced pressure is the ratio of the actual pressure to the critical pressure, Pcrit. Similarly, the reduced temperature is the ratio of the actual temperature to the critical temperature, Tcrit. The critical pressure is the minimum pressure required to compress a gas into liquid at its critical temperature, and the critical temperature is the temperature beyond which a gas cannot be compressed into a liquid. Figure 4.6 presents a commonly used graph to

4.2 Flow

187

Pseudo reduced pressure 1

0

2

3

1.1

4

5

6

7

Pseudo reduced temperature 3.0 2.8 2.6 2.4 2.2 2.0 1.9 1.8

1.0

0.9

8 1.1 1.05 1.0 1.2 0.95

1.5

1.7

1.1

1.4 05 1. 1 1.

1.6 0.8

1.3

1.5

1.7

1.45

1.35

1.6

3 1.

1.3 0.6

4 1. 1.5 1.6 1.7 1.8 1.9 2.0 2.2

1.25 1.2

0.5

5 1.1 0.4

2.4

1.1

1.5

1.4

Compressibility factor Z

Compressibility factor Z

2 1.

1.4

0.7

1.3

2.6 3.0

0.3

1.2

5 1.0

0.25 2.8

1.1

3.0

1.1

2.6 2.4 2.2 2.0 1.9 1.8

1.0

1.1 1.05

1.2

1.0 January 1, 1941

1.7 1.6

0.9

1.4 1.3

7

8

9

10

11

12

13

14

0.9 15

Pseudo reduced pressure

FIGURE 4.4 Compressibility Factors for Natural Gases.6 Reproduced with permission from McGraw-Hill.

correlate Zgas with Pr and Tr.8 Table 4.2 presents critical temperatures and pressures of some hydrocarbons.9 The average compressibility factor, Zave is then calculated from the percentages of various gases and their respective compressibility factors (Table 4.2): Zave ¼

Pave :V nR:Tave

(Eqn. 4.17)

188

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

0.9

0.8

Z

0.7

0.6 800 psia 1150 psia 1350 psia 1675 psia 2140 psia

0.5

0.4 0

5

10

15

20

25

30

35

40

Ethane, mole %

FIGURE 4.5 Compressibility Factors for Mixed Gases.7 Reproduced with permission from NOVA Chemicals.

where Pave is the average pressure and Tave is the average temperature, which are calculated using Eqns. 4.18 and 4.19 respectively: Pave ¼ Pca :Ya þ Pcb :Yb þ Pcc :Yc þ :::

(Eqn. 4.18)

Tave ¼ Tca :Ya þ Tcb :Yb þ Tcc :Yc þ :::

(Eqn. 4.19)

where Ya, Yb, etc. are the percentages of gases and Pca , Pcb, etc. and Tca, Tcb, etc. are the critical pressures and critical temperatures of the corresponding gases, respectively.

ii. Calculation of potential energy Potential energy, DPE,G, i.e., the pressure drop due to elevation change in single phase gas flow, is calculated as:   0:0375SGgas $ Hd Hu $P2ave DPE;G ¼ (Eqn. 4.20) Tave $Zave where SGgas is the gas gravity (dimensionless); Hd is the downstream elevation (ft); Hu is the upstream elevation (ft); Pave is the average pressure (psi); Tave is the average temperature ( R); and Zave is the average compressibility factor. Alternatively some constant values of DPE are assumed. Some commonly used approximate values of DPE are:10 1 for new pipe with no bends, fittings, or pipe diameter changes; 0.95 for very good operating conditions, typically for the first 12–28 months; 0.92 for average operating conditions; and 0.85 for unfavorable operating conditions.

4.2 Flow

189

1.125 ture, Tr

Reduced Tempera

4 3 2.6 2.2 2.1 2.0 1.9 1.8 1.7 1.6

1.000

1.55 1.50 1.45

0.750

1.40

5 1.3 0 1.3 5 1.2 0 1.2 5 1.1

0.625

1. 1. 00 05

Supercompressibility Factor, Z

0.875

0.500

P Reduced Pressure, Pr = — Pc

0.375

T Reduced Temperature, Tr = — Tc 0.250

0.125 1

2

3

4

5

6

7

8

9

Reduced Pressure, Pr

FIGURE 4.6 Correlation between Compressibility Factors and Critical Pressure and Critical Temperature.8 Reproduced with permission from Taylor & Francis.

iii. Calculation of transmission factor Table 4.3 presents four common methods for calculating transmission factors. The Weymouth method is used for high flow-rate, large diameter, and high pressure pipelines; the Panhandle A method is used for medium to relatively large diameter pipeline with moderate flow rate, operating under medium to high pressure; the Panhandle B method is used for high flow rate, large diameter (i.e. larger than NPS 24), high pressure pipelines; and the American Gas Association (AGA) Fully Turbulent method is used for high pressure, high flow rate, medium to large diameter pipelines.

4.2.1c Two-phase liquid-gas In two-phase liquid-gas flow, the volume occupied by the gas is physically negligible due to its compressibility. Therefore, the two-phase liquid-gas calculation is only used when the gas flow rate is greater than 3,500,00 ft3/d(w100,000 m3/d). Below this gas production rate, either the single phase liquid (see section 4.2.1a) or single phase gas calculation (see section 4.2.1b) is used depending on the production rates of liquid and gas. Several methods can be used to calculate the pressure drop in a two-phase liquid-gas flow. Only the simple approach is described in this section. In this approach the pressure drop in a

190

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Table 4.2 Critical Properties of Certain Gases9

Gas Methane Ethane Propane Isobutane n-butane Hydrogen n-pentane n-hexane n-heptane n-ocatane n-nonane n-c10 n-c11 n-c12 Air Nitrogen Oxygen CO2 H2S He

Molecular Weight (lbm/mole) 16.04 30.07 44.09 58.12 58.12 2.02 72.15 86.18 100.21 114.23 128.26 142.29 156.30 170.34 29 28.02 32.0 44.01 34.08 4.00

Critical Temperature, Tcri ( R)

K

343.3 549.8 666.0 734.7 765.3 60 845.6 913 972 1,024 1,070 1,112 1,150 1,185 238.4 226.9 277.0 547.7 672 9

Critical Pressure, Pcrit MPa

Psi

191 305 370 408 425

4.6 4.88 4.25 3.65 3.8

470 507 540 569 595 618 639 658 132 126 155 304 373 5

3.37 3.01 2.74 2.49 2.29 2.10 1.97 1.82 3.77 3.4 5.04 7.38 8.96 0.23

673.1 708.3 617.4 529.1 550.7 189.0 489.5 437 397 361 332 305 285 264 547.0 492.0 730.0 1073.0 1,300 33

Table 4.3 Transmission Factors Transmission Factor

Formulae

Weymouth

pffiffiffiffiffiffiffi 1=6 1=f ¼ 11:19di
 pffiffiffiffiffiffiffi Ug SGgas 0:07305 1=f ¼ 7:211 di Where Ug is the flow rate of gas (ft3/h)

Panhandle A

Panhandle B

AGA fully turbulent


 pffiffiffiffiffiffiffi Ug SGgas 0:01961 1=f ¼ 16:70 di pffiffiffiffiffiffiffi 3:7di 1=f ¼ 4log Ke Where Ke is the effective roughness (in.)

Compressibility Factor, Zgas 0.290 0.285 0.277 0.283 0.274 0.304 0.269

e 0.291 0.292 0.274

4.2 Flow

191

two-phase liquid-gas flow (DPLG) can be determined based on the pressure drop in a single phase gas flow as:11 DPL

G

¼ DPG 42

(Eqn. 4.21)

where 4 is the two-phase flow modulus. The values of 4 depend on Lockhart-Martinelli two-phase modulus XLM, which is defined as: vffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi !0:2ffi u
1:8
 u U r h g l XLM ¼ t $ l $ (Eqn. 4.22) rl Ug hg

where Ul is the liquid flow rate (lb/h), Ug is the gas flow rate (lb/h), rg is the gas density (lb/ft3), rl is the liquid density (lb/ft3), hl is the viscosity of liquid (centipoise), and hg is the viscosity of gas (centipoise). The relationship between 4 and XLM depends on the flow regime. For annular, annular mist, and wispy flow (see section 4.2.2 for flow regimes): 0:343 0:3125di XLM

4 ¼ 4:8

0:021di

(Eqn. 4.23)

where di is inner pipe diameter in inches. For bubble flow: 14:2X 0:75 4 ¼  . LM 0:1 Ul A

(Eqn. 4.24)

where A is the cross sectional surface area of the pipe (ft2). For plug flow:

For slug, churn, and oscillator flows:

27315X 0:855 4 ¼  . LM 0:17 Ul A

For stratified flow:

1190X 0:815 4 ¼  . LM 0:5 Ul A

For dispersed flow:

15400XLM 4 ¼  . 0:3 Ul A

42 ¼

4 3 0:00003:XLM þ 0:0048:XLM

2 0:2415:XLM þ 7:6125:XLM þ 6:5734

(Eqn. 4.25)

(Eqn. 4.26)

(Eqn. 4.27)

(Eqn. 4.28)

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

4.2.1d Two-phase liquid-liquid When two immiscible liquids, e.g., oil and water, are transported, the pressure drop is calculated as per section 4.2.1a, except that the mixed viscosity is used in Eqns. 4.6 and 4.10. The mixed viscosity is calculated as: Vo :ho þ Vw :hw hl ¼ (Eqn. 4.29) V o þ VW where hl is the viscosity of liquid, ho and hw are viscosities of oil and of water respectively, and Vo and Vw are the volumes of oil and water respectively.

4.2.1e Two-phase liquid-solid The solid content in most of the oil and gas industry infrastructure, except hydrotransport pipelines, is relatively low. Therefore the effect of solid on the pressure drop may conveniently be neglected. The head loss due to slurry flow in hydrotransport pipelines compared with water flow at the same flow velocity is expressed as:12 ! DPsolid DPL fdi rs : ¼f 1 (Eqn. 4.30) ½SolidŠDPL Ul2 rl where DPSolid is the pressure drop in the liquid containing solids (e.g., hydrotransport pipeline); DPL is the pressure drop in liquid flow (see section 4.2.1a); [Solid] concentration of solids; f is the friction factor; di is the internal diameter of pipe; Ul is the liquid flow rate; rs is the density of solids; and rl is the density of liquid.

4.2.1f Two-phase gas-solid The solids present in a gaseous flow may include corrosion products, e.g., iron sulfides, sands, debris, and other impurities. The solid content in gas pipelines is relatively low in most cases, and hence its effect on the pressure drop may conveniently be neglected. The pressure drop in gas-solid flow is therefore calculated using the equations presented in section 4.2.1b.

4.2.1g Three-phase liquid-liquid-gas Multiphase pipelines may transport oil, water, and gas. Very little information is available on threephase flow. The pressure drop in three-phase liquid-liquid-gas flow can be calculated by considering oil and water as one phase, and calculating the viscosity of this phase using Eqn. 4.29. With this consideration, the two-phase liquid-gas equation (see section 4.2.1c) is used to calculate the pressure drop in three-phase flow.

4.2.1h Series pipeline The pressure drop of a pipeline in series with different diameters (Figure 4.7)13 can be calculated by calculating the pressure drop in adjacent sections individually as: P21;S

nPD P22;S ¼ k1;S Ub;S

(Eqn. 4.31)

P22;S

nPD P23;S ¼ k2;S Ub;S

(Eqn. 4.32)

P23;S

nPD P24;S ¼ k3;S Ub;S

(Eqn. 4.33)

4.2 Flow

k1,S Ub

P1

k2,S Ub

P2

193

k3,S Ub

P3

P4

FIGURE 4.7 Pipeline in Series.13

Then the pressure drop across the entire section is given as:    nPD nPD P21;S P24;S ¼ kT;S Ub;S ¼ k1;S þ k2;S þ k3;S :Ub;S kS ¼ RPD :L

(Eqn. 4.34) (Eqn. 4.35)

where P1,S, P2,S, P3,S and P4,S are respectively the pressure drops at segments 1, 2, 3, and 4 of pipeline in series; k1,S, k2,S, k3,S and kT,S are the pipeline resistance in segments 1, 2, 3, and total respectively; RPD is the resistance per foot of pipeline; L is the length of pipeline in feet; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). Equation 4.36 presents a simple equation to calculate RPD; several more complicated and more accurate equations are also available:13 Tf RPD ¼ 4:82  10 4 5 $SG0:855 (Eqn. 4.36) g di where Tf is the temperature constant and is equal to 520 R and SGg is specific gravity of gas.

4.2.1i Parallel pipelines Flow in the pipeline is diverted into two parallel lines (i.e., looped pipeline) to reduce resistance to flow. Figure 4.8 presents an example of looped pipeline.14 The pressure drop in each segment can be calculated as: P21;P

nPD P22;P ¼ k1;P Ub1

(Eqn. 4.37)

P21;P

nPD P22;P ¼ k2;P Ub2

(Eqn. 4.38)

k1;P :k2;P nPD kT;P ¼  1=n 1=nPD k1;P þ k2;P PD

(Eqn. 4.39)

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Ub,1 K1 P P1,P P2,P

Ub

Ub

K2 P

Ub,2

FIGURE 4.8 Pipeline in Parallel.14

where P1,P and P2,P are the pressure drops in parallel pipeline segments 1 and 2 respectively; k1,P, k2,P, and kT,P are the pipeline resistance in segments 1, 2, and total respectively; Ub is the gas flow rate at base conditions; and nPD is the flow exponent (value ranges between 1.74 and 2.00). By calculating the resistance to flow in individual segments using Eqn. 4.35, the total resistance (kT,P) in the entire loop is calculated. Then the pressure drop at the exit point of the looped segment can be calculated.

4.2.1j Expansion of cross-section15 If the cross-section of a pipe is suddenly enlarged, the fluid stream separates from the wall and flows as a jet into the enlarged section. The fluid then expands to fill the entire cross-section of the larger conduit (Figure 4.9). Considerable friction is generated in the space between the expanding jet (smaller pipe) and the larger pipe completely filled with fluid. The pressure drop from a sudden expansion of cross-section is given as:  2
dup;Ex 2 2 Uup;Ex (Eqn. 4.40) PEx ¼ 1 ddown;Ex 2g where PEx is the pressure drop at pipeline expansion, ft; dup,Ex is the diameter of pipeline upstream to expansion; ddown,Ex is the diameter of pipeline downstream to expansion; Uup,Ex is the flow velocity in

Va

Sa

Vb

Sb

Direction of flow

FIGURE 4.9 Pipeline with Sudden Expansion.15 Reproduced with permission from Taylor & Francis.

4.2 Flow

195

the smaller (upstream) pipeline segment before expansion, ft/s; and g is the acceleration of gravity (32.2 ft/s2).

4.2.1k Contraction of cross-section15 When the cross-section of the pipe is suddenly reduced, the fluid jet expands downstream from the point of contraction and then establishes a normal velocity distribution. The pressure drop from the sudden contraction may be given as:  2
ddown;Con Udown;Con (Eqn. 4.41) PCon ¼ 0:4 1 dup:Con 2g where Pcon is the pressure drop at pipeline contraction, ft, ddown,Con is the diameter of pipeline downstream of the contraction; dup,Con is the diameter of pipeline upstream to contraction; Udown, Con is the velocity in the smaller (downstream) pipe, ft/s; and g is the acceleration of gravity (32.2 ft/s2). It is important to note that the pressure drop depends on the velocity in the smaller pipe: at expansion it is proportional to the upstream flow, and at contraction it is proportional to the downstream flow. These calculations (discussed in sections 4.2.1j and 4.2.1k) are applicable to turbulent liquid flow only, but not to laminar (the effect of expansion or contraction is negligible) or gaseous flow.

4.2.1l Accessories Valves and fittings also contribute to overall pressure loss. When the ratio of pipeline length to pipe diameter is equal or greater than 1,000 to 1 (e.g., transmission pipelines) with a standard number of fittings and valves, the effect of pressure drop through valves and fittings may be considered as negligible. But in a pumping station, refinery piping, and process piping, where many valves exist over relatively short distances, pressure loss due to valves and fittings is important. Obtaining the pressure drop of every size and type of valve and pipe fitting is difficult. a practical approach is to use the equivalent length method, in which the pressure drop through a valve, fitting, miter elbow, or any component is assumed to be equivalent to the pressure drop of an equivalent length of straight, round pipe. Table 4.4 presents the equivalent length values; it should be noted that these values apply only to single phase, non-compressible liquids in turbulent flow in steel and iron pipe.

Table 4.4 Head Loss in Terms of Equivalent Length (L)16 Type of Bend

Radius

U-bend Z-bend U-bend Z-bend

Short Short Long Long

L/di Ratio 30 30 20 20

Equation Lequivalent Lequivalent Lequivalent Lequivalent

¼ ¼ ¼ ¼

2Haccessories 2Haccessories 2Haccessories 2Haccessories

þ116 di þ 174 di þ 74 di þ 111 di

where Lequivalent is the equivalent length of accessories to calculate pressure drop; Haccessories is the height (or, if horizontal, the width) of the loop, feet; and di is the internal diameter of pipe in feet. These equivalent lengths are based on Lequivalent /di ratio of 30 for short-radius elbows and 20 for long-radius elbows

196

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

4.2.1m Annular space17 Sometimes the fluids are transported in the annular space between the pipelines, typically between tubing and casing (see Chapter 2). The pressure drop of flow in the annular space may be calculated as follows: For laminar flow:
0:1 di;casing 6 7:95  10 hl LUl d 2 i;casing do;tubing   PAnn:Lam ¼  (Eqn. 4.42) 2  di;casing do;tubing di;casing 2 do;tubing 2 1þ 1:5eecc 2 For turbulent flow: PAnn:Tur ¼ ðdi;casing

11:46  10 6 SGl :f :Ul2 L  2
di;casing do;tubing Þ di;casing 2 do;tubing 2 d d i;casing

o;tubing

2

0:1



1þ 1:5eecc 2

0:25

(Eqn. 4.43)

where PAnn.Lam is the pressure drop, psi of laminar flow in the annular space; PAnn.Tur is the pressure drop, psi of turbulent flow in the annular space; hl is the viscosity of liquid, cp; L is the length of annulus, ft; Ul is the flow rate, barrel per day; di,casing is the internal diameter of the casing, in.; do,tubing is the outer diameter of the tubing, in.; eecc is the eccentricity of tubes (defined in Eqn. 4.44); SGl is the specific gravity of liquid; and f is the friction factor. Eccentricity of tube, eecc is defined as: 2:dtube:off (Eqn. 4.44) eecc ¼ di;casing do;tubing where dtub.off is the distance tubing is off the center, in.

4.2.1n Transient flow Normally transmission pipelines operate under steady-state conditions when supply and demand are stable. However such ideal situations seldom occur. The flow rate in the pipelines fluctuates on a daily, weekly, monthly, and annual basis. In addition to seasonal variations, large variations in the flow rate may occur during commissioning, during normal operation (e.g., air purging and loading of pipeline and pigging operations) and abnormal operation (e.g., failure of a component). The duration of a transient flow situation and the extent of deviation from steady-state conditions should be analyzed to determine appropriate corrosion factors.

4.2.2 Flow regimes Most of the flow in the oil and gas pipelines involves two or more phases. The two-phase flows may be liquid-gas, liquid-liquid, liquid-solid, or gas-solid. Because the physical properties (density and viscosity) of the phases involved are different, their rates of flow are different. Consequently, multiphase flow can take an infinite number of patterns. Fortunately these patterns can be delineated on the basis of the interfacial distribution between various phases. The delineated patterns are commonly known as flow regimes. The flow regime depends on the position of the pipe (i.e., vertical, inclined, or horizontal), flow rate, flow directions (i.e., upward or downward), and fluid properties (density and viscosity).

4.2 Flow

197

Baker parameter, Bx 105

10–1

1

10

102

103

104

Dispersed

Baker parameter, By

Wave

Bubble or froth

Annular

104

Slug Stratified 103

Plug 102

FIGURE 4.10 Baker Flow Regime Map.18 Reproduced with permission from Taylor & Francis.

4.2.2a Two-phase liquid-gas The flow regime map for gas-liquid flow in a horizontal pipe was first developed by Baker in 1954. Although various other flow regime maps have been developed, the Baker flow regime (Figure 4.10) is still widely used in the oil and gas industry. A Baker flow regime map uses two empirically developed parameters lGLflow and jGLflow defined as:18,19  r  r 1=2 g l (Eqn. 4.45) lGLflow ¼ 1:2 1000 "
 #1=3 0:073  hl  1000 2 (Eqn. 4.46) jGLflow ¼ 10 3 g rl where rg is the gas density; rl is the liquid density; hl is the liquid viscosity; and g is the surface tension.

i. Vertical upward flow regimes Figures 4.11, 4.12, and 4.13 present flow regimes of vertical upward flow, inclined upward flow (inclination angle up to 10 ), and inclined upward flow (inclination angle between 10 and 45 ) respectively. Common flow regimes of vertical flow are described in the following paragraphs.20–22

198

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

104

Annular Wispy Annular

PG(UG)2 kg m-1 s-2

103

102 Churn Bubble Flow with Developing Structure 10 Plug 1

0.1 1

10

10 10 PL(UL)2 kg m-1 s-2

10

10

FIGURE 4.11 Vertical Upward Flow Regimes.20 Reproduced with permission from Taylor & Francis.

FIGURE 4.12 Inclined Upward Flow Regimes (Inclination Angle up to 10 ).21 (DB Dispersed bubble flow and A is the annular flow). Reproduced with permission from Taylor & Francis.

4.2 Flow

199

FIGURE 4.13 Inclined Upward Flow Regimes (Inclination Angle between 10 and 45 ).22 Reproduced with permission from Taylor & Francis.

Churn flow: This flow occurs at low liquid and gas velocity in which the liquid moves upward and downward creating large bubbles of gas phase surrounded by liquid phase. With increasing flow velocity the bubbles break down leading to an unstable flow regime. Plug flow: At higher liquid flow rates, the bubbles coalesce and eventually the bubble diameter approaches that of the pipe. When this occurs, large, characteristically bullet-shaped bubbles are formed, which may be separated by regions containing dispersions of smaller bubbles. Typically this liquid phase flows down the outside of the large bubbles in the form of a falling liquid film, but because of higher fluid velocity the net flow of both liquid and gas is upwards. In plug flow, falling films may exist if the gas velocity is relatively low. As the gas flow increases, the flow undergoes a series of changes from falling to flooding, upward-downward and finally to upward. On the other hand, when the gas flow decreases the liquid begins to creep and this process is normally known as creeping. Bubble flow: At higher liquid flow conditions (higher than the plug flow) the liquid phase is continuous and a dispersion of bubbles flows within the liquid continuum. In bubble flow, the bubbles undergo random motions which pass through the channel, and from time to time, bubbles coalesce to form larger ones, leading to plug flow. The collision frequency increases with increasing void fraction. As a rule of thumb, a 30% void fraction may be taken as the limit of bubble flow. Bubble flow may exist at higher void fraction in the presence of contaminants that prevent coalescence or at very high flow velocities that prevent the growth of bubbles. Annular flow: At high gas flow rate and relatively small volume of liquid flow, the liquid flows on the wall of the pipe as a film, and the gas phase flows in the center. Usually some liquid is entrained as small droplets in the gas core.

200

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Wispy annular flow: Under annular flow conditions, if the liquid flow rate increases, the concentration of liquid droplets in the gas core increases. Ultimately the liquid droplets coalesce in the gas core in the center to large lumps or streaks (wisps) of liquid. Froth flow: Some authors describe froth flow regimes as being an emulsion-type flow without noticeable structure. However, high-speed analysis of this flow regime indicates that it is indeed bubble to annular flow, depending on the gas flow rate.

ii. Vertical downward flow regimes Figures 4.14 and 4.15 present the flow regimes of vertical downward and inclined downward flow (inclination angle up to 10 ), respectively. Vertical downward flow regimes are different from those for upward flow. Not much work has been done for this flow regime. The main characteristic of flow is the dominance of the annular flow regime. It should be noted that annular flow can, in effect, occur at zero gas flow in the form of a falling film on the wall.23,24

iii. Horizontal flow regimes Figure 4.16 presents the flow regimes of horizontal flow.25 These are more complex than those in vertical flow, mainly because of the asymmetry in the flow caused by gravitational force. This acts

FIGURE 4.14 Vertical Downward Flow Regimes.23 Reproduced with permission from Taylor & Francis.

4.2 Flow

201

FIGURE 4.15 Inclined Downward Flow Regimes (Inclination Angle up to 10 ).24 (DB is dispersed bubble, S is stratified, and A is annular). Reproduced with permission from Taylor & Francis.

FIGURE 4.16 Horizontal Flow Regimes.25 Reproduced with permission from Taylor & Francis.

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

normal to the direction of horizontal flow, whereas as it acts parallel to flow in vertical flow. As a consequence, the heavier phase tends to accumulate at the bottom of the pipe in horizontal flow. Stratified flow: When the flow rates are small, the gravitational force separates the two phases completely. As a result the liquid flows at the bottom and the gas flows at the top of the pipe. Stratified-wavy flow: As the gas velocity increases in stratified flow, waves are formed at the gasliquid interface, producing the stratified-wavy or wavy flow regime. Annular-annular mist (dispersed) flow: This pattern is similar to that of vertical flow and occurs at very high gas flow rates. However the film thickness is non-uniform, with the film at the bottom of the pipe being thicker than that on the top of the pipe. Further, most of the liquid may be entrained in the gas core. Bubble flow: Characteristic bullet-shaped bubbles are formed which normally move near the top of the pipe. In some flow regime descriptions, this flow pattern may be identified as plug flow. Slug flow: At relatively moderate gas and liquid flow rates, slugs are intermittently created. The slug contains continuous liquid phase but with large amounts of entrained gas bubbles. The presence of slugs produces sudden pressure pulses causing vibrations in the pipe. Dispersed flow: At high liquid flow rates the bubbles are dispersed in a liquid continuum. The bubbles tend to congregate near the top of the pipe. At high liquid velocities the bubbles may be more uniformly distributed and may appear as froth.

4.2.2b Two-phase liquid-liquid Liquid-liquid flow occurs in the oil and gas industry when oil and water are transported simultaneously. The oil and water may flow either in the emulsion (oil-in-water or water-in-oil) form or in the stratified form. Due to their non-ionic nature, hydrocarbons cannot dissolve ionic water. However at low water concentrations, hydrocarbons can form an emulsion with the water. The type of emulsion and its stability depends on the type of hydrocarbon, presence of surfactants (e.g., corrosion inhibitors), the ionic content of the water, as well as the pressure, temperature, and flow rate (see section 4.3 for more information on emulsions). At high concentrations of water, oil and water exist as two distinct phases and different flow regimes can exist under these conditions. Figures 4.17 and 4.18 present typical flow regimes of oil and water mixture in horizontal pipe and Figure 4.19 presents typical flow regimes in vertical pipe.26–28 Typically, the density of oil is less than that of water, and as a result stratification occurs (Figure 4.18). When the density of oil (e.g., heavy oil) is similar to that of water the oil moves as a central core with water flowing in the annulus space (Figure 4.17).

4.2.2c Two-phase liquid-solid Liquid-solid flow occurs mainly in hydrotransport pipelines (see section 2.12), but it can also occur in liquid pipelines containing corrosion products and scales. Liquid-solid flow may exist in different flow regimes depending on the flow rate, particle size, and density difference between the solid and liquid (Figure 4.20).29 Below a minimum flow velocity in a horizontal pipeline (or below critical angles in inclined pipelines), solid particles in the fluid can form a bed on the bottom of the line. As the sand is produced, a sand bed will build up until the increased velocity above the bed is large enough to transport the particles further down the pipeline, where the particles settle again, resulting in an increase in the length of the sand bed. Deposition of the solids can lead to partial or complete blockage of flowlines,

4.2 Flow

Flow pattern

203

Superficial oil velocity V0 (ft s-1) 1.95

Water drops in oil 1.11 Oil in water concentric 0.682 Oil slugs in water 0.200 Oil globules in water Superficial water velocity

Vw = 0.682 ft s-1

FIGURE 4.17 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are almost Same).26 Reproduced with permission from Taylor & Francis.

0.491 Stratified 0.290 0.149

0.043 Oil globules in water Superficial water velocity Vw = 0.287 ft s-1 Superficial oil velocity ft/s

FIGURE 4.18 Flow Regimes of Oil and Water Mixture in a Horizontal Pipeline. (Densities of Oil and Water are Different).27 Reproduced with permission from Taylor & Francis.

underdeposit corrosion, microbiologically influenced corrosion (caused by sessile bacteria), and trapping of pigs. In sour media, the presence of solid sulfur enhances corrosion. As the flow rate increases, the sand may move in dune patterns. In a moving dunes pattern the sand will move along the pipeline at low velocities. All particles will be transported through the pipe under these conditions. As the flow rate further increases, the pattern changes to scouring. In a scouring

204

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Superficial oil velocity V0 (ft s-1) 0.015

0.06

0.18

0.55 1.2

3.0

9.0

Superficial water velocity Vw = 0.1 ft s-1

FIGURE 4.19 Flow Regimes of Oil and Water Mixture in a Vertical Pipeline.28 Reproduced with permission from Taylor & Francis.

FIGURE 4.20 Flow regimes of Liquid-Solid Flow.

pattern, the particles will move at the liquid velocity close to the pipe wall. At a sufficiently high velocity, a dispersed pattern will be established, in which the sand particles will move at the velocity of the bulk liquid phase. The transition between the various regimes is somewhat gradual with no sharp boundary. Depending on service conditions, any of the transitions between these regimes may be critical. For oil transportation, the transition between scouring and moving dunes may be critical. The flow velocity at this transition point will be lower than the velocity required to keep the sand suspended in oil but high enough to transport the sand through the pipeline. This flow velocity is often known as the critical velocity, Ucrit,SM and it is calculated using a general formula: Ucrit:SM ¼ a:Vsand dsand DDo s di

(Eqn. 4.47)

where a is a constant, Vsand is the solid volume; dp diameter of solid or sand particles; DDo–s difference in density between oil and solid phases; and di is the pipe internal diameter.

4.2 Flow

205

4.2.2d Two-phase gas-solid When gas is used as a conveying medium then the process is known as a pneumatic process. Gassolid flow occurs either in suspended or non-suspended forms. Suspended flow occurs when the volume of solid is small and when the velocity of gas is high. Non-suspended flow occurs when the volume of solid is larger and when the velocity of gas is low. Pneumatic conveying of solids is frequently used to transport coal and minerals, grains, foodstuffs, chemicals, and plastics, but is not a common method of transportation in the oil and gas industry. Gas-solid flow may occur in a gas pipeline containing corrosion products, frequently iron sulfide black powders. However, such a solid is assumed to have little effect on the gas flow due to the relatively small percentages occuring in most conditions.

4.2.3 Water accumulation Internal corrosion occurs in oil and gas infrastructure only when water accumulates on metallic surfaces. Many oil and gas infrastructures, e.g., oil transmission and gas transmission pipelines operate under conditions of extremely low water content (typically less than 0.5% by weight). Determining the locations where water may accumulate in those infrastructures is critical. The accumulation of water depends on oil, water, and gas characteristics, the inclination of the pipe, the flow velocity, and the cleanliness of the pipeline. Several methodologies and rules of thumb are available to determine the likelihood of water accumulation, leading to the establishment of corrosion conditions. Every methodology has its advantages and limitations, therefore in using a particular methodology, its characteristics and limitations should be understood. Some methodologies are described in this section. In order to predict the locations of water accumulation, three broad categories are established: single phase oil, single phase gas, and multi phase. Flow is considered as single phase oil when 95% of the products it transmits are oil, i.e.: 
P:R:oil > 0:95 (Eqn. 4.48) P:R:oil þ P:R:water þ P:R:gas The flow is considered as a single phase gas when the water content is less than 7 mmscf and the gas to liquid production rate ratio is higher than 5,000, i.e.: 
P:R:gas > 5; 000 (Eqn. 4.49) P:R:oil þ P:R:water where P.R.gas, P.R.oil, and P.R.water are the production rates of gas, oil, and water, respectively. The flow is considered to be multiphase when it does not meet the conditions of Eqns. 4.48 or 4.49.

4.2.3a Single phase oil Based on field experience, it is commonly assumed that if the oil flow rate is higher than 1 m/s and if the water content is less than 20% water does not accumulate.30,31 Field experience has also indicated that water accumulation depends on the nature of the oil, and in some cases an 0.5 m/s oil flow rate is sufficient to avoid any accumulation of water. A parameter known as the Froude number (Fr) is used to predict the water accumulation tendency in a single phase oil pipeline. Several definitions of the

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Froude number are available, and most of them for single phase flow takes the form presented in Eqn. 4.50:32–37 Fr ¼

Doil VL DDo w gdpipe

(Eqn. 4.50)

where Fr is the Froude number, Doil is the density of oil, DDo-w is the density difference between oil and water, g is the acceleration due to gravity, dpipe is the hydraulic diameter of pipe, and VL is the velocity of the liquid. In most situations, the critical Froude number for water accumulation is assumed to be approximately 0.65; above this value, water does not accumulate and below this value water is likely to accumulate. The critical Froude number is found to be inversely proportional to the inclination angle of the pipeline.38 Standards providing guidelines for calculating the accumulation of water in single phase oil pipelines include: •

NACE SP0208, ‘Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines’

4.2.3b Single phase gas In normally dry gas transmission pipelines the flow is single phase. When water accidently enters into the system, it may be carried as droplets in the gas flow, or accumulates in localized regions along the pipeline. To determine the locations where water may accumulate, two parameters are determined: inclination angle of the pipeline based on field topography, and the critical angle above which the flow cannot carry the water through. In the locations of the pipe where the inclination angle is greater than the critical angle water accumulation occurs. The critical angle is determined as:33 !1:091 rg Ug 2 qCA ¼ arcsin 0:675$ (Eqn. 4.51) $ rl rg g$di where qCA is the critical angle; rg is the density of gas (kg/m3); rl is the density of liquid (kg/m3); Ug is the gas flow rate (m/s); g is the acceleration due to gravity (9.81 m/s2); and di is the inner pipe diameter (m). The flow rate of gas (Ug) cannot be calculated directly from the production rate of gas because this is measured at standard temperature and pressure (STP). Hence, the production rate of gas at STP is converted into the production rate of gas at pipeline operating temperatures and pressures, using either the compressibility factor (Zgas) (Eqn. 4.52) or Van der Waal’s real gas equation (Eqn. 4.53). From Eqn. 4.16: Pstp Vstp PV ¼ RTstp ZRT


 an2 p þ 2  V nb ¼ RT V

(Eqn. 4.52) (Eqn. 4.53)

4.2 Flow

207

Table 4.5 Comparison of Results Using Compressibility Factor (Z) versus Van der Waal’s Equation39 Parameter Gas Velocity (m/s) Critical Angle, degrees

Result from Compressibility Factor

Result from Van der Waal’s Equation

% Difference between the Two Approaches

6.6 5.9

5.9 4.4

11.8 28.0

The calculations were performed for 100% methane gas using the following values: ll ¼ 1.0 g/cm3, g ¼ 9.81m/s2, di ¼ 0.745 m, P ¼ 35.05 atm, T ¼ 298K, VSTP ¼ 4.13 x 108 L/h, TSTP ¼ 273K, PSTP ¼ 1.000 atm, R ¼ 0.08206 L atm/mol K, AVan ¼ 2.25 L2atm/mol2, bVan ¼ 0.0428 L/mol

where P is the pressure; PSTP is the pressure at STP; V is the volume; VSTP is the volume at STP; TSTP is the temperature at STP; R is the gas constant; and T is the temperature; and aVan and BVan are Van der Waal’s constants. Van der Waal’s equation Eqn. 4.53 is similar to using the compressibility factor, in that it is a modification of the ideal gas law to simulate non-ideal gas behavior. Unlike the compressibility factor method, Van der Waal’s equation contains two constants which change with the gas being simulated, and Van der Waal’s equation is cubic in form, which is better for simulating a non-ideal system. The advantage of using this method is increased accuracy, the disadvantage is the complicated mathematics involved in cubic equations.39 Table 4.5 shows the difference in results obtained by using compressibility factor and Van der Waal’s equation. Standards providing guidelines for calculating the accumulation of water in single phase gas pipelines include: •

NACE SP0206, ‘Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Gas (DG-ICDA)’

4.2.3c Multiphase When two phases are transported in a pipe, the flow velocity is frequently inadequate to uniformly transport both phases at the same rate. As a result, the gas flows faster than the liquid and there is a hold-up of liquid. This means that the volume of liquid in some areas along the pipeline is higher than the normal liquid to gas ratio. The amount of liquid hold-up depends on gravity, the inclination of the pipe, and the flow velocity. Numerous equations and commercial software are available to calculate liquid hold-up.

i. Two-phase The rate of deposition of liquid from the gas phase may be calculated as:40 mD ¼ kd $Cw

(Eqn. 4.54)

where mD is the rate of deposition (mass per unit peripheral area per unit time); kd is the deposition mass transfer coefficient; and Cw is the concentration of droplets in the gas core (mass per unit volume calculated on a homogeneous basis).

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

The value of kd is calculated as: kd ¼

Vc) :87

sffiffiffiffiffiffiffiffiffiffiffi h2l DsrL

(Eqn. 4.55)

where VC) is the core friction velocity (defined in Eqn. 4.56); hl is the liquid phase viscosity; di is the internal diameter of pipe, m; s is the surface tension kg/s2; and rl is the liquid phase density (kg/m3). rffiffiffiffiffi si (Eqn. 4.56) VC) ¼ rg where si is the interfacial shear stress in the absence of interface mass transfer, N/m2 and rg is the gas density, kg/m3.

ii. Three-phase When oil, water, and gas phases are involved the liquid fraction, l, is first calculated as: l¼

P:R:oil þ P:R:water P:R:oil þ P:R:water þ P:R:gas

(Eqn. 4.57)

where P.R.oil is the oil volumetric flow rate (m3/d); P.R.water is the water volumetric flow rate (m3/d), and P.R.gas is the gas volumetric flow rate (m3/d). Then the modified Froude number for multiphase flow is calculated as: ! ! rl rg g$di $sinðqÞ (Eqn. 4.58) $ Fr ¼ rg Vg 2 where rl is the liquid density (kg/m3); rg is the gas density (kg/m3); g is the gravity constant (9.81 m/s2); di is the inner pipe diameter (m); Vg is the gas flow rate (m/s); and q is the angle of pipe inclination. Based on the liquid fraction (Eqn. 4.57), modified Froude number (Eqn. 4.58), and flow regimes (section 4.2.2) the liquid hold-up (HL) is then calculated using the formulae presented in Table 4.6.41,42 The same calculations may also be used for two-phase flow by deleting the flow rate of oil or water as appropriate from Eqn. 4.57, and replacing the liquid density with the appropriate density of oil or water in Eqn. 4.58.

4.2.4 Effect of flow on corrosion In addition to determining the pressure drop, flow regimes, and locations where corrosion may take place (i.e., where water accumulates), the flow may directly affect corrosion in three ways: mass transfer, momentum transfer, and phase transfer. A complete understanding of the effect of flow on corrosion should also include heat transfer; however heat transfer in most oil and gas infrastructure (production, transmission, and product pipelines) is not sufficient to affect the corrosion. Heat transfer effect may be important in the refinery operating conditions (see section 2.31) and top-of-the line corrosion (see section 5.24).

4.2.4a Mass transfer Flow may influence corrosion by bringing corrosive species (e.g., dissolved oxygen) towards the metal surface or moving corrosion products away from the metal surface. Flow may decrease corrosion rate

4.2 Flow

209

Table 4.6 Liquid Hold-Up Calculation41,42 Pipe Orientation

Flow Regime

Incline

• • • • • • •

Incline

Horizontal

Wave Annular Stratified Annular Mist Annular Wispy Annular Annular Mist

Liquid Hold-up Equation

HLð1Þ ¼

0:98$l0:4846 Fr 0:0868

• Slug • Churn, Plug • Oscillatory

HLð2Þ ¼

0:845$l0:5351 Fr 0:0172

• Dispersed • Bubble • Slug

HLð3Þ ¼

1:065$l0:5825 Fr 0:0609

by removing corrosive species from the metal surface; a mass transfer coefficient is used to represent this effect. The mass transfer coefficient is the rate at which the reactants (or products) are transferred to the surface (or removed from it). The mass transfer in various geometries is assumed to be similar if the mass transfer coefficients are equal. The mass transfer coefficient, kcoeff is expressed as:43 Di kcoeff ¼ Sh$ L

(Eqn. 4.59)

where Sh is the Sherwood number (see Eqn. 4.60); Di is the diffusivity of species i, m2/s; and L is characteristic length, e.g., diameter of pipe, m. Sh ¼

0:62048Sc1=3 Re1=2 1 þ 0:2980Sc 1=3 þ 0:14514Sc

2=3

(Eqn. 4.60)

where Sc is the Schmidt number, dimensionless (see Eqn. 4.61) and Re is the Reynolds number (see Eqn. 4.5) h Sc ¼ (Eqn. 4.61) rDi

4.2.4b Momentum transfer An increase in corrosion due to momentum transfer is commonly known as flow-induced localized corrosion (FILC), and the wall shear stress is used to represent its effect. FILC occurs due to increasing turbulence intensity and mass transfer as a result of flow over a surface and is different from erosioncorrosion (see section 4.2.4c).44 The wall shear stress is a measure of the viscous energy loss within the turbulent boundary layer and is related to the intensity of turbulence in the fluid acting on the wall. Wall shear stress and mass transfer are intimately linked and their individual contributions to flowaccelerated corrosion cannot be delineated either experimentally or mathematically. Changes to flow that affect the mass transfer coefficient will affect the wall shear stress, and vice versa.

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Wall shear stress is the force per unit area on the pipe due to fluid friction. The wall shear stress, Wss, in Pascal, can be calculated as: fU 2 r (Eqn. 4.62) 2 where f is the friction factor (dimensionless); U is the flow rate (m/s); and r is the density (kg/m3). Alternatively the wall shear stress may also be determined experimentally as: 

DP di (Eqn. 4.63) Wss ¼ 4 DLpipe Wss ¼

where DP is the pressure drop over a specific length (DL) of pipe of specific diameter (di).

4.2.4c Phase transfer In the presence of a second phase, flow may affect corrosion in two ways: erosion-corrosion and underdeposit corrosion. The second phase may be gas, liquid, or solid and the primary phase is mostly liquid, but it can also be gas. Under high flow conditions, the flow impinges the second phase (e.g., sand or liquid) on the surface, causing erosion-corrosion (see sections 5.11 and 6.6) or collapses the second phase (e.g., gas) causing cavitation corrosion (see section 5.10):45 Under low flow conditions, the second phase (mostly sand or other solid particles) deposits in localized areas, causing under-deposit corrosion and blocking access of the inhibitor to the surface. These locations are susceptible to localized corrosion in the form of pits. Guidelines to predict critical flow below which solid deposition occurs have been established on the basis of laboratory experiments. In horizontal pipes solid deposition occurs if the flow rate is less than the following value:46 5:305  10

6 ð314:96d

ðdi =2Þ

i

þ 20Þ

2

m=s

(Eqn. 4.64)

where di is the internal diameter of pipe in meters. Solid deposition does not occur in pipes inclined downwards. In pipes inclined upwards, solid deposition depends on flow rate, inclination angle, and pipe diameter. For an incline of less than 40 , deposition occurs if the flow rate is less than the following value: 5:305  10

6 ð314:96d

ðdi =2Þ

i

2

þ 16Þ

m=s

(Eqn. 4.65)

For an incline of greater than 40 , deposition occurs if the following relationship holds: ½U þ 8ð39:4:di


2 di 2Š60000pU þ 8ð39:4di 2

2Þ < ½ð

0:5qÞ53:3Š

(Eqn. 4.66)

where U is flow rate in m/s and q is the angle of inclination in rad. Eqns. 4.64 through 4.66 are only applicable over the range of parameters analyzed in tests.46 The density and size of solids, the density and viscosity of liquids, the pipe diameters evaluated, and the

4.3 Oil phase

211

relative length/diameter of the flow loop used in these investigations influence the solid deposition. Other methodologies for determining locations for solids to deposit are presented in: •

NACE Standard Practice SP0208–08, Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines (LP-ICDA)

These methodologies have been found to be reliable for solid deposition from light oil. However, for heavy oil, it has been found that solids deposit downstream of over-bends.47 A computational fluid dynamics (CFD) study of a representative segment of a transmission pipeline suggests that the main reason for the observed solids deposition downstream of over-bends in pipelines carrying heavy crude oil is that the wall boundary layer is thicker for heavy oil than for light oil. This thicker boundary layer leads to lower near-wall velocities than for the light oil case. This effect is especially pronounced for heavy oils downstream of over-bends, where the boundary layer is even thicker and near-wall velocities even slower. Extremely slow velocity makes the particles susceptible to becoming trapped in existing corrosion pits or stationary solid deposits. Conversely, it was found that, for light oil, even though the particles fall quickly to the pipe floor, the relatively rapid near-wall velocity keeps them moving.48

4.3 Oil phase Crude oils are corrosive at the higher temperatures prevailing in the refinery (see section 3.31), but are non-corrosive at lower temperatures. At lower temperatures, crude oils have low conductivity, i.e., they are poor electrolytes (see section 5.2 for details), preventing electrochemical reactions from occuring.49–53 However at lower temperatures crude oils may influence the corrosivity of an aqueous phase with which they are in contact. The corrosivity of crudes depends on their chemical and physical constituents, emulsion type, wettability, and partition of chemicals between oil and aqueous phase.

4.3.1 Chemical and physical constituents Chemical constituents affect corrosion only at temperatures high enough to liberate them but low enough for water to exist as liquid. Such conditions normally occur in certain parts of the refineries (see section 3.31). On the other hand, constituents such as solids or paraffins may affect the corrosivity of the water phase which is in contact with crude oils at lower temperatures (typically below 158 F (70 C)). The influence of specific chemicals on the corrosivity of crude oils is discussed in this section.

4.3.1a Inorganic salts Analyses of crudes indicate that over 2,000 mg/L (70 LB/100BBL) of inorganic salts can be extracted from corrosive crudes and about 20 times less from non-corrosive crudes.54 The chloride content is usually referred to as total salt. The total salt may sometimes be used as an index of corrosivity. It should be noted that only salts that produce hydrogen chloride [HCl] at high temperatures are corrosive. In general, the total amount of HCl liberated is proportional to the salt content. A direct estimate of HCl provides a measure of the corrosivity of the crudes. Factors affecting the amount of HCl liberated at high temperatures typically occurring in the refinery operation conditions

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

include ratio of calcium (Ca) and magnesium (Mg) to sodium (Na) and pH. If about 10% of chlorides are present in the form of Ca and Mg salts and the pH is alkaline, less HCl is liberated; on the other hand, if the Ca and Mg salts are about 20% and if the brine pH is acidic, the amount of HCl liberated is high.55

4.3.1b Sulfur content It has been known for many years that the greatest single cause of crude oil corrosion at higher temperatures occurring in the refinery operating conditions is the presence of sulfur compounds, but there is no direct correlation between sulfur content and corrosivity.56,57 The controlling factor with respect to corrosion is not the sulfur content, but the degree to which the sulfur compounds decompose to form more corrosive constituents such as H2S and HCl. The sulfur content of crude oil is usually less than 1%.58 The sulfur contents of heavier crudes may be in the range 2.0–3.5%. A McConomy curve is used to predict the corrosivity of crude oil based on its sulfur content. Figure 4.21 presents two versions of the McConomy curve.59 However it should be noted that only those sulfur compounds that liberate H2S at high temperatures are important. The total sulfur of certain crudes may be lower (less than 1%), but the H2S liberated may be higher (typically 60–450 mg/L [20–150 LB/1000 BBL]). Sulfur compounds may provide corrosion protection when stable sulfide layers form on the metal surface.

4.3.1c Organic acids Of the organic acids, naphthenic acid is most important with respect to the corrosivity of crude oil at higher temperatures. Naphthenic acids cause corrosion in vacuum units of refineries operating between 428 and 700 F (220 and 370 C). No corrosion occurs at temperatures above 752 F (400 C) due to the decomposition of naphthenic acids. No corrosion product is formed in the presence of naphthenic acid. In addition to carbon steel, stainless steels (12% Cr, 316 SS, 317 SS, and 6% Mo) are also susceptible to naphthenic acid. One study has indicated that the product of the organic nitrogen and naphthenic acid content is inversely proportional to the corrosion rate of steel at lower temperatures (less than 70 C).60 In addition to naphthenic acid, other organic acids including formic, acetic, and propionic acids may also influence the corrosivity of the crude oils at lower temperatures.61 These acids influence the corrosivity of aqueous phase in contact with crude oil by supplying hydrogen ions which undergo cathodic reactions during the corrosion of metals (see section 5.2): HCOOH/Hþ þ HCOO

(Eqn. 4.67)

CH3 COOH/Hþ þ CH3 COO

(Eqn. 4.68)

COOH/Hþ

(Eqn. 4.69)

Formic acid : Acetic acid : Propionic acid :

CH3 CH2

þ CH3 CH2 COO

4.3.1d Dissolved gases62–66 Oxygen, carbon dioxide and hydrogen sulfide are the main corrosive gases. H2S is more soluble in hydrocarbons than in water. The ratio of the concentration of H2S in hydrocarbon to that in water is 1.7 at 32 C (90 F); 1.67 at 29 C (84 F) for mineral oil; 5.95 at 31 C (88 F) for benzene; 2.4 at 31 C (88 F) in kerosene; and 2.65 at 31 C (88 F) for iso-octane. The saturation concentration of H2S in crude oil is 5,000 ppm, whereas normal concentrations are found to be in the range of 100–200 ppm. The solubility of CO2 and oxygen in hydrocarbons is also higher than they are in water.

4.3 Oil phase

Corrosion rate multiplier

100 50 20 10 5 2 1 0.5

213

Carbon Steel 1 – 3Cr

4 – 6Cr

9Cr

0.2 12Cr 0.1 0.05 18/8 Sulfur content:.0.6wt% 0.02 0.01 450 500 550 600 650 700 750 800 Tempature F

Modified McConomy Curve [1]

Sulfer content, wt%

10 5 2 1 0.5 0.2 0.1 0.05 0.02 0.01 0.4

0.8 1.2 1.6 Corrosion rate multipiler

2.0

Correction curve for sulfur content [1]

FIGURE 4.21 McConomy Curve to Predict the Effect of Sulfur Content in Crude Oils on High-Temperature Corrosion Rate.59

4.3.1e Solids Crudes may contain solids and sediments as finely divided particles of siliceous matter.67 At high velocities the solids may be swept along with the flow while at low velocities they settle at the bottom of the pipe. When they settle, they shield the pipe and facilitate the occurrence of corrosion beneath them (underdeposit corrosion). The extent of corrosion depends on the amount and composition of solids.

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

4.3.1f Paraffin Paraffin is a mixture of aliphatic and aromatic hydrocarbons, asphalts, resins, and naphthenes. Crude oils contain paraffin as suspensions of 1–100 mm (0.04–4 mil). The paraffin layer on the pipe wall protects it, but when the layer entraps water localized corrosion may take place.

4.3.2 Emulsion type Because of their non-polar nature, crude oils cannot dissolve ionic water. However, at low concentrations of water, crude oil can form an emulsion with water. The type of emulsion and its stability depends on the type of crude oil, composition of water, presence of surfactants, operating pressure, temperature, and flow rate. There are two kinds of emulsion: water-in-oil and oil-in-water. In water-in-oil emulsions, the nonionic (non-conducting) oil is the continuous phase in which the ionic water is dispersed. Therefore, corrosion does not occur in the presence of a water-in-oil emulsion; since oil is a non-conducting electrolyte, corrosion does not take place. On the other hand, in oil-in-water emulsions the ionic (conducting) water forms the continuous phase in which the non-ionic oil is dispersed. Therefore, corrosion occurs in the presence of oil-in-water emulsions. The water-cut at which a water-in-oil emulsion inverts into an oil-in-water emulsion is known as the ‘emulsion inversion point’ (EIP) (Figure 4.22).68,69 By measuring the conductivity of the emulsion under flowing conditions the type of emulsion can be determined.70 Standard providing guidelines to measure EIP include: •

ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’

FIGURE 4.22 Schematic Diagram of the Experimental Section of Emulsion Inversion Point Apparatus.70 Reproduced with permission from ASTM.

4.3 Oil phase

215

4.3.3 Wettability The probability of corrosion in the presence of an oil-in-water emulsion or free water depends on the wettability. When the oil phase preferentially wets the surface (oil-wet), corrosion is negligible; but when the water phase preferentially wets the surface (water-wet), corrosion does take place; and when no phase preferentially wets the surface (mixed-wet), corrosion may or may not take place. It should be pointed out that emulsion and wettability are two different properties. The emulsion depends on the interaction between two phases: water phase and oil phase, whereas the wettability depends on three phases: water phase, oil phase, and solid phase (e.g., pipeline steel). A crude oil may have high EIP, i.e., it may hold water in the water-in-oil phase, but as soon as the EIP is reached water drops out and wets the surface. On the other hand, the crude oil may have a low EIP, i.e., water drops out even when present in low concentration, but the surface may continue to be oil-wet, reducing the possibility of corrosion. The wettability can be estimated by considering the relative surface energies of all the interfaces involved. A water-steel interface will be replaced by an oil-steel interface if the energy of the system decreases as a result of this action (that is, the tendency of oil to displace water from steel). The difference in surface energy (Dwo) between a steel-oil and a steel-water interface can be calculated from measured values of the contact angle (qCaw) and the water-oil interfacial tension (gwo) as: Dwo ¼ gwo $cos qCaw

(Eqn. 4.70)

It follows that displacement of water by oil should be expected when qCaw is between 90 and 180 ; on the other hand, displacement of oil by water would be expected when qCaw is between 0 and 90 (Figure 4.23). The contact angle method is extensively used to determine the wettability of different surfaces. The oil and water may be added in two sequences: oil-first water-next sequence or water-first, oil-next sequence. The first sequence represents the case of oil transmission pipelines, but measuring the contact angle using this sequence is relatively difficult. Due to the dark background of the oil, the wo

Caw

so

sw

FIGURE 4.23 Principle behind Determining Wettability using Contact Angle Measurement.70 Reproduced with permission from ASTM.

216

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

FIGURE 4.24 Schematic Diagram of Apparatus to Determine Wettability using Spread Method.70 Reproduced with permission from ASTM.

apparatus should be illuminated. For this reason, the contact angle is normally measured in a waterfirst, oil-next sequence. However, this sequence does not truly represent the oil transmission pipeline operating conditions. The spreading method overcomes these difficulties. This method measures the conductivity across a series of 20 steel pins imbedded in non-conducting material (Figure 4.24). The conductivity is measured between a central reference pin and series of outer test pins. Based on how many measurements exhibit high resistance (low conductivity), the crude oil is classified as: • • •

Oil-wet (less than five of the 20 pins exhibit high conductivity) Mixed-wet (between five and 15 of the 20 pins exhibit high conductivity) Water-wet (more than 15 of the 20 pins exhibit high conductivity)

Although this apparatus can be operated at elevated pressures, the boundary for differentiating different wettabilities is arbitrary. Standard providing guidelines to measure wettability include: •

ASTM G205, ‘Standard Guide for Determining Corrosivity of Crude Oils’

4.3.4 Partition of chemicals between oil and water phases In the presence of an oil-in-water emulsion or free water phase on a water-wet surface; corrosion may take place. The crude oil phase surrounding the water phase may influence corrosion by partitioning water-soluble species into it. If the water-soluble species are corrosive in nature, the corrosivity of the aqueous phase would increase and be greater than that observed without an oil phase. On the other hand, if water-soluble species are inhibitive in nature, the corrosivity of the aqueous phase would decrease and be less than that observed without an oil phase. In order to understand the influence of an oil phase on the corrosivity of a water phase, tests should be performed using both oil and water phases

4.4 Water (Brine or Aqueous) phase

217

No Corrosion

W/O Emulsion O/W

Oil-Wet Wettability

No Corrosion

Mixed-Wet Water-Wet

Less then 0.01 mpy (Preventive Hydrocarbon)

Corrosivity of Brine in the Presence of Hydrocarbon

No Corrosion

Less then Absence of Hydrocarbons (Inhibitive Hydrocarbon)

Reduced Corrosion

No Change (Neutral Hydrocarbon)

Aqueous Corrosion

Higher then Absence of Hydrocarbons (Corrosive Hydrocarbon)

Accelerated Corrosion

FIGURE 4.25 Classification of Crude Oil (Hydrocarbons) based on Corrosivity (ASTM G205).70 Reproduced with permission from ASTM.

in a laboratory methodology (see section 8.2.2a). Based on the results, the overall corrosivity of oil may be established (Figure 4.25).

4.4 Water (Brine or Aqueous) phase The water phase may also be identified as brine solution, brine, or aqueous phase. The source and composition of the water used in various sectors of the oil and gas industry vary considerably. The water phase sustains corrosion by being a good electrolytic conductor (‘E’ in the ACME; see section 5.2). Deionized water does not contain ionic species, is a poor-conductor, and hence does not support corrosion. As the concentration of ions increases, the corrosivity of water increases. The ionic species influence the corrosivity of water in several ways: they increase conductivity of water, participate in electrochemical corrosion reactions (e.g., oxygen, by forming hydroxyl ion, may undergo cathodic reduction reaction), and change the properties of surface layers (e.g., chloride ions destroy many oxide surface layers leading to localized corrosion). The corrosivity of water depends on the nature as well as the concentrations of both anions and cations.

218

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

4.4.1 Effect of anions The dominant anions affecting corrosion are halide ions, of which chloride ion is the most significant. Figure 4.26 presents the variation in corrosion rate of iron in air-saturated distilled water at room temperature as a function of Cl ion concentration (added in the form of NaCl). The corrosion rate increases as a function of NaCl concentration up to 3% NaCl. The concentration of oxygen is highest in pure distilled water, but its solution resistance is also high (i.e., the solution conductivity is low), so the corrosion rate is low. Addition of NaCl increases the solution’s conductivity, so the corrosion rate increases. At around 3% NaCl the solution conductivity reaches levels sufficient for the oxygen effect to become dominant. As the NaCl concentration increases above 3%, the dissolved oxygen content decreases; consequently the corrosion rate decreases. At about 26% NaCl the corrosion rate is as low as that in distilled water. The most prominent effect of chloride is, however, in initiating localized corrosion of metals. One study found that the tendency to initiate pits increases with increase in chloride ion concentration in the range 10,000 to 120,000 ppm, and that the effect of chloride ion depends on the presence of other ionic species.72 Depending on other factors, the presence of 5% chloride ion may increase localized pitting corrosion rate by 100 mpy.73 The chloride ion increases the susceptibility of metal to localized pitting corrosion by penetrating and destroying the oxide or other surface layers that are otherwise protective. Other halides may also initiate pitting corrosion, but the effect decreases in the order chloride > bromide > iodide > fluoride. Sulfate, bicarbonate, and phosphate ions in general decrease the susceptibility to pitting corrosion. In the presence of phosphate ions, the susceptibility to pit initiation decreases in the order: H2PO4 > HPO24 > PO34 .

3

Relative Corrosion Rate

3% NaCl

2

1

0 0

5

10

15 20 Concentration of NaCl (wt. %)

25

30

FIGURE 4.26 Corrosion Rate of Iron in Aerated Solution at Room Temperature as a Function of NaCl.71

35

4.4 Water (Brine or Aqueous) phase

219

4.4.2 Effect of cations74,75 Studies indicate that most of the univalent cations (Liþ, Naþ, Kþ, and Rbþ) increase susceptibility to pitting corrosion in various metals; the effect increases with the size of the ion. The bivalent cation Zn2þ may also increase the susceptibility of metals to pitting corrosion, initiating pitting by hydrolysis of the zinc salt. However most bivalent cations, such as Mg2þ, Ca2þ, Ba2þ, Sr2þ and Mo2þ, decrease susceptibility to pitting corrosion.

4.4.3 The combined effect of anions and cations In order to maintain the charge balance, equal amounts of anions and cations exist in solution. Therefore the combined effect of anions and cations needs to be understood. The cations and anions may combine to form a salt that may precipitate as scale. Formation of scale may plug pipes and equipment, and may lead to underdeposit corrosion. The tendency to form scale depends on the solubility. Solubility is a measure of maximum amount of solute (e.g., NaCl) which can be dissolved in a solvent (e.g., water phase), and this depends on pressure, temperature, and pH. Although several types of scales can form calcium carbonate (CaCO3) (commonly known as calcite), calcium sulfate (CaSO4), barium sulfate (BaSO4), and strontium sulfate (SrSO4) scales are all common in the oil and gas industry. Calcium carbonate scale forms by the reaction between calcium with carbonate (Eqn. 4.71) or bicarbonate (Eqn. 4.72) ions: Ca2þ þ CO3 2 Ca2þ þ 2HCO3

> CaCO3 > CaCO3 þ CO2 þ H2 O

(Eqn. 4.71) (Eqn. 4.72)

Normally, calcium carbonate scale forms in downhole tubulars due to release of CO2 when the pressure drops. Calcium sulfate scale forms when calcium ions combine with sulfate ions: Ca2þ þ SO4 2

> CaSO4

(Eqn. 4.73)

Calcium sulfate scale may be anhydrous (CaSO4) or hydrated (CaSO4.2H2O) (commonly known as gypsum). Normally, calcium sulfate scale forms in seawater because this contains high sulfate concentrations. In addition, barium sulfate (Eqn. 4.74) and strontium sulfate (Eqn. 4.75) scales, and to a smaller extent calcium fluoride scale, also form in the oil and gas production sector: Ba2þ þ SO4 2

> BaSO4

(Eqn. 4.74)

Sr2þ þ SO4 2

> SrSO4

(Eqn. 4.75)

The tendency to form scale is determined using saturation index (SI): SI ¼ log10 ðSRÞ

(Eqn. 4.76)

where SR is the saturation ratio; it is the ratio of the ionic product at a given concentration to that under saturation conditions. For example, for calcium carbonate the saturation ratio is defined as:  2þ  2 Ca : CO3 (Eqn. 4.77) SR ¼ 2þ ½Ca Šsatn: :½CO23 Šsatn:

220

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

where [Ca2þ] is the concentration of calcium ion in solution; [CO23 ] is the concentration of carbonate in solution; [Ca2þ]satn. and [CO23 ]satn. are the respective concentrations at the saturation point. For a given solution, if SR is unity, the solution is saturated with CaCO3 and scale can potentially form; if SR less than unity, the solution is undersaturated with CaCO3 and scale will not form; and SR is greater than unity the solution is supersaturated with CaCO3 and scale can form (precipitation is a kinetic driven process, so we may not see scale even when SR is greater than unity).

4.5 CO2 In the 1950s, corrosion was encountered in high pressure sweet oil wells, which, at that time, were thought to be non-corrosive. Based on a statistical analysis of data from several companies, the NACE TP-1C76 committee found that: general pitting-type corrosion occurs frequently in oil-producing pipe lines; corrosion starts once the wells begin producing water; pitting frequency varies with thickness of the pipe and the number of pits is higher at points of maximum wall thickness; and unique and unexplained scale conditions obscure the interpretation of caliper surveys (see section 8.4.9). An economic analysis at that time indicated that $1,500,000 must be spent within the next four years because of corrosion in 150 wells concentrated in a small geographic area located in SouthEastern Louisiana.77 Since the 1950s, several groups have studied the corrosion of carbon steel in CO2 solution. Carbon dioxide is soluble in the aqueous phase; concentrations of CO2 increase with a decrease in temperature. Normal solution CO2 concentrations are in the range 265–320 ppm at 80 C (176 F), and 1125–1720 ppm at 20 C (68 F).78 CO2 dissolved in water hydrates to become carbonic acid (H2CO3).79–82 This hydration reaction is a slow process; hence, only a small fraction of aqueous CO2 exists as H2CO3. The dissociation of H2CO3 produces carbonate (CO23 ) and bicarbonate (HCO3 ) ions. Within the pH range 6 to 10, HCO3 exists predominantly and above pH 10, CO23 predominates. Accordingly, the corrosion of carbon steel produces both Fe(HCO3)2 (below pH 10) and FeCO3 (above pH 10), but in practice only FeCO3 is observed. Thus the overall corrosion of carbon steel in CO2 environment may be written as:83 Fe þ H2 CO3 /FeCO3 þ H2

(Eqn. 4.78)

Corrosion takes place without a corrosion layer if the Fe2þ and CO23 concentrations are below the solubility limit. When the concentrations of Fe2þ and CO23 exceed the solubility limit, corrosion layers form.84 Sometimes a FeCO3 surface layer does not form until the solution concentrations of Fe2þ and CO23 are five to ten times more than the values obtained from thermodynamic calculations. A solution is considered as supersaturated when the concentrations of Fe2þ and CO23 in it exceed values from thermodynamic calculations. The extent to which the solution is in the supersaturated condition (before FeCO3 surface layer formation) depends on pH, surface-volume ratio, and temperature. The supersaturation stage occurs because the precipitation rate of FeCO3 is slow.85,86 When the surface layer is formed, the corrosion rate decreases, and the extent of decrease depends on temperature, velocity, pH, H2S, and steel type. Several other mechanisms have been proposed for the formation of FeCO3. Irrespective of the mechanisms by which they form, an intact FeCO3 surface layer reduces corrosion and when FeCO3 is broken, localized pitting corrosion occurs.

4.5 CO2

221

4.5.1 Effect of temperature87–89 In general, corrosion rate increases with increase of temperature until reaching a maximum. Many studies indicate that formation of a FeCO3 surface layer is difficult at temperatures below 70 F (w20 C); surface layers formed between temperatures 70 and 100 F (w20 and 40 C) are not adherent and may be removed by wiping with a cloth; surface layers formed between 100 and 140 F (40 and 60 C) are non-protective; and surface layers form between 140 and 300 F (60 and 150 C) are hard, adherent, and protective. Figure 4.27 presents the distribution of pit densities on carbon steel exposed for 100 hours in CO2 solution as determined by laser profilometer.90 At 70 F (20 C); the pit density (i.e., number of pits per unit area) is higher but the pits are shallower – indicating a non-uniform, fragile surface layer. Between 70 and 175 F (20 and 75 C), as the temperature increases, the pit density decreases but the pits are deeper, indicating insufficient amounts of adherent surface layer; and between 170 and 250 F (75 and 120 C), as temperature increases both pit density and pit depth decrease, indicating the formation of adherent and protective surface layers.

4.5.2 Effect of velocity91–94 Velocity may facilitate the formation of a FeCO3 layer by promoting the dissolution of CO2 in the solution and by transporting of reactants to the surface. On the other hand, velocity may delay formation of a FeCO3 layer by transporting reaction products away from the surface, or it may completely prevent the formation of surface layer. Depending on the flow conditions, different forms of corrosion can take place in solutions containing CO2: pitting, mesa attack, FILC, and general corrosion. The boundary between these forms is not sharp, and depends on several factors including flow rate (single phase or multi phase), type of steel, pH, CO2 partial pressure, temperature, and the presence of other species (e.g., H2S). Pitting corrosion occurs under stagnant to low flow conditions, and is characterized by loss of metal in discrete areas of the surface, with surrounding areas remaining essentially unaffected or subject to general corrosion. These discrete areas may exist as circular depressions (pits) or slits (sometimes referred to as knife lines). Stepped depressions with flat-bottom and sharp-vertical side geometry, often referred to as mesa corrosion, occur at medium flow rate conditions (Figure 4.28).95 This type normally occurs when stable, hard, but non-adherent surface layers are exposed to moderate flow conditions. At very high flow velocities, the corrosion feature may take the form of parallel grooves extending in the flow direction; this phenomenon is known as FILC. FILC may start from pits or mesa corrosion above a critical flow velocity. The pits and mesa type corrosion features disturb the flow pattern and create local turbulence. This turbulence and stresses inherent in the surface layer may destroy and remove the surface layers, and the flow also prevents re-formation of a surface layer on the exposed metal. The velocity at which the surface layer is completely removed, or prevented from forming, is known as the critical velocity. Various studies indicate that the critical velocity varies between 4 and 6.5 feet/s (1.25 and 2 m/s).

4.5.3 Effect of microstructure96–102 In general, microstructural elements (e.g., pearlite, normalization) which promote anchoring of the surface layer decrease the corrosion rate, whereas elements (e.g., ferrite and cementite) which promote

222

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Profiles of the Outer Surface

Temperature oC

20

50

75

FIGURE 4.27 Distribution of Pits (as Determined by Laser Profilometer) on Carbon Steel in CO2 Atmosphere as a Function of Temperature.90 Reproduced with permission from NACE International.

4.5 CO2

223

90

120

FIGURE 4.27 (continued ).

FIGURE 4.28 Example of Mesa Type of Corrosion.95 Reproduced with permission from NACE International.

224

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Table 4.7 Characteristics of Surface Layers in Sweet Environment Characteristics

Magnetite

Cementite

Siderite

Name Chemical formula Color

Iron Oxide Fe3O4 Black

Metastable carbide Fe3C

Hardness Physical stat

5.5e6.5 Crystal

e Brittle

Iron Carbonate FeCO3 Gray, yellow, yellowish brown, greenishbrown, reddish brown and brown 3.5e4.5 Crystal

galvanic corrosion increase the corrosion rate. Table 4.7 presents the characteristics of surface layers. When iron corrodes away, leaving pearlite behind, cavities between pearlite facilitate an increase in the concentration of ferrous ions. Local flow stagnation and the higher local Fe2þ concentrations in the cavities allow the formation of an iron carbonate scale between the pearlite platelets. In addition, the pearlite helps to anchor the layer. This mechanism explains why adherent surface layers are formed on steel with a normalized microstructure rather than on steel with a quenched, tempered microstructure. When ferrite (a-Fe) microstructure preferentially corrodes, leaving cementite (Fe3C) behind, surface layer formation is hindered. Fe3C is a good electrical conductor; therefore the cathodic reaction occurs readily on Fe3C. This leads to galvanic coupling between the steel substrate and the Fe3C layer, promoting and sustaining corrosion. The effect of microstructure is evident at temperatures up to 60 C but diminishes above this. The FeCO3 surface layer makes the role of the underlying steel microstructure less pronounced.

4.5.4 Effect of pH103–108 A minimum pH is required for the formation and for the stability of surface layers. This minimum pH may vary between 4.2 and 6.0 depending on several other parameters including temperature, chemical species (CO2, carbonate, and bicarbonate), and flow rate.

4.5.5 Effect of H2S109–110 Small amounts of H2S may have some inhibitory effect on CO2 corrosion of steel, due to the formation of more protective iron sulfide (FeS). When the pCO2/pH2S ratio is above 5,000, sweet corrosion (controlled by FeCO3 surface layer) occurs. This ratio, however, may vary with temperature and pH.

4.6 H2S111–125 A historic test that is directly relevant to the understanding of iron and steel corrosion by elemental sulfur was conducted by Nemery in 1700. He mixed equal parts of iron filings and sulfur with water to form dough and buried it underground. This dough fermented and caught fire. The vigorous reaction lifted the soil, and this phenomenon led Nemery to the postulate that earthquakes occur due to similar reactions. This test indicated that iron reacts vigorously with sulfur in the presence of water.

4.6 H2S

225

Two-hundred and fifty years after Nemery’s test, Farrer and Wormwell patented the use of suspensions of sulfur in water as an etching medium for iron and steel. They found that such a suspension was corrosive to steel. They used this solution to assess the porosity of non-ferrous coatings on a ferrous base material. In the oil and gas industry, environments containing H2S are commonly known as sour environments. Sour environments cause two types of failures: sour corrosion and sulfide-stress cracking (SSC). Industry first experienced both these failures in the 1950s. Sour corrosion was first experienced in oil production fields in the USA, and SSC was first experienced in Western Canadian oil fields. Sour corrosion frequently caused – in some cases within 30 days of installation – broken sucker rods and perforated tubing. To control sour corrosion, 942 (about 26%) of the 3,618 wells operating in one location in 1950s were treated with corrosion inhibitors. (Section 5.18.4 discusses SSC in detail). Similar to CO2, H2S dissolved in water is a weak acid. In the absence of buffering ions, water equilibrated with H2S at atmospheric pressure reaches a pH value of about 4. Under higher pressures, the pH value can become as low as 3.114 Sulfur and H2S may occur naturally or may be generated by sulfate reducing bacteria (see section 4.9). At high pressure, sulfanes (the acid form of a polysulfide) are formed in the gas phase by the dissolution of elemental sulfur. As the pressure reduces (e.g., in production pipelines), the sulfanes in the gas phase dissociate to form elemental sulfur and, in the presence of water, sulfanes dissociate into H2S and elemental sulfur. Elemental sulfur may also be formed by the oxidation of H2S by air or by oxides (for example, iron oxides): 2H2 S þ O2 /2H2 O þ 2S

(Eqn. 4.79)

3H2 S þ 2FeOðOHÞ/2FeS þ S þ 4H2 O

(Eqn. 4.80)

This oxidation is detrimental for two reasons: it produces elemental sulfur, which causes severe sulfur corrosion, and further it produces water which makes dry and non-corrosive H2S becoming wet and corrosive. The solubility of sulfur in water increases with temperature (w10 ppm to 20 ppm at 77 F (25 C) to w50 ppm at 122 F (50 C)). The dissolution of sulfur in water produces H2S and sulfuric acid: 4S þ 4H2 O/3H2 S þ H2 SO4

(Eqn. 4.81)

This reaction is very slow at ambient temperatures, yet it occurs and produces enough H2S. Carbon steel or iron corrodes in the presence of H2S to produce FeS: Fe þ H2 S/FeS þ H2

(Eqn. 4.82)

The production of hydrogen atoms on the metal surface, as precursor to molecular hydrogen (Eqn. 4.82) leads to SSC (see section 5.18.4). Corrosion is however less severe in the presence of H2S than in the presence CO2 because the kinetics of formation of FeS is faster than those of FeCO3. Consequently, the surface layer of FeS is formed relatively quickly. However FeS is an electron-conductor; therefore it provides site for cathodic reactions to occur. Therefore a surface not fully covered by FeS may undergo severe localized corrosion. Iron sulfides may exist in different forms. Table 4.8 presents characteristics of these forms. The term kansite was used first in 1953–1955 for a corrosion product found in steel tubing in a Kansas oil well. In 1958, kansite Fe9S8 was described as a new iron sulfide, formed by action of H2S on steel. Based on very similar properties, to avoid confusion, the name kansite was dropped and the name

226

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Table 4.8 Common Species of Iron Sulphide123,124 Name

Stability

Chemical Formula

Pyrrhotite Trolite Mackinawite

Meta stable Stable Various degree

Marcasite Pyrite Greigite

Meta stable Stable (sulfide mineral) Metastable

Fe1-xS (e.g., Fe7S8) FeS Fe1þxS (x ¼ 0 to 0.1, e.g., Fe9S8)) FeS2 FeS2 Fe3S4

)

may be identified as kansite

Mackinawite was approved by the International Committee on Mineral Names. Since then many corrosion products of sour corrosion have been identified as Mackinawite.

4.6.1 Effect of temperature126–129 In general, at constant concentrations of H2S, the corrosion rate increases with temperature in the range 40 to 140 F (5 to 60 C). Temperature has no significant effect on corrosion rate in the range between 190 and 300 F (w90 and 150 C). At 302 F (w150 C), the surface layer is very hard and adherent. At 425 F (w220 C), the surface layer predominately consists of pyrrhotite, with small amounts of pyrite and trolite, which reduces the corrosion rate. High temperature (above 500 F [260 C]) corrosion of carbon steel may occur in the presence of H2S in reforming and desulfurizing units of refineries.

4.6.2 Effect of velocity130 Iron sulfides have low solubility (precipitation as surface layer is fast), good adherence onto steel, and good mechanical properties. For these reasons, velocity effects are generally not encountered in sour systems at velocities up to 30 m/s (100 ft/s).

4.6.3 Effect of microstructure131–132 Any microstructural changes (e.g., cold-working) that promote the formation of FeS on the surface decrease corrosion. On the other hand, any microstructural changes that promote galvanic corrosion increase corrosion. For example, the presence of a cementite phase acts as a cathode with respect to ferrite, and promotes dissolution of the ferritic phase. FeS is preferentially formed on cementite phases (which continues to act as cathode) further sustaining corrosion in the ferrite phase, leading to grooves on the metal surface.

4.6.4 Effect of pH133 In the pH range 1.7 to 2.7, iron continues to corrode and ferrous ion continues to dissolve without forming any FeS surface layer. The FeS layer starts to form at pH 2.8. Figure 4.29 presents the general variation of sour corrosion of carbon steel with pH.

4.7 O2

227

FIGURE 4.29 Variation of Corrosion Rate in H2S Medium with pH.133

4.6.5 Effect of CO2134–135 When the pCO2/pH2S ratio is below 5,000, sour corrosion (controlled by the FeS surface layer) occurs. This ratio, however, may vary with temperature and pH.

4.7 O2136 Although oxygen is not normally present at depths greater than approximately 100 m (330 ft) below the surface and is not intentionally added, it is nevertheless responsible for some corrosion encountered in the oil and gas industry. Oxygen is soluble in water. The solubility of oxygen in water increases with decreasing temperature (Figure 4.30).137–139 Even trace amounts of oxygen are sufficient to cause corrosion. Figure 4.31 provides a comparison of corrosion rates in oxygen, H2S, and CO2 atmospheres.140 The kinetics of oxygen reduction on steel is relatively fast. In the presence of oxygen, depending on the pH, two types cathodic reaction can take place: In acidic solution: O2 þ 4Hþ þ 4e /2H2 O

(Eqn. 4.83)

In neutral or alkaline solution: 1=2 O2 þ H2 O þ 2e /2 OH

(Eqn. 4.84)

228

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

OVERALL CORROSION RATE OF CARBON STEEL MPY

FIGURE 4.30 Dissolution of Oxygen in Aqueous Solution as a Function of Temperature.

O2

25

20 CO2

15

10 H2S

5

O2 1

2

3

4

5

6

7

8

H2S 100 200 300 400 500 600 700 800 CO2 50 100 150 200 250 300 350 400 DISSOLVED GAS CONCENTRATION IN WATER PHASE (PPM)

FIGURE 4.31 General Corrosion of Carbon Steel in the Presence of Oxygen, CO2 and H2S.140

4.7 O2

229

The overall reaction taking place during the corrosion of iron in the presence of oxygen is given by: Fe þ H2 O þ 1=2O2 /FeðOHÞ2

(Eqn. 4.85)

Ferrous hydroxide [Fe(OH)2], or hydrous ferrous oxide [FeO.nH2O] initially dissolves in the solution, saturates it, and finally forms a porous layer on the surface (green/blue). Fe(OH)2 is further oxidized to hydrous ferric oxide (reddish brown in color): FeðOHÞ2 þ 1=2H2 O þ 1=4O2 /FeðOHÞ3

(Eqn. 4.86)

A solution saturated with hydrous ferrous oxide has a pH of about 9.5. A solution saturated with hydrous ferric oxide has a neutral pH. Hydrous ferric oxide often turns black due to the formation of an intermediate hydrous ferrous-ferrite oxide (Fe2O3.FeO.nH2O or Fe3O4.nH2O). Thus, the surface layers of iron may consist of three or more forms of iron oxide, depending on the extent of oxidation and hydration (Table 4.9). Depending on environmental conditions, the oxide surface layers can be porous and non-protective, or compact and protective.141–154 The surface layers of iron oxides are stable even at higher temperatures. An adherent and protective magnetite has been observed even at 310 C.155

4.7.1 Effect of temperature It is generally accepted that, in the presence of oxygen, the corrosion rate of carbon steel doubles for every 30 C (90 F) increase in temperature (when compared to chemical reactions that in general, double in rate for every 10 C (50 F) increase of temperature) (see also section 4.11). In an open system, the corrosion rate drops at the boiling point due to the evaporation of water (disappearance of dissolved oxygen). On the other hand, in a closed system, the corrosion rate continues to increase with temperature (Figure 4.32).156

4.7.2 Effect of velocity157 In general, the surface layer thickness is large in stagnant systems and decreases progressively with increasing flow rate, until eventually all surface layers are removed. The effect of flow rate on corrosion in the presence of oxygen depends on the solution composition. For example, in the presence of chloride ions the corrosion rate increases with flow (Figure 4.33),158 but in the absence of chlorides, corrosion rate decreases with flow rate.

Table 4.9 Common Oxides of Iron Formula

Color

Oxidation State 2þ

Fe(OH)2 or FeO.nH2O FeO Fe(OH)3 or Fe2O3.nH2O

blue/green black red brown

Fe Fe2þ Fe3þ

Fe3O4 or Fe2O3.FeO.nH2O

black

Fe2þ/3þ

Name Ferrous oxide (hydrated) Ferrous oxide (unhydrated) Ferric oxide (hydrated) or Hematite (common rust) Ferrous-ferric oxide or Magnetite

230

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

FIGURE 4.32 Effect of Temperature on Corrosion of Iron in Water containing Dissolved Oxygen.156 Reproduced with permission from McGraw-Hill.

4.7.3 Effect of microstructure The influence of microstructure on the corrosion rate of steels in oxygen solution or in air is minimal in neutral solutions; only large amounts of chromium (more than 12%, e.g., stainless steel), silicon, or nickel decreases the corrosion rate. In acid solution, both composition and microstructure influence corrosion. Many alloying elements, such as carbon, nitrogen, sulfur, and phosphorous, increase both the general and pitting corrosion rates. Table 4.10 presents the general influence of alloying elements on the corrosion rate of iron.

FIGURE 4.33 Effect of Velocity on the Corrosion of Iron.158 Reproduced with permission from Wiley.

4.8 Sand and solids

231

Table 4.10 Effect of Alloying Elements on the Corrosion of Iron in Acid Media159 Element

Formula

Carbon

C

Phosphorous Sulphur

Concentration, %

Influence on Corrosion

Remarks

0.1 to 0.8

Slight increase in corrosion

Fe3C (cementite) acting as effective cathode increases galvanic corrosion

P S

0.02 0.015

Increases corrosion Increases corrosion

Copper

Cu

1

Moderately Increases corrosion rate

Chromium

Cr

12

Arsenic Manganese

As Mn

0.1 0.1

Nickel

Ni

5

Drastically decreases corrosion by forming effective oxide layer Increases corrosion Decreases corrosion; MnS, if present, may become location for pit initiation

Sulfur acts as anodic site, facilitating localized corrosion But in the presence of phosphorous and sulfur counteracts their accelerating effect Stainless steel

MnS inclusion has low electrical conductivity compared to FeS. It decreases the solubility of sulfur in iron

Decreases corrosion; may promote localized corrosion

4.7.4 Effect of pH Figure 4.34 presents the effect of pH on the corrosion rate of iron. Below pH 4, no surface layer is formed and the corrosion rate is independent of oxygen concentration; between pH 4 and 10, the corrosion rate increases with increase in oxygen concentration; and above pH 10 the corrosion rate decreases due to increased stability and compactness of surface layers. In many practical situations in the oil and gas industry, the pH is between 4 and 10, and under these conditions the corrosion rate increases with oxygen concentration.

4.8 Sand and solids161–163 Analyses of reservoir and rock mechanics of formations that have a relatively low strength (less than 2,000 psi (13.8 MPa)) and the availability of large amounts of oilsands indicate that the presence of sand in certain parts of the oil and gas industry is inevitable. Table 4.11 presents common types of solid and the most common cause of their formation.161 Both particle size distribution and concentration depend mostly on the formation rock and sand control technologies used. In most production facilities, sand control techniques are used to prevent the entry of sand into the downhole production tubulars. However, even with best sand control techniques,

232

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

FIGURE 4.34 Effect of pH on Corrosion of Iron in Aerated Soft water, Room Temperature.160 Reproduced with permission from the American Chemical Society.

Table 4.11 Common Types of Solids and Their Formation Mechanisms161 Solid Type

Typical Cause

Sand Oilsand Iron oxide, iron sulfide, iron carbonate and sulfur (generically referred to as ‘black powders’)

• Sand produced naturally from normal production wells • Sand naturally socked with oil • Direct chemical reaction of transported fluid components with pipe material • Ineffective removal of mill-scale from new pipe during pre-commissioning • Improper dewatering, drying and/or lay-up of pipe during pre-commissioning or remedial works. • Temperature and pressure change during the transportation of aqueous fluids; some inorganic scales (e.g., calcium carbonate, calcium sulfate, barium sulfate, and strontium sulfate) are deposited. • Comingling of incompatible aqueous fluids • Temperature and pressure change during the transportation of hydrocarbon fluids some organic molecules (e.g., asphaltene and wax) are deposited • Decrease of temperature (below dew point) and increased pressure during the transportation of wet (water containing) natural gas

Inorganic scales

Organic solids)

Hydrates)

)

These solids, though cause operational difficulties for flow-assurance team, they do not normally accelerate corrosion

4.8 Sand and solids

233

sand will enter into the tubulars. Depending on the composition of the material being transported and the efficiency of the sand control techniques used, different types of sand or solid contamination may occur. Two unique pipelines of the oilsand sector of the industry are hydrotransport pipelines and tailing pipelines. Oilsands are transported from the mining area either by conveyer belt or by hydrotransport. Hydrotransport has been used since 2005. In this process, oilsands and water are mixed together to make a slurry, which is transported in pipeline from the mine to a bitumen-extraction facility. While the mixture of oil sands and water flow through the pipeline, large lumps of oil sands are broken down and bitumen is separated from the oil sands in the form of tiny droplets. The benefits of hydrotransport include lower energy consumption, lower operating temperature, and flexibility of transportation. However, the degradation of pipelines, due to erosion and corrosion caused by sand and water, is a major challenge (see section 2.13). Fine tailings are by-products of the oilsand extraction process. They are a mixture of water, sand, silt, and fine clay particles, and they are transported to tailing ponds via tailing pipelines. Similar to hydrotransport pipelines, tailing pipelines also suffer from erosion and corrosion (see section 2.20). Solids may form due to corrosion of steel exposed to wet-gas. Typical solids include iron oxides, iron sulfides, iron carbonates, and sulfur, and these are collectively known as black powders. Gas transmission pipelines may contain several types of solids including sand, sludges, biomass (containing microbial species), inorganic scales (e.g., calcium carbonate, barium carbonate), organic scales (e.g., paraffins and asphaltenes) and corrosion products. Some dissolved solids carried by entrained liquids may also drop out and accumulate under favorable conditions. The presence of black powder affects gas transmission pipelines in several ways. These black powders may be hygroscopic or deliquescent, and they increase corrosion rates by retaining water, by establishing environments under them (i.e., underdeposit corrosion), and by sustaining microbial growth. Black powders may decrease the corrosion rate if they form an adherent surface layer on the pipe’s surface. When water from different sources is mixed, inorganic scales can be formed (see section 4.4.3). When the temperature of pipelines transporting extra-heavy crude oil is low, some long-chain (typically containing more than 20 carbon atoms, e.g., C20H42) paraffinic components (asphaltenes and wax) may deposit as hard solids. The majority of crude oils with API 20 or less (i.e., heavy and extra-heavy crude oils) contain significant amounts of paraffinic wax. As temperature reduces, wax will start to precipitate out. The wax may deposit in the form of an oil-gel containing some entrapped oil. As the temperature decreases the wax solidifies, eventually stopping the flow of crude oil. The temperature at which oil stops moving is known as the crude pour point temperature. To avoid wax formation, several measures are taken, including thermally insulating the pipe, using cleaning pigs, and adding chemicals. Asphaltenes are organic fractions of crude oils that are soluble in benzene and toluene, but not in alkanes (n-pentane and n-hexane). As the temperature decreases, asphaltene precipitates as a solid. Similar to wax formation, asphaltene formation may block the flow, but unlike wax they do not melt on heating. To remove asphaltene the pipeline is mechanically cleaned (using pigging and wireline cutting), or chemical solvents are used to dissolve it. Chemical inhibitors are also used to prevent the precipitation of asphaltenes in the first place. In wet-gas and multiphase pipelines, gas hydrates may form at low temperatures. Gas hydrate is formed when gas molecules are trapped in a cage of water molecules under certain pressure and temperature conditions. Generally, methane hydrate is formed in the presence of water, when the temperature is below 40 F (4 C) and pressure is above 170 psi (1,172 kPa). Decreasing temperatures and increasing pressures further favor hydrate formation. In addition to methane hydrate, ethane,

Very high

Dispersed sand flow Liquid/solid impingment erosion

Dispersed sand flow Solid/liquid impingment erosion

Dispersed sand flow Solid impingment erosion

High

Flow Rate

Liquid impingment erosion

Flow induced localized corrosion

Dispersed sand flow Corrosion influenced erosion

Scouring sand flow Corrosion influenced erosion

Scouring sand flow Corrosion influenced erosion

Medium

CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Flow assisted pitting corrosion

Scouring sand flow Erosion influenced corrosion

Sand dunes Erosion influenced corrosion

Sand dunes Erosion influenced corrosion

Low

234

General and pitting corrosion

Sand dunes Pitting corrosion

Sand deposits Pitting corrosion

Sand deposits Underdeposit corrosion

No

Small

Medium

Large

Sand Level FIGURE 4.35 Effect of Sand on Corrosion and Erosion.

propane, CO2 and H2S hydrates may also form. These hydrates form as solids or semi-solids, and they slow or even completely block the gas flow. Several measures are taken to avoid hydrate formation in gas pipelines, including removal of water, keeping the temperature above hydrate formation temperature, maintaining the pressure below hydrate formation pressure, and by injecting chemicals (hydrate inhibitors). The formation of these solids, i.e., asphaltene deposits, wax deposits, and hydrate normally decrease the corrosion rate. But they create operational difficulties, e.g., pressure drop and, in extreme situation, stoppage of flow; therefore their formation is avoided. The presence of solids may result in corrosion under sand beds (underdeposit corrosion), erosioninfluenced corrosion (EIC), corrosion-influenced erosion (CIE), and erosion. Figure 4.35 presents various types of corrosion and the conditions in which they will probably occur. However the boundary conditions between these types of corrosion are not well established.

4.9 Microorganisms165–168 When some microbiological species are present, they may influence corrosion. The corrosion influenced by microbiological activities is known as microbiologically influenced corrosion (MIC).164 Microorganisms do not produce unique types of corrosion. For this reason, it is accepted by international community that the term is microbiologically ‘influenced’ corrosion, rather than microbiologically ‘induced’ corrosion. The presence and activities of microorganisms may cause pitting, crevice corrosion, selective dealloying, and differential aeration cells (see section 5.14).

4.9 Microorganisms

235

There are several types of microorganisms present in air, water, and attached to solid materials. The microorganisms floating freely in a liquid are commonly referred to as ‘planktonic’ organisms. Microorganisms that are attached to a surface are commonly known as ‘sessile’ organisms. The microorganisms may be classified as bacteria (0.2 to 2 mm), fungi (2 to 20 mm), and algae (2 to 20 mm). All these microorganisms can be present in diversified environments of various pH, oxygen content, temperature, and food sources. Table 4.12 presents some of their characteristics. When conditions are conducive, they multiply rapidly, with growth as high as 1 million/ml within 24 hours. Of the various microorganisms, sulphate-reducing bacteria (SRB), acid-producing bacteria (APB), iron-oxidizing bacteria (IOB) and iron-reducing bacteria (IRB) are known to cause MIC. SRB constitute a diverse group of anaerobic bacteria which have several morphologies and nutritional requirements. They reduce sulfate to hydrogen sulfide. Common SRBs include Desulfovibrio, Desulfobacter and Desulfotomaculum. Since the discovery of SRBs by the Dutch microbiologist Wilhelm Bijerninck in 1905, they have been considered as the dominant bacteria associated with MIC.169 Despite the recognition that the most severe MIC occurs in the presence of consortia of bacteria, SRB are most often considered as the primary cause, because they are ubiquitous; in sulfate-containing environments they produce hydrogen sulfide; and they convert sweet production to sour production (containing hydrogen sulfide).

Table 4.12 Characteristics of Microorganisms Properties

Definition

Bacteria

Fungi

Algae

Nucleus

Procaryote (i.e., it does not have any nucleus) eucaryote (i.e., they have nucleus)

Procaryote

Eucaryote

Eucaryote

0.2 to 2 No 3 to 9

2 to 20 No 3 to 5

2 to 20 Yes 7 to 8

Yes

Yes

Yes

Yes Yes Yes Yes

No e e Yes

No e e Yes

Yes

e

e

Yes

e

e

e Yes

e e

Yes e

Yes

e

e

Typical size, mm Chlorophyll Typical pH range of activity Aerobic Anaerobic Anaerobic-Obligate Anaerobic-Faculative Psychrophiles Mesophiles Thermophiles Phototrophs Lithotrophs Heterotrophs

Requires light to grow

Presence of oxygen required for growth Oxygen is not required for growth Can not tolerate oxygen Can tolerate oxygen Active in the temperature range 20 to 20 C Active in the temperature range 20 to 45 C Active in the temperature range above 45 C Light is the source of energy Inorganic matters are the source of energy Organic matters are the source of energy

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Section 5.14 discusses the mechanism of MIC, section 6.7.6 presents comprehensive model for MIC, and section 8.2.4 presents methods for monitoring MIC.

4.10 Pressure As discussed in section 4.2, pressure is the force that moves the hydrocarbons. Therefore an important consideration in designing and operating the piping and pipeline is to estimate the amount of pressure required to transport the hydrocarbons. Many oil and gas facilities are operated at elevated pressure. The effect of pressure on corrosion depends on the partial pressures of acid gases (H2S and CO2), other chemical species (bicarbonate, acetate, and calcite), the pH and temperature. Higher pressure (or partial pressures of acid gases H2S and CO2), may increase corrosion if it increases the dissolution of corrosive species into the solution, or increases the dissolution of the surface layer from the metal surface. On the other hand, higher pressure may decrease corrosion if it facilitates the formation of a compact surface layer.

4.11 Temperature In general, the relationship between temperature and chemical reactions is provided by the Arrhenius equation. According to this equation, the rate of a chemical reaction increases with an increase in temperature. The Arrhenius equation also applies to corrosion reactions taking place by electrochemical mechanisms (see section 5.2). Depending on the material, environment, and temperature, the corrosion rate doubles for every 10 or 30 C increase in temperature. However, the Arrhenius equation applies only in the range of temperature in which the corrosion mechanism remains the same. Above and below this temperature range, the relationship between corrosion rate and temperature may be different. Sections 4.5.1, 4.6.1, and 4.7.1 respectively present the effect of temperature in CO2, H2S, and O2 systems. In some cases, an increase in temperature decreases corrosion. The dew point is the temperature below which water condenses. When the temperature is above the dew point water does not condense. Because water is required for electrochemical corrosion to take place, above the dew point the corrosion rate decreases. Most of the gas wells and gas pipelines are operated above the dew point to avoid condensation of water, and hence corrosion. On the other hand, in some cases, a decrease in temperature decreases corrosion; this normally happens when solids such as asphaltene, wax, and hydrates form (see section 4.8). However, the formation of these solids causes other operational difficulties and hence this is avoided. At high temperatures, typically above 840 F (w450 C), another form of corrosion known as ‘high temperature corrosion’ takes place (see section 5.15).

4.12 pH The pH of the waters in the oil and gas industry depends on the partial pressures of the acid gases (H2S and CO2), concentrations of buffering species (bicarbonate and acetate ions), the concentration of scale-forming species (calcium carbonate), temperature, and organic acids (acetic acid). Table 4.13

4.13 Organic acids

237

Table 4.13 Influence of Parameters on pH (Experimental Data)170 Parameter

Parameter Range

pH Range

CO2 H2S CO2 and H2S

10 to 80 psi 10 to 80 psi 80 psi each

4.5 to 5.5 4.8 to 5.5 4.0 to 5.0

Temperature NaHCO3

30 and 50 C 4,000 ppm

4.4 to 4.8 6.0

CH3COONa

4,000 ppm

6.0

CH3COOH A mixture of NaHCO3 and CH3COONa

4,000 ppm 4,000 ppm each

4.0 6.0

Effect of Increasing Value of the Parameter on pH Decreases Decreases Same as for individual acid gases Slightly increases Increases and stabilizes (buffering) Increases and stabilizes (buffering) Decreases Stabilizes (buffering)

summarizes the influence of some parameters on the pH. Sections 4.5.4, 4.6.4, and 4.7.4 respectively discuss the influence of pH in sweet, sour, and oxygen containing environments. Determination of pH at the point where corrosion occurs provides valuable information; however such measurement is not routinely carried out. In many instances, the pH of the solution is measured under atmospheric pressure, immediately upon withdrawal from the system. This pH may not necessarily be the pH of the water within the system, because of the loss of acid gases, such as H2S and CO2, through pressure reduction and exposure of the fluid to atmosphere. Alternatively the in situ pH is estimated.171–175 The use of handheld devices facilitates estimation of in situ pH quickly. Equation 4.87 provides a simple method to quickly estimate pH in sweet environment: 1 pH ¼ 4:08 þ Log pffiffiffiffiffiffiffiffiffiffiffi WCO2

(Eqn. 4.87)

where WCO2 is the weight of CO2 in grams dissolved per liter of water.

4.13 Organic acids Organic acids include a broad range of compounds containing a carboxylic group, i.e., –COOH. Depending on the hydrocarbon molecule to which this carboxylic group is attached the organic acids can be broadly classified into: • • •

aliphatic acids (Ali.COOH) where the hydrocarbon molecule may be a straight or branched hydrocarbon, e.g., CH3– (acetic acid), C2H5– (propionic acid), etc; aromatic acids (Ar.COOH) where the hydrocarbon molecule may be benzene or substituted benzene ring; and naphthenic acids (Nap.COOH) where the hydrocarbon molecule may be a saturated cyclic ring, e.g., cyclopentane, cyclohexane, etc. The term ‘naphthenic acid’ as used in the oil and gas industry actually refers to many organic acids present in crude oil.

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

Section 4.3.1c briefly discusses the influence on organic acids present in crude oils. The organic acids influence corrosion as: Fe þ 2RCOOH/FeðCOORÞ2 þ H2

(Eqn. 4.88)

where R’ is an aliphatic, aromatic, or naphthenic group. Depending on the type of organic acid, the reaction product, Fe(COOR’)2, is soluble in crude oil or in the aqueous phase. For this reason, corrosion by organic acids does not leave any product layers on the metal surface. Corrosion by aliphatic acids normally occurs at temperatures as low as 140 F (60 C) due to their low volatility. On the other hand, corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C); the corrosion rate increases with increase of temperature up to between 500 and 700 F (260 and 370 C), and drops above 700–750 F (370–400 C) due to the decomposition of the acids. Aromatic acids are not normally corrosive.

4.13.1 Aliphatic acids The presence of acetic acid in oilfield brines can significantly increase the rate of corrosion of carbon steel, even if the bulk pH is high due to the presence of bicarbonate ions. Although the presence of acetic acid affects the corrosion rate, it does not necessarily affect the corrosion mechanism (see section 5.24). The species increases the corrosion rate by locally decreasing the pH and dissolving the iron carbonate surface layer. As a result, the thickness of the iron carbonate surface layer is locally reduced. Acetic acid also interferes with the chemical analysis of bicarbonate ions resulting in overestimation of the concentration of bicarbonate ions. For these reasons, the effect of acetic acid is commonly known as a ‘double whammy effect’; i.e., acetate ions lead to overestimation of the concentration of bicarbonate ions (thus underestimation of sweet corrosion rate) and itself increases corrosion rate.176

4.13.2 Naphthenic acids Corrosion by naphthenic acids normally occurs at temperatures above 430 F (w220 C) during refinery processing. For this reason, the concentration of naphthenic acids in crude oil is routinely determined before processing. The crude oil is titrated with potassium hydroxide (KOH) and the resultant value is known as ‘neutralizing number’ or ‘acid number’ or total acid number (TAN). The TAN is expressed as milligrams of KOH required to neutralize the acidity of one gram oil. Standards providing procedures to determine the naphthenic acid content of crude oils include: • •

ASTM D664, ‘Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration’ ASTM D974, ‘Standard Test Method for Acid and Base Number by Color-Indicator Titration’

As a rule of thumb, crude oils with TAN values greater than 0.5 and refined fractions with TAN values greater than 1.5 are considered corrosive.177 However, the corrosivity of different oils with same acid number may not be the same. Corrosivity also depends on other parameters including temperature,

4.14 Mercury

239

type of acid and the presence of other chemicals, e.g., sulfide. Depending on the presence of a sulfide surface layer, naphthenic acid corrosion may be classified into three types: • • •

Pure naphthenic acid corrosion with no or little effect of sulfur compounds. Sulfidation corrosion, i.e., accelerated corrosion due to the destruction of a sulfide surface layer by naphthenic acid. Inhibited naphthenic acid corrosion, i.e., inhibition of naphthenic acid corrosion due to the presence of a sulfide surface layer.

This property is utilized during refining crudes with higher TAN and high sulfur contents. The highTAN crudes and high sulfur crudes are often blended together to control corrosion. The forms of sulfur involved in this process and the threshold amounts have not been established.

4.14 Mercury Mercury (Hg) in natural gas streams was first recognized in gas fields in Asia. Since then production of Hg in natural gas has been observed in many fields. Though handling of Hg is a health concern, from the perspective of corrosion, liquid metal embrittlement (LME) is of concern. Mercury forms amalgams (liquid solutions) with many metals including aluminum, tin, gold, silver, and zinc. In general, aluminum oxide protects Al. When Hg contacts an Al surface, it breaks the aluminum oxide, wets the surface and forms an amalgam. As a consequence of the amalgam, the mechanical strength of the metal is lost. The Al amalgam also reacts with moisture, producing aluminum hydroxide and regenerating Hg. The aluminum hydroxide grows as a characteristic tree-like structure. As a consequence of this self propagation, the corrosion rate of Al can be as high as 40 inch/y (w1 meter/y), with corrosion products appearing on the surface dramatically and rapidly. Table 4.14 presents the interaction of Hg with other metals.178

Table 4.14 Effect of Mercury on Metals178 Metal

Effect of Hg

Remarks

Carbon and low alloy steel

No effect

Type 304 SS

Sensitization

Carbon steel piping and vessels are used in the presence of Hg without loss of integrity The fracture surface of the sensitized material exhibits intergranular regions

Type 316 SS Type 316L SS Type 321 SS Alloy 800 13% Cr SS Ti Grade 2 alloy Alloy 600 Monel 400

No effect

Sensitization LME

Exhibits intergranular cracking

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CHAPTER 4 The Main Environmental Factors Influencing Corrosion

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92. Nesic S, Lunde L. Carbon Dioxide Corrosion of Carbon Steel in Two-Phase Flow. Corrosion 1994;50(9): 717–27. 93. Heuer JK, Stubbins JF. Microstructure Analysis of Coupons Exposed to Carbon Dioxide Corrosion in Multiphase Flow. Corrosion July 1998;54(7):566–75. 94. Schmitt G, Mueller M, Papenfuss M, Strobel-Effertz E. Understanding Localized CO2 Corrosion of Carbon Steel from Physical Properties of Iron Carbonate Scales. Corrosion 99, Paper #38. Houston, TX: NACE; 1999. 95. Nyborg R, Dugsted A. MESA Corrosion Attack in Carbon Steel and 0.5% Chromium Steel. Corrosion 98, Paper #29. Houston, TX: NACE; 1998. 96. Kermani MB, Smith LM. CO2 Corrosion Control in Oil and Gas Production: Design Considerations. European Federation of Corrosion Publications; 1997. Number 23, EFC. 97. Al-Hassan S, Mishra B, Olson DL, Salama MM. Effect of Microstructure on Corrosion of Steels in Aqueous Solutions Containing Carbon Dioxide. Corrosion June 1998;54(6):480–91. 98. Dugstad A, Hemmer H, Seiersten M. Effect of Steel microstructure on Corrosion Rate and Protective Iron Carbonate Film Formation. Corrosion April 2001;57(4):369–78. 99. Crolet JL, Thevenot N, Nesic S. Role of Conductive Corrosion Products in the Protectiveness of Corrosion Layers. Corrosion March 1998;54(3):194–203. 100. Palacios CA, Shadley JR. Characteristics of Corrosion Scales on Steels in a CO2-Saturated NaCl Brine. Corrosion February 1991;47(2):122–7. 101. Mishra B, Olson DL, Al-Hassan S, Salama MM. Physical Characteristics of Iron Carbonate Scale Formation in Linepipe Steels. Corrosion 92, Paper #13. Houston, TX: NACE; 1992. 102. Ikeda A, Ueda M. Effect of Microstructure and Cr Content in Steel on CO2 Corrosion. Corrosion 96, paper #13. Houston, TX: NACE; 1996. 103. Schmitt G, Rothmann B. Corrosion of Unalloyed and Low Alloyed Steels in Carbonic Acid Solutions. Werkstoffe und Korrosion 1978;29:237. 104. Schmitt G, Gudde T, Strobel-Effertz E. Fracture Mechanical Properties of CO2 Corrosion Product Scales and Their Relation to Localized Corrosion. Corrosion 96, Paper #9. Houston, TX: NACE; 1996. 105. Mishra B, Olson DL, Al-Hassan S, Salama MM. Physical Characteristics of Iron Carbonate Scale Formation in Linepipe Steels. Corrosion 92, Paper #13. Houston, TX: NACE; 1992. 106. Simpson LJ, Melendres CA. Surface-Enhanced Raman Spectroelectrochemical Studies of Corrosion Films on Iron in Aqueous Carbonate Solution. J. Electrochem. Soc. July 1996;143(7):2146–52. 107. Legrand L, Abdelmoula M, Gehin A, Chausse A, Genin JMR. Electrochemical formation of a new Fe(II)Fe(III) hydroxy-carbonate green rust: characterisation and morphology. Electrochimica Acta 2001;46: 1815–22. 108. Adamy ST, Cala FR. Inhibition of Pitting in Ferrous Materials by Carbonate as a Function of Temperature and Alkalinity. Corrosion September 1999;55(9):825–39. 109. Mishra B, Olson DL, Al-Hassan S, Salama MM. Physical Characteristics of Iron Carbonate Scale Formation in Linepipe Steels. Corrosion 92, Paper #13. Houston, TX: NACE; 1992. 110. Anderko A, Young RD. Simulation of CO2/H2S Corrosion using Thermodynamic and Electrochemical Models. Corrosion 99, Paper #31. Houston, TX: NACE; 1999. 111. Johnson DL, Omura H. Characterization of Carbon Steel Corrosion in Dilute Ammonium Nitrate Solutions and Irrigation Ground Waters. Corrosion, N.A.C.E April 1981;37(4):209–13. 112. Schmitt G. Effect of Elemental Sulfur on Corrosion in Sour Gas Systems. Corrosion April 1991;47(4): 285–308. 113. Caldwell JA. Sour Oil Well Corrosion TP-1D - Sour Oil Well Corrosion. Corrosion, NACE August 1952: 292–4.

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CHAPTER

5

Mechanisms

5.1 Introduction Corrosion may occur in various segments of the oil and gas industry by different mechanisms. Several terminologies, definitions, and acronyms are used by corrosion professionals to explain these mechanisms. Familiarity of corrosion related terms will help to understand different types of corrosion and their mechanisms more easily. Standards providing guidelines on various corrosion related terms include: ASTM-NACE G193-12D, ‘Standard Terminology and Acronyms Relating to Corrosion’ ASTM G40, ‘Terminology Relating to Wear and Erosion’ ASTM G16, ‘Terminology for Paint, Related Coatings, Materials, and Applications’ Table 5.1 presents corrosion types which predominate in various segments of oil and gas industry. This chapter describes types of corrosion and their mechanisms, as well as general methods of controlling them.

5.2 Electrochemical nature of corrosion Corrosion of metals and alloys in aqueous solution, or in any other ionically conducting medium, takes place by electrochemical mechanisms.1–3 An electrochemical corrosion reaction requires four elements (Figure 5.1): an anode, a cathode, a metallic conductor, and an electrolytic conductor (ACME). At the anode, a metal ion leaves the metal surface and goes into solution. In this process it leaves electrons behind on the metal surface. Therefore the metal is oxidized, i.e., it loses electrons at the anode. This process is corrosion. A typical anodic (corrosion) reaction can be written as (Eqn. 5.1): M/Mnþ þ ne

(Eqn. 5.1)

The solution (scientifically known as an ionically conducting electrolyte) carries the metal ions from the anode to the cathode. Electrolytes are mostly liquids, but they may be solids. Electrolytes containing a higher concentration of ions have higher electrical conductivities. In general, an electrolyte contains two types of ions: anions and cations. Anions are negatively charged, and they move towards the anode, where they may get oxidized (i.e., they lose electrons). Cations are positively charged and they move towards cathode, where they may get reduced (i.e., they gain electrons). For example, Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00005-4 Copyright Ó 2014 Elsevier Inc. All rights reserved.

249

250

Table 5.1 Predominant Corrosion Types in Various Segments of the Oil and Gas Industry

Component

Production

Drill Pipe

• Carbon steel

Casing Pipe

• Carbon steel

Downhole Tubular

• Carbon steel

• SSC • Chloride SCC

Sucker Rods

• Carbon steel

Acidizing Pipe

• Carbon steel

• Corrosion fatigue • SSC • General corrosion

Water Generator

• Carbon steel

• Localized pitting corrosion

Gas Generator

• Carbon steel

Open Mining In situ Production

• Carbon steel • Carbon steel

• Localized pitting corrosion • Chloride SCC • Erosion-corrosion • Erosion-corrosion

Wellhead

• Carbon steel

Production Pipeline

• Carbon steel

Heavy Crude Oil Pipelines Hydrotransportation Pipeline

• Carbon steel • Carbon steel

Predominant Corrosion Type) • SSC • Corrosion fatigue • SSC

• Localized pitting corrosion • SSC • Localized pitting corrosion • HIC • Localized pitting corrosion • Localized pitting corrosion • Erosion-corrosion

Main Environmental Factors Influencing Corrosion (see Chapter 4)

Internal or External or Both

• H 2S

• External

• • • • • •

H 2S Temperature H 2S Chloride Temperature H 2S Temperature Acids (organic and inorganic) O2 Microbes H 2S CO2 O2 Chloride

• • • • • • •

Sand Temperature Sand CO2 H 2S O2 O2

• • • • • • • •

• Internal • Internal

• External • Internal • Internal

• Internal

• Internal • Internal • Internal

• External

• H 2S • CO2

• Internal

• Crude oil

• Internal

• Sand

• Internal

CHAPTER 5 Mechanisms

Sector

Predominant Material of Construction (see Chapter 3)

Transmissionpipelines

Gas Dehydration Facility

• Carbon steel

• Localized pitting corrosion

Oil Separator

• Carbon steel

Recovery Center (Extraction) Upgrader Lease Tank

• Carbon steel

• Localized pitting corrosion • Erosion-corrosion

Waste Water Pipeline

• Carbon steel

Tailing Pipeline Transmission Pipeline (Midstream Pipeline)

• Carbon steel • Carbon steel

Carbon steel CRAs Carbon steel CRAs

• • • •

Pipeline Accessories

• Carbon steel • CRAs

• •

Ship

• Carbon steel

•

Pump Station

TransportationTankers

• HIC • Localized pitting corrosion • Localized pitting corrosion • Erosion-corrosion • SCC • Localized pitting corrosion • Localized pitting corrosion

• • • •

•

• Carbon steel • Carbon steel • Carbon steel

• • •

• Sand • Temperature

• Internal

• H2S • CO2

• Internal

• O2

• Internal

Sand CO2 O2 Microbes Crude oil (oil transmission) • Solids e black powder (gas transmission) • Microbes • Flow

• Internal • External

• Flow

• Internal

• Flow

• Internal

• • • • •

• Internal

• Internal

• Internal

• Solids • Internal (sediments) • Microbes • Seawater • External • Microbes General corrosion may occur; but corrosion is not a major issue General corrosion may occur; but corrosion is not a major issue General corrosion may occur; but corrosion is not a major issue Continued

251

LNG Tank Railcar Trucks

Erosion-corrosion Corrosion fatigue Erosion-corrosion Localized pitting corrosion Erosion-corrosion Localized pitting corrosion Localized pitting corrosion MIC

• Internal

5.2 Electrochemical nature of corrosion

Compressor Station

• See refinery • Carbon steel

CO2 H2S O2 Crude oil

• • • •

252

Table 5.1 Predominant Corrosion Types in Various Segments of the Oil and Gas Industry Continued

Component

Storage

Gas Storage

• Carbon steel

Oil Storage

• Carbon steel

Refining

Desalter

• Carbon steel

Distillation units (atmospheric and vacuum)

• Carbon steel

Hydrotreating units

• Carbon steel • Stainless steel

Predominant Corrosion Type) • Localized pitting corrosion • Localized pitting corrosion • MIC

• Localized pitting corrosion • Localized pitting corrosion

SSC SCC Hydrogen flaking Pitting corrosion Corrosion under insulation • Metal dusting • Carburization • Pitting corrosion

• • • • •

Catalytic reforming

• Carbon steel • Stainless steel

Catalytic cracking unit

• Carbon steel • Stainless steel

• Intergranular SCC • Erosion

Thermal cracking unit

• Carbon steel • Stainless steel

• Intergranular SCC • Graphitization • Erosion

Main Environmental Factors Influencing Corrosion (see Chapter 4)

Internal or External or Both

• Chloride

• Internal

• Solids (sediments) • Microbes • Oil • Microbes • Ground water • Salt

• Internal

• • • • • • • • • • • • • • • • • • •

Hydrochloric acid Naphthenic acid Sulfur Temperature H 2S Temperature Polythionic acid Ammonia Moisture Chlorides Temperature Chloride Ammonia Caustic Temperature Ammonia Carbonate Solid (Catalyst) Temperature

• External • Internal • Internal

• Internal

• External • Internal

• Internal

• Internal

CHAPTER 5 Mechanisms

Sector

Predominant Material of Construction (see Chapter 3)

• Carbon steel • Stainless steel

Steam cracking unit

• Carbon steel

Visbreaker unit

• Carbon steel

Merox unit

• Carbon steel

Coker

• Carbon steel • Stainless steel

Gas plant

• Carbon steel

Alkylation

• Carbon steel

Isomerization

• Carbon steel

Gas treating plant

• Carbon steel

Sour water stripper

• Carbon steel • Titanium

Claus sulfur plant

• Stainless steel • Carbon steel

• High temperature corrosion • Localized pitting corrosion • High temperature corrosion • High temperature corrosion • Localized pitting corrosion • High temperature corrosion (oxidation/ sulphidation) • Localized pitting corrosion • Localized pitting corrosion • Hydrogen grooving • Hydrogen embrittlement • SCC • Flow accelerated corrosion • Localized pitting corrosion • Localized pitting corrosion • Localized pitting corrosion • Erosion-corrosion • Pitting corrosion

• H 2S • Organic sulfides • Temperature

• Internal

• Temperature • Steam • Temperature

• Internal • Internal

• Sulfur compounds • Temperature • H 2S

• Internal

• Salt water

• Internal

• Acids (sulfuric acid and hydrofluoric acid) • SO2

• Internal

Chlorides High temperature H 2S CO2 Amines H 2S Flow Chloride H 2S CO2 SO2 Sulfur

• Internal

• • • • • • • • • • • •

• Internal

• Internal

• Internal

• Internal

253

Continued

5.2 Electrochemical nature of corrosion

Hydro-cracking unit

254

Table 5.1 Predominant Corrosion Types in Various Segments of the Oil and Gas Industry Continued

Component Heat exchanger

Cooling towers

Solvent extraction unit Steam reforming

MTBE Polymerization unit Other units (Hydrogen plant)

• • • • •

Carbon steel Stainless steel Nickel alloys Titanium alloys Carbon steel

• Carbon steel • Stainless steel • Carbon steel

• • • • •

Carbon steel Carbon steel Stainless steel Carbon steel Stainless steel

Predominant Corrosion Type)

• Carbon steel • Stainless steel

Other units (Methanol plant)

• Carbon steel • Stainless steel

Internal or External or Both

• Pitting corrosion • Erosion-corrosion

• Chloride • Oxygen • H2S

• Internal

• Localized pitting corrosion • Erosion-corrosion • Chloride SCC

• Chloride • Oxygen

• Internal

• Chloride

• Internal

• • • • • • •

• Other units (ammonia plant)

Main Environmental Factors Influencing Corrosion (see Chapter 4)

•

• •

•

• Erosion-corrosion • Caustic SCC • Metal dusting Corrosion fatigue Corrosion is not a major Localized pitting • corrosion • High temperature • corrosion (green rot) • Localized pitting corrosion • High temperature • corrosion • (nitriding) HIC • High temperature • corrosion (metal dusting) • SCC

Flow Steam (water) Carbonates and bicarbonates issue Phosphoric acid

• Internal

• Internal

Temperature H 2S CO2

• Internal

High temperature Hydrogen Ammonia

• Internal

High temperature CO2 Hydrogen

• Internal

CHAPTER 5 Mechanisms

Sector

Predominant Material of Construction (see Chapter 3)

Distribution

Special

• Carbon steel • Carbon steel • Carbon steel

Corrosion is not an issue under normal operating conditions Corrosion is not an issue under normal operating conditions Corrosion is not an issue under normal operating conditions

• Carbon steel • Carbon steel

CO2 pipeline

• Carbon steel

Biofuel Infrastructure

• Carbon steel

High Vapor Pressure pipeline Hydrogen pipeline

• Corrosion steel

Corrosion is not an issue under normal operating conditions Corrosion is not an issue under normal operating Internal conditions • External • CO2 • SCC • O2 • Localized pitting • Microbes corrosion • CO2 • Localized pitting • Internal corrosion • Impurities • Internal • Oxygen • Stress-corrosion • Impurities cracking • Microbes • Localized pitting corrosion • Corrosion characteristics similar to production pipelines

• Carbon steel

• Hydrogen embrittlement

• Hydrogen • Pressure

• Internal

This does not mean that other types of corrosion do not take place, but these forms of corrosion have caused major failures or incidents in these sectors

5.2 Electrochemical nature of corrosion

)

Product pipeline Terminal City gates and local distribution CNG tank Diluent pipeline

255

256

CHAPTER 5 Mechanisms

Electrolyte path

Anode

Cathode

Metallic path metal FIGURE 5.1 Basic Four Elements (ACME) for Corrosion to Take Place.

deionized water contains smaller amounts of ions; hence it is a poor electrolyte. On the other hand, sea water contains several dissolved ions; hence it is a good electrolyte and sustains corrosion. Metallic ions may in some cases leave the solution and deposit on the cathode, if they are reduced at the cathode. In this process it gains electron from the metal surface. The cathodic reaction can be written as (Eqn. 5.2): Mnþ þ ne /M

(Eqn. 5.2)

The electrolyte may contain several other species that could undergo reduction instead of the metal ion. Commonly occurring other species include hydrogen ions and dissolved oxygen. Therefore, depending on the pH, hydrogen ion reduction (Eqn. 5.3) or oxygen reduction (Eqn. 5.4) may take place: 2Hþ þ 2e /H2

(Eqn. 5.3)

O2 þ 2H2 O þ 4e /4OH

(Eqn. 5.4)

The metal conductor carries the electrons left by the metal ions at the anode site to the cathodic site. Corrosion takes place only when all four (ACME) processes occur simultaneously. The absence of any one of these prevents corrosion. In the presence of all four elements a balance is established, so that the rate of anodic reaction (corrosion) is equal to that of cathodic reaction (reduction). It should be noted that anodes, cathodes, and metallic conductors exist in a metal. Therefore when a metal comes in contact with an electrolyte corrosion can potentially take place. Two more things should be known before corrosion control strategies can be developed: does corrosion take place under given conditions, and if it does, at what rate does it take place? When one throws a ball, it will initially bounce, then roll, and ultimately settle down at a lowest point. It does so because it seeks a state of lowest energy; i.e., the lower the energy the more stable the state is. Scientifically this tendency is defined by Gibbs free energy change (DG). If the energy change is negative as a result of a process or reaction, then the result of the process or reaction is in lower energy state than the starting material. Hence the product is more stable and so the process is energetically feasible; i.e., it takes place spontaneously. If the free energy change is positive, then the reaction does not take place spontaneously. A metal occurs in nature as an ore such as metal oxide, metal carbonate, or metal sulfide because it is the lowest energy state. From the ore, the metal is produced by several processes including smelting,

5.2 Electrochemical nature of corrosion

257

Table 5.2 Energy Required to Convert Ore to Metal Energy Level

Metal

High

Magnesium Aluminum Zinc Chromium Iron Nickel Tin Copper Silver Platinum

Low

Gold

refining, casting, rolling, and shaping. All these processes add energy to the metal to keep it in a higher energy state. The extent of energy required varies from metal to metal. Table 5.2 compares relative energy requirements for converting ores into metals. This means that metals inherently have a tendency to return back to their original lower energy state, i.e., they have a tendency to corrode. From Table 5.2 it is apparent that magnesium has a greater tendency to corrode because of the large amounts of energy used to extract it from the ore; i.e., it is in a relatively high energy state. On the other hand, gold has a smaller tendency to corrode because of the smaller amounts of energy used to extract it from its ore; i.e., it is in a relatively low energy state. The DG is related to the potential as: DG ¼ )

nFE)

(Eqn. 5.5)

where E is the potential according to the Nernst-Latimer convention, n is the number of electrons transferred and F is the Faraday constant. There has been considerable confusion regarding the sign for denoting the potential because of the use of two conventions for this: the Nernst-Latimer convention and the Gibbs-Stockholm convention.4 In the Nernst-Latimer convention, the sign of the potential depends on the way the reaction is written. For example, in the reactions taking place in Eqns. 5.1 and 5.2, the potential would have the same value but opposite sign, i.e., according to the Nernst-Latimer convention, the sign of the potential depends upon the way that the reaction is written. In the Gibbs-Stockholm convention, the positive direction of electrode potential implies an increasingly oxidizing condition at the electrode. The positive direction is also commonly known as the noble direction. This is so because the corrosion potentials of most noble (lower tendency to corrode) metals are more positive than active metals (higher tendency to corrode). On the other hand, the negative direction implies an increasingly reducing condition at the electrode. This convention was

258

CHAPTER 5 Mechanisms

adopted unanimously by the 1953 International Union of Pure and Applied Chemistry (IUPAC). According to this convention, the Gibbs free energy is related to the potential as: DG ¼ nFEo

(Eqn. 5.6)

where Eo is the standard redox potential. The standard redox potentials of ions are referred to the hydrogen potential, i.e., the potential for reducing hydrogen ions from a concentration (activity) of 1 g-mole/l at 25 C to gas at 1 atmospheric pressure is zero. The standard potential (Eo) is the potential of a metal in contact with its own ions at a concentration equal to unit activity at 25 C. The arrangement of metal-based standard potentials is known as the Standard Potential, Standard Oxidation-Reduction (redox) Potential, Standard Equilibrium Reduction Potential, Electromotive Force (EMF), or Standard Reversible Potential series. Table 5.3 presents the standard potential series of metals.5 The standard potential helps us to understand the corrosion tendency of metals. For example, Figure 5.2 presents a situation in which copper and zinc pieces each immersed separately in their own ions of unit activity are electrically connected together. (Electrically connecting metal pieces is commonly called short-circuiting).6 From Table 5.3, the standard potential of copper is þ0.337V and that of zinc is 0.763V. From these values and signs it is obvious that zinc is active compared to copper. Therefore when copper and zinc are short-circuited, an ACME is established (Figure 5.1) with zinc undergoing oxidation (corrosion) and copper ions undergoing reduction. The potential measured will be 1.1 V; by convention the potential of more active material is subtracted from that of the more noble material, i.e., 0.337 V ( 0.763 V) ¼ 1.1 V. In this example, it is important that the metallic ions must not be allowed to mix. If they did copper would deposit on zinc and consequently, the potentials of copper and zinc electrodes would be identical. In the previous example, the metals were immersed into electrolytes of their own ions of unit activity. To determine the potential of a metal in a solution in which its ions are not at unit activity, or in solution of ions other than its own, Nernst derived an equation: E ¼ Eo þ 2:3

RT ½OXŠ log nF ½REDŠ

(Eqn. 5.7)

where E is the potential, Eo is the standard redox potential, R is the gas constant, T is the absolute temperature, a [OX] is the activity (concentration) of oxidized species, and [RED] is the activity of the reduced species. From Eqn. 5.7, it is obvious that the potential of metal varies depending on the ionic species in the solution with which it is in contact; it becomes more positive as the concentration of oxidized species increases. For each tenfold increase in concentration of oxidized species, the potential increases by 59 mV at 25 C for a single electron reaction, i.e., when n is equal to unity. In practice, both anode and cathode can exist on the same metal sample, which can also act as the metallic conductor (i.e., the ACM elements of ACME can exist on the metal sample). When the metal is immersed in an electrolyte, all four elements are established, and a potential is developed. This potential is called the corrosion potential (Ecorr) and is different from the standard redox potential (Eo). The extent of difference in potential depends on the concentration of the chemical species in solution (Eqn. 5.7). It is also obvious that E and Ecorr are the same. Measurement of the corrosion potential is the fundamental primary step for understanding the corrosion tendency of metals or alloys in an electrolyte. Practically, one cannot measure the potential

5.2 Electrochemical nature of corrosion

259

Table 5.3 Standard Electrode Potential5 Standard Potential Eo (in volts) at 25 C

Electrode Reaction Au3þ Pt2þ Pd2þ Hg2þ Agþ Hg2þ 2 Cuþ Cu2þ 2Hþ Pb2þ Sn2þ Mo3þ Ni2þ Co2þ T1þ In3þ Cd2þ Fe2þ Ga3þ Cr3þ Cr2þ Zn2þ Nb3þ Mn2þ Zr4þ Ti2þ Al3þ Hf4þ U3þ Be2þ Mg2þ Naþ Ca2þ Kþ Liþ

þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ þ

3e2e 2e 2e e 2e e 2e 2e 2e 2e 3e 2e 2e e 3e 2e 2e 3e 3e 2e 2e 3e 2e 4e 2e 3e 4e 3e 2e 2e e 2e e e

¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼

Au Pt Pd Hg Ag 2Hg Cu Cu H2 Pb Sn Mo Ni Co T1 In Cd Fe Ga Cr Cr Zn Nb Mn Zr Ti Al Hf U Be Mg Na Ca K Li

1.50 ca. 1.2 0.987 0.854 0.800 0.789 0.521 0.337 0.000 0.126 0.136 Ca. 0.2 0.250 0.277 0.336 0.342 0.403 0.440 0.53 0.74 0.91 0.763 ca. 1.1 1.18 1.53 1.63 1.66 1.70 1.80 1.85 2.37 2.71 2.87 2.93 3.05

of a single electrode, but can measure only the difference between the potentials of two electrodes. For this reason, the corrosion potential of an electrode is measured using another electrode called a ‘reference electrode’. Therefore, the corrosion potential should always be reported with respect to a reference electrode. Some commonly used standard reference electrodes are standard hydrogen

260

CHAPTER 5 Mechanisms

FIGURE 5.2 Copper and Zinc Experiment.6 Reproduced with permission from Wiley.

electrode (SHE) saturated the calomel electrode (SCE), silver/silver chloride (Ag/AgCl) electrode, and copper/copper sulfate (CCS) electrode.7 The corrosion potential measured against one reference electrode can be converted into that against another reference electrode. Table 5.4 presents correction factors for converting the corrosion potential from one reference electrode to another.8 Metals and alloys can be arranged on the basis of their corrosion potentials in a given environment (electrolyte). Such an arrangement of metals and alloys is called a ‘galvanic series’; this series is Table 5.4 Potentials of Standard Reference Electrodes and Conversion Factors to Convert Potentials Against One Standard Reference Electrode to Another8 To Convert toz Reference Electrode

Common Abbreviation

Potential (V) at 25 C (Vs SHE)y

Thermal Coefficient (mV)

SHE Scale

SCE Scale

Hydrogen Silver-Silver chloride Saturated calomel electrode Copper-copper sulfate

SHE Ag/AgCl) SCE)) CCS

0.000 þ0.235 þ0.241 þ0.300

þ0.87 þ0.25 þ0.22 þ0.90

N/A þ0.235 þ0.241 þ0.300

0.241 0.006 N/A þ0.060

) with 1 M KCl as internal electrolyte; in addition sea water with 0.6 M chloride ion or solution with 0.1 M chloride ion is also used as internal electrolyte )) the internal electrolyte contains excessive amounts of potassium chloride (KCl) crystals; therefore the electrolyte is saturated; in addition 0.1 M KCl or 1 M KCl solution is used as internal electrolyte y the potential of reference electrodes depend on the concentrations of internal electrolyte z An electrode potential of þ1.000 V versus SCE would be (1.000 þ 0.241) equal to þ1.241 V versus SHE. On the other hand, an electrode potential of 1.000 V versus SCE would be ( 1.000 þ 0.241) equal to 0.759 V versus SHE

5.2 Electrochemical nature of corrosion

261

Table 5.5 Galvanic Series vs. EMF Series9 Galvanic Series

EMF Series

List of metals and alloys Tendency of corrosion of metals and alloys in a given environment (e.g., sea water) Several galvanic series can be developed to represent corrosion tendency of metals and alloys in various environments Associated with ‘corrosion potential’

List of metals ONLY Tendency of corrosion of metals in solution of its own ions at unit activity Only one series

Associated with equilibrium ‘redox potential’ or ‘reversible potential’

different from the EMF series presented in Table 5.3. Table 5.5 presents the difference between galvanic and EMF series.9 Using the galvanic series, the tendency for a metal listed in the series to act as cathode can be predicted if the metal has a more positive potential than the other metal in the couple. On the other hand, if the potential is more negative the metal will probably be the anode in the couple. If a metal or alloy has the tendency to corrode in a given environment, the next question is; at what rate does it corrode? The corrosion potential only indicates the tendency of metals to corrode, but it does not provide the rate of corrosion. Corrosion rates are proportional to the rate of electron transfer between electrode and electrolyte, and the rate of electron transfer is represented as current (I). Normally, the current over the surface area is measured and reported as current density (i). It should further be noted that the rate of electron transfer is determined by the rate of the slowest step of the ACME process. If a metal (e.g., zinc) is in equilibrium with its own ions at unit activity (i.e., it would be at standard redox potential (as given in Table 5.3)). The rate of exchange of electrons under this condition is known as the exchange current density (iZnnþ/Zn). Similarly, if we consider a hydrogen electrode in equilibrium with Hþ ions, it would be at redox potential (EHþ/H) and there would be a corresponding exchange current density (iHþ/H). What will happen if we combine these two systems? If the zinc is immersed in a solution containing Hþ ions (e.g., hydrochloric acid), the potential of the metal will not be at the redox potential of either the zinc or the hydrogen, but it will stabilize at the corrosion potential (Ecorr). Figure 5.3 illustrates how the system moves from the redox potentials of zinc and hydrogen towards the corrosion potential. Evans first developed the figure which illustrates how the potentials of anode and cathode will move when they are connected; therefore Figure 5.3 is commonly known as an Evans diagram.10 At Ecorr the rate of zinc dissolution is equal to the rate of hydrogen evolution and charge conservation is maintained. The current at Ecorr is known as Icorr, which is the rate at which the zinc will corrode when it is immersed in hydrochloric acid. Thus, by measuring the current density one can determine the rate of corrosion. From the above discussion it can be inferred that by altering the potential of the metal by an external source one can alter its corrosion. If the potential is moved in the positive direction, the rate of anodic reaction increases; similarly if the potential is moved in the negative direction, the rate of cathodic reaction increases. Controlling corrosion by moving the potential in the negative direction using an external source is the basic principle of cathodic protection (CP) (see section 9.3 for more discussion).

262

CHAPTER 5 Mechanisms

FIGURE 5.3 Evans Diagram (Zinc immersed in a solution containing hydrogen ions at 25 C).10 Reproduced with permission from McGraw-Hill.

In terms of altering the potential, the concept of activation control and diffusion control should be understood. Figure 5.4 illustrates that, as the potential of the metal is moved in the negative direction (active direction) by external equipment, the rate of reduction reaction taking place on its surface increases.11 If we assume that the cathodic reaction is the reduction of hydrogen ions, the scenario of the metal in the solution will be similar to that presented in Figure 5.5.12 Initially when the potential is close to the corrosion potential, the concentration of hydrogen ion is uniformly distributed. This

+ Activation polarization E

Concentration polarization

–

log i

FIGURE 5.4 Variation of Potential and Current Density of Metal When the Reduction Reaction Changes from Activation Control (Identified as activation polarization region in which the current increases as the potential moves in the negative direction) to Diffusion Control (Identified as concentration polarization region in which the current does not change as the potential moves in the negative direction).11 Reproduced with permission from McGraw-Hill.

5.2 Electrochemical nature of corrosion

263

H+ H+

H+

H+

H+ H+

H+

H+

H+

H+

H+

H+

H+ H+

H+

H+ H+

H+ H+

H+

H+

H+

H+

Low reduction rate

H+ H+

H+ H+

H+

H+ H+ H+

H+ H+

H+

H+

H+

High reduction rate

FIGURE 5.5 Schematic Diagram of Solution Concentration of Hydrogen Ion Surrounding Metal Undergoing Cathodic Reaction (Activation Control (large amounts of hydrogen ions are present around the electrode because the rate at which the electrons are transferred between electrode and solution is low) to Diffusion Control (very small amounts of hydrogen ions are present around the electrode because the rate at which the electrons are transferred between electrode and solution is high; consequently the rate at which the hydrogen ions diffuse from the bulk towards the metal surface controls the overall rate)).12 Reproduced with permission from McGraw-Hill.

scenario usually implies that the reaction (corrosion) rate is under charge transfer control (the rate at which the electrons are transferred between the metal and solution). An electrode exhibiting this behavior experiences “activation control”. An electrode exhibiting activation control has its reaction rate (corrosion rate) determined by Tafel kinetics (see section 8.2.2b.ii). As the potential is moved from the corrosion potential, the concentration of hydrogen ions in solution surrounding the electrode depletes; i.e., they are consumed by the reduction reaction. Consequently, more hydrogen ions diffuse from the bulk towards the electrode. When the rate of diffusion to the electrode surface can no longer keep up with the rate of reaction, the electrode experiences diffusion control, and the effect of this limitation on the potential is known as concentration polarization. When the electrode reaches the point where the current (i.e., corrosion rate) no longer is affected by small changes in the potential, the concentration of the reactant at the electrode surface is zero (Fig. 5.5: High reduction rate). The corrosion rate is controlled by the slowest reaction; it may be charge controlled or diffusion controlled, depending on the potential and on the distribution of ions in the solution surrounding it. Under charge controlled conditions, the rate of electron transfer determines the corrosion rate; whereas under diffusion controlled conditions, the rate of diffusion of reactants determines the corrosion rate. Under diffusion controlled conditions, the corrosion rate is independent of the potential. The corrosion rate under diffusion controlled conditions may be increased by increasing the solution flow rate; i.e., by increasing the diffusion rate. On the other hand, under charge controlled conditions, an increase in flow rate has no effect on the corrosion rate; this scenario occurs in the absence of other mechanical effects of flow such as erosion.

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CHAPTER 5 Mechanisms

5.3 General corrosion As presented in section 5.2, both anodic and cathodic sites reside in the same piece of metal. The anodic and cathodic reactions on the metal surface do not partition, but occur simultaneously over the entire surface. Therefore, corrosion proceeds uniformly over the entire surface and the metal thins uniformly. Figure 5.6A illustrates this concept, by showing 50% of the area as anode and 50% of the area as cathode. In reality, however, such distinction can not be made on the metal. Uniform or general corrosion represents loss of metal on a tonnage basis, but this type of corrosion seldom occurs. One example of general corrosion in the oil and gas industry is corrosion of acidizing pipes in the presence of hydrochloric acid. However, many factors convert uniform corrosion into localized corrosion, including variation of corrosion surface layers, extraneous materials, velocity, and metallurgy. If the product of the corrosion reaction dissolves in the environment, corrosion continues to take place uniformly. But beyond a certain point, due to solution saturation, some products may deposit back onto the surface. If the deposition occurs uniformly, then the surface is fully covered and no corrosion reaction takes place. Neither uniform corrosion nor intact surface layer formation occurs all the time in practice. Usually the surface layers (which may also be known as passive layers) are formed discontinuously, and at various thicknesses at various locations in the structure. In addition, several other factors facilitate localized corrosion; some of them are described in the following paragraphs: Extraneous materials such as sand, clay particles may deposit on the surface. Solution species may locally alter the corrosion rate. Surface layers may form irregularly. If the velocity of the flow to and from the surface is constant over the entire surface, then mostly general corrosion takes place. But flow is likely to vary across the surface, facilitating localization.

(A)

(B)

(C)

Anode Cathode

FIGURE 5.6 Illustration of Situation when Uniform Corrosion Occurs. [A: 50% of the surface is anode and 50% is cathode] and when Localized Corrosion Occurs [B: Percentage Anode is Larger than Percentage Cathode and C: Percentage Anode is Smaller than Percentage Cathode] (A) (B) (C). Note: This figure is only an “illustration” and it does not have any theoretical reasoning. Literal interpretation of the figure may appear to be in violation of mixed-potential theory proposed by Wagner and Traud.

5.5 Pitting corrosion

265

As discussed in section 3.2, grains and grain boundaries exist at different energy levels, facilitating localization of corrosion. Impurities such oxides and other inclusions, mill scale, orientation of grains, dislocation arrays, differences in composition of the microstructure, precipitated phases, localized stresses, scratches and nicks all facilitate localized corrosion. General corrosion is mitigated by appropriate material selection and by using corrosion inhibitors (see section 7.4).

5.4 Galvanic corrosion Galvanic corrosion occurs when dissimilar metals or alloys are electrically in contact with one another and are immersed in a conductive solution. From the galvanic series (section 5.2) it is obvious that a potential difference exists between two dissimilar metals in contact with one another in a solution. The further apart the metals are from one another in the galvanic series, the greater the galvanic corrosion. The corrosion of less corrosion-resistant material (active side) increases whereas that of the more corrosion-resistant material (noble side) decreases; i.e., the less corrosion-resistant material becomes the anode and the more corrosion-resistant material becomes the cathode, leading to galvanic corrosion. The galvanic effect of connecting dissimilar metals is highest at the junction between them, and decreases progressively with distance. The extent of the decrease depends on the conductivity of the solution; the higher the conductivity, the greater the distance over which the galvanic effect extends. On the other hand, in a non-conducting electrolyte, the galvanic corrosion occurs in smaller area around the junction between metals and manifests as sharp groove. The anode-cathode relative area affects galvanic corrosion; a large cathode surrounding a smaller anode creates conditions for accelerated galvanic corrosion. To minimize galvanic corrosion, metals close to one another in the galvanic series are chosen. In addition, to the greatest extent possible, unfavorable area effects, i.e., small anode and large cathode, are avoided. Electrically connected dissimilar metals are insulated from the electrolyte by coating. The structure is designed in such a way that the anodic areas can be replaced relatively easily.

5.5 Pitting corrosion1,2 When the surface areas of anodic and cathodic sites are different (as illustrated in Figures 5.6B and 5.6C), localized, rather than general, corrosion takes place. In localized corrosion the rates of corrosion in certain areas of the metal are higher than those in other areas. In Figure 5.6B the percentage of the anodic area is higher than that of the cathodic area. In this scenario, corrosion takes place over more of the surface of the metal. The ultimate result is similar to general corrosion. On the other hand, in Figure 5.6C, the percentage of the cathodic area is larger than that of the anodic area. In this scenario, corrosion takes place in small area with the large areas acting as cathode. This scenario causes pitting corrosion – the extreme form of localized attack resulting in holes in the surface. During pitting corrosion, amount of metal lost is small, but is lost from a relatively small area, so pitting is one of the most destructive and insidious forms of corrosion. Pits may form in various shapes, with irregular walls. Figure 5.7 presents some typical pit shapes.13 Pitting corrosion is a process that consists of three stages: formation of surface layer on the steel surface; initiation of pits at localized regions where layer breakdown occurs; and pit propagation and eventual penetration of the material.

266

CHAPTER 5 Mechanisms

(a) Narrow, Deep

(b) Elliptical

(e) Undercutting

(d) Subsurface

(Horizontal)

(c) Wide, Shallow

(Vertical) (f) Microstructural Orientation

FIGURE 5.7 Typical Shapes of Pits.13 Reproduced with permission from ASTM.

Surface layers generally form adjacent to the metal. For some metals and alloys, e.g., stainless steel, titanium, the surface layer is inherent, i.e., the surface layer is formed as the metal or alloy is produced, by the reaction between the metal or alloy and the atmosphere. This air-formed surface layer is usually the oxide of the metal or alloy. Such a layer is compact, adherent to the metal surface, and protects it from further corrosion. This surface layer is often known as a primary passive, or simply passive, layer. For some metals and alloys, e.g., carbon steel, the air-formed primary passive layer is not compact and does not protect the metal surface from corrosion. However, when exposed to certain environments, a compact and adherent surface layer may form, as a consequence of a corrosion reaction between the metal and the environment. This layer is commonly known as a precipitated layer, secondary layer, or salt layer. The secondary layer may incorporate anions and cations from the solution and may be porous. It is thick and is usually visible to the naked eye. It usually forms on top of primary layer. Neither primary nor secondary surface layers are static; i.e., they break and reform continuously. Figure 5.8 presents general features of the passive layers. The pits initiate at localized regions where passive breaks down. Initiation of pits depends on passive layer composition, thickness and the presence of extraneous ions, such as chloride ions. The pit initiation is a random process with respect to space and time. An experiment to demonstrate the random nature of pit initiation was conducted by Fleischmann. In this experiment, 50 identical test samples were electrochemically subjected to pit initiation by the application of a potential. The resulting current was used to determine if pits were initiated or not (Figure 5.9). The scatter in the experimental results illustrates the randomness of pit initiation. When a pit stabilizes, i.e., large local cathodes surround a small anode, it propagates continuously until failure occurs. Mostly the pit growth rate decreases progressively with time as the passive layers reform at its tip. Sometimes pit growth rate accelerates if its tip continues to be an anode, and the cathode to anode ratio increases. This process is known as autocatalytic pit growth.

5.6 Intergranular corrosion

M+

M++OHLayer dissolution

Metal

Primary passive layer

267

M(OH)

Porous, precipitated layer

Solution

Layer growth

O2

FIGURE 5.8 General Features of Passive Layers.

FIGURE 5.9 A Laboratory Experimental Result on the Initiation of Pits in Stainless Steel (Y axis is current in microampere).14 Reproduced with permission from The Electrochemical Society.

Pitting corrosion may be controlled by appropriate material selection and by addition of corrosion inhibitors (see section 7.4).

5.6 Intergranular corrosion Section 3.2 describes grain and grain boundaries. Corrosion occurs preferentially at or near grain boundaries whereas grain crystals are immune; this type of corrosion is known as intergranular corrosion. In extreme cases, intergranular corrosion may cause sudden loss of tensile properties, even though only a small volume of metal in or around the grain boundaries has corroded. Figure 5.10 presents a typical morphology of intergranular corrosion.15

268

CHAPTER 5 Mechanisms

FIGURE 5.10 Example of Intergranular Corrosion.15 Reproduced with permission from ASM International.

Grain boundaries undergo more corrosion when certain substances are enriched or depleted in them; i.e., when the chemical composition of grain boundaries and grains is different. This difference in chemical composition develops due to migration of impurities or alloying elements from the grain to the grain boundaries. At sufficiently high concentrations, these impurities may react with other constituents in the grain boundaries producing new compounds or constituents, i.e., secondary phases. This difference in chemical composition causes a potential difference between grain boundaries and grains, creating conditions for intergranular corrosion. In a way, intergranular corrosion is a special type of galvanic corrosion. The constituents of the grain boundaries may be anodic, cathodic, or neutral with respect to the grains. If the constituent is anodic, grain boundaries corrode preferentially causing intergranular corrosion. If the constituents in the grain boundaries are cathodic to those in the grains, intergranular corrosion may occur in areas adjacent to grain boundaries. The metallurgical history of the metal or alloy is as important as chemical composition in creating conditions for intergranular corrosion to occur. Some metallurgical treatments causing intergranular corrosion include heat treatment (heating and then cooling a material to obtain desired property), cold-working (deforming a material at room temperature to induce strain hardening), and welding (joining two pieces of material by applying heat or pressure). Improper heating (either during heat treatment or welding) may segregate and precipitate the constituent elements. If these precipitated elements accumulate along the grain boundaries they may cause intergranular corrosion. If the precipitated elements disperse throughout the grains, intergranular corrosion does not occur. Cold work may also cause accumulation of precipitated elements in the grain boundaries and may increase susceptibility to intergranular corrosion or may break up the precipitated elements along the grain boundaries thereby reducing the susceptibility for intergranular corrosion. The metallurgical state caused by heating, cooling, or cold working that cause material to be susceptible to intergranular corrosion or cracking is known as sensitization. Sensitization is caused due to precipitation of constituent elements in the grain boundaries. Austenitic stainless steel may suffer from intergranular corrosion after welding. This occurs if the welding process precipitates chromium carbide in the grain boundaries, reducing the chromium content in the grain immediately adjacent to the grain boundaries. The adjacent area deficient in chromium

5.7 Selective leaching (Dealloying)

269

Table 5.6 Examples of Intergranular Corrosion Metal/alloy Undergoing Intergranular Corrosion

Substances Causing Intergranular Corrosion

Aluminum Stainless steel

Duraluminum (Al-Cu alloy)

Causes

Remedy

Segregation of iron Depletion of chromium

Reactive material in the grain Formation of chromium carbide

Depletion of copper

Precipitation of CuAl2. Substantial potential difference exists between copper-depleted area and adjacent material

Proper microalloying 1. Quench-annealing 2. lowering the carbon content to below 0.03% Solution-quenching

undergoes corrosion. Intergranular corrosion may occur on both sides of a weld and immediately adjacent to it, with practically no corrosion in the rest of the material. Sometimes intergranular corrosion may lead to knife-line attack (KLA) which normally occurs in a narrow band in the parent metal immediately adjacent to weld. Intergranular corrosion may also lead to grooving corrosion along the weld-line. Table 5.6 presents some common materials susceptible to intergranular corrosion, and its causes. Intergranular corrosion is mitigated by adding stabilizers and by heat treatment. Stabilizers are elements that have higher affinity to form their own carbides. Addition of stabilizers decreases the susceptibility to intergranular corrosion of stainless steel. Common stabilizers include columbium and tantalum which preferentially form their own carbides thereby preventing formation of chromium carbide in the grain boundaries. Heat-treating stainless steel after welding to a temperature where chromium carbide dissolves and columbium carbide forms decreases its susceptibility to intergranular corrosion. However, grooving-type corrosion cannot be mitigated by heat treatment.

5.7 Selective leaching (Dealloying) Selective leaching is a process in which one metal dissolves preferentially from an alloy. Selective leaching may also be known as dealloying, parting, or selective dissolution. The term dealloying is more commonly used nowadays. Dealloying may also be explained as another type of galvanic corrosion, because the material leaching out is anodic. An example is zinc in brass, because it is anodic to copper. Dealloying of zinc from brass alloys is commonly known as dezincification. Dezincification may be visible to the naked eye, as the characteristically yellow brass turns into red copper. Dezincification may occur uniformly or in a localized fashion. In brasses with high zinc content, dezincification occurs uniformly in acid solutions, and in brasses with low zinc content, dezincification occurs locally in alkaline or neutral solutions. Other examples of dealloying include the removal of aluminum from aluminum bronzes; silicon from silicon bronzes; cobalt from cobalt-tungsten-chromium alloys, and iron from cast irons. Dealloying of iron from grey cast iron may sometimes be known as graphitic corrosion, due to the presence

270

CHAPTER 5 Mechanisms

of graphite (carbon) after the removal of iron. Neither ductile iron nor white cast iron will exhibit this form of corrosion. Dealloying may be accelerated by higher temperatures, higher chloride content, lower flow velocity, and the presence of crevices and deposits. It may be minimized by reducing the corrosivity of the solution or by application of cathodic protection, but neither of these options are economical. The better option is to use material not susceptible to dealloying. This may be attained either by decreasing the concentration of anodic material in the alloy or by adding another material. For example, reducing the zinc content to less than 15% makes red brass immune to dezincification. Addition of 1% tin to 70–30 brass (Admiralty metal) decreases its susceptibility to dezincification.

5.8 Deposition corrosion Deposition corrosion is another form of galvanic corrosion. It occurs when ions of a more noble metal deposit from solution onto a more active metal. Common metals (that are more noble in the galvanic series) triggering deposition corrosion are copper and mercury. Common metals (that are more active in the galvanic series) undergoing deposition corrosion are magnesium, zinc, and aluminum. Galvanized (zinc plated) steel or aluminum vessels suffer from deposition corrosion when copper ions form solution deposit on them. This may occur when soft water passing through copper water pipes is collected in galvanized steel or aluminum vessels. Copper water pipes corrode when soft water passes through them. The resultant copper ions dissolve in soft water and deposit downstream on galvanized steel or aluminum vessels, causing deposition corrosion. Deposition corrosion is prevented by scavenging copper ions from the water before it enters galvanized steel or aluminum vessels. This is normally done by passing soft water through a tower packed with more anodic metal turnings on which the copper ion deposits.

5.9 Crevice corrosion Metals (including aluminum, stainless steel, titanium, and magnesium) which are protected from corrosion by passive films are more susceptible to crevice corrosion. Crevice corrosion occurs in shielded area containing small amounts of stagnant solution. The shielded area, such as a crevice or crack, may form between metal surfaces as well as between metal and non-metal surfaces. Any material including washers, gaskets, scale, deposits, wood, plastic, rubber, glass, concrete, asbestos, wax, or fabrics can create a crevice. Figure 5.11 presents a typical geometry of metal undergoing crevice corrosion. For corrosion to occur, the crevice must be wide enough to permit entry of liquid, but narrow enough to maintain stagnant solution. Crevice corrosion does normally not occur when the groove or slot is wider than 125 mil (w3 mm). The most common reason for corrosion to occur in crevices is differential aeration of solutions between the crevice and outside. Initially both anodic and cathodic reactions take place uniformly inside a crevice; subsequently oxygen (or any other species undergoing reduction) becomes depleted and solution inside the crevice becomes acidic. As a consequence, the metallic area within the crevice becomes the anode and the area outside crevice becomes the cathode. Crevice corrosion is thus a special case of pitting corrosion, in which the physical existence of a crevice facilitates the

5.10 Cavitation-corrosion

271

Crevice

FIGURE 5.11 Typical Geometry of Crevice Corrosion.

establishing of conditions for pitting corrosion to occur. Similar to pitting corrosion, extraneous ions (mostly chloride) accelerate the crevice corrosion rate. Crevice corrosion can be avoided by some design changes; for example, by welding the joints rather than riveting or bolting them together. The existing crevices in the structure may be plugging by welding, caulking, soldering, or filling with suitable materials. Materials used for filling the crevice should exclude moisture and should remain resilient, e.g., polytetrafluoroethylene (PTFE) gaskets are frequently used. The TeflonÔ suffers creep when under stress, and a joint that is tight initially may lose its tightness during service. The potential for crevice corrosion may also be avoided by preventing the accumulation of stagnant water. This can be achieved by designing drainage.

5.10 Cavitation-corrosion Cavitation-corrosion is the combined deterioration of a surface by the formation and collapse of bubbles in a liquid, as well as corrosion. Cavitation-corrosion may also be known as cavitation erosion. Although there is a slight difference between the two – during cavitation-corrosion both corrosion and cavitation damage occur, and during cavitation-erosion only cavitation damage occurs-it may be very difficult delineate the corrosion effect from cavitation forces. Cavitation-corrosion occurs in facilities such as hydraulic turbines, turbine blades, propellers, submerged planes, and pump impellers. To understand the formation and collapse of a cavity in the system, a cylinder containing water and fitted with a tight piston may be considered. When the piston moves outward, the volume inside the cylinder increases, and consequently the pressure decreases. At reduced pressure, the water starts to boil, forming bubbles at room temperature. When the piston now moves inward, the volume decreases, the pressure increases, and the bubbles collapse. This process is repeated many times at high speed in turbines, propellers, and impellers, leading to the rapid formation and collapse of bubbles. The collapsing bubbles destroy protective layers on the metal surface. The unprotected metal surface undergoes corrosion and the protective layer is reformed. Bubble reform and collapse destroys the newly formed surface layer. These processes repeat to create a cavity, which grows in depth until failure occurs. In the absence of protective surface layers, bubble formation and collapse propagates cavitation by plastic deformation (which tears metal particles away from the surface) of the metal. Corrosion

272

CHAPTER 5 Mechanisms

facilitates the propagation of cavitation further. Thus cavitation-corrosion is a synergistic action involving both mechanical (bubble formation and collapse) and electrounder chemical (corrosion) processes. Cavitation damage can be controlled by minimizing the probability of bubble formation and collapse, which can be achieved by designing hydrodynamic systems with smaller pressure differences. In the case of a pump experiencing cavitation the standard approach is to increase the system pressure sufficiently to prevent bubble formation at the low pressure points in the system. Further, hydrodynamic systems are fabricated with materials which are resistant to corrosion and mechanical damage. With respect to material selection, it should be noted that ductile materials are more resistant than brittle materials, materials with higher fatigue resistance also have higher resistance to cavitationcorrosion, and resistance to cavitation-corrosion increases with decreasing grain size of materials. Rough surfaces provide more sites for bubble nucleation than smooth surfaces; therefore the surfaces of pump impellers and propellers may be smoothened. Material surfaces are protected with coatings; commonly rubber or plastic. In using the coating, it should be noted that disbonded areas between the metal and the coating may act as potential sites for cavity formation. Cathodic protection and the application of corrosion inhibitors reduce the rate of cavitation-corrosion by controlling corrosion. However, they do not reduce cavitation damage by mechanical forces.

5.11 Mechanical forces Material loss by corrosion occurs mostly by electrochemical mechanisms (see section 5.2). In addition, material loss may occur due to mechanical forces. Depending on the interacting phases and the nature of their interaction, the mechanical forces may be divided into: erosion, abrasion, and wear. In general, erosion involves impingement (impact) of solid or liquid particles in a fluid (e.g., liquid) onto a surface; abrasion involves interaction between the surface and hard solid particles normally in one direction, and wear involves relative motion (rubbing) between the surface and another solid substance in more than one direction. When mechanical forces (erosion, abrasion, or wear) and corrosion occur simultaneously, the combined effect may be more severe than sum of all individual effects. As a consequence, the total material loss is far higher than the sum of material loss due to each individual action, i.e., the interaction is synergistic in nature. Figure 5.12 presents different conditions in which various mechanisms prevail.16 The rest of this section discusses erosion-corrosion, but the principles apply to other interactions between corrosion and mechanical forces such as abrasion and wear. Erosion-corrosion is normally more common in curved portions of infrastructure than in straight sections; these include pipe expansions and contractions, bends, elbows, tees, centrifugal pump blades, propellers, pumps, valves, orifices, impellers, agitators, nozzles, baffles, and grinders. Erosioncorrosion produces grooves, gullies, waves, rounded holes and valleys. The mechanism of erosion-corrosion is similar to that of cavitation-corrosion, except that the former occurs due to the presence of solid particles already present in the liquids. The flow destroys protective surface layers on the metal surface by impacting gas, liquid, or solid particles onto it. The unprotected metal surface undergoes corrosion and the protective layer is reformed. Further flow impacts more particles onto the same spot and destroys the newly formed surface layer. These processes repeat to remove more metal particles until failure occurs. In the absence of protective surface layers, erosive forces can physically remove metallic particles at higher flow rates. Thus, similar to

5.11 Mechanical forces

273

FIGURE 5.12 Interaction Between Corrosion and Mechanical Forces.16 (Corrosion dominates in stages A and B; both corrosion and erosion occur in stages C and D; and erosion dominates in stage E). Reproduced with permission from NACE International.

cavitation-corrosion, erosion-corrosion is a synergistic action of both mechanical (erosion) and electrochemical (corrosion) processes. In the absence of corrosion, erosion may occur, causing mechanical damage to materials. Chemical composition, corrosion resistance, hardness, and metallurgical history determine the susceptibility of materials to erosion-corrosion. Materials which are more corrosion resistant are less susceptible to erosion-corrosion than those which are less corrosion resistant. For example, 80% nickel – 20% chromium has higher resistance to erosion-corrosion than 80% iron – 20% chromium (nickel has higher corrosion resistance to corrosion than iron). In some cases, addition of third element increases resistance to erosion-corrosion, by increasing resistance to corrosion. For example, addition of molybdenum to 18–8 stainless steel stabilizes protective surface layers and hence increases resistance to both corrosion and erosion-corrosion. However, molybdenum will provide increased resistance only in chloride environments, but not necessarily in other environments. Soft materials such as copper and lead are more susceptible to erosive forces. The hardness of a material may be an indicator of its resistance to erosion; the higher the hardness, the higher the resistance to erosion. However, hardness may not be an indicator of resistance to erosion-corrosion, because hardened materials may lose their resistance to corrosion. An increase in flow rate, in general increases the erosion-corrosion rate. However, a minimum critical velocity is required for erosion forces to act. The critical velocity depends on the material, the type of entrained particles (gases or solid), and the type of fluid. More than flow rate, turbulence is the main cause of erosion-corrosion. Severe erosion-corrosion occurs in locations where laminar flow

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CHAPTER 5 Mechanisms

FIGURE 5.13 Erosion-Corrosion at a Pipe Expansion.17

changes into turbulent flow. For this reason, the inlet end of a larger diameter pipe connected to a smaller diameter pipe is more susceptible to erosion-corrosion (Figure 5.13).17 Sharp changes in crosssection and obstructions such as ledges, pits, crevices, and deposits increase turbulent flow and hence the erosion-corrosion rate. Erosion-corrosion may be controlled by using materials with better resistance to erosion-corrosion and by increasing the thickness of materials in locations susceptible to erosion-corrosion. It may also be controlled by decreasing velocity and by creating laminar flow conditions, e.g., by increasing the diameter of the pipe and by increasing the angle of pipe bend (smooth bends reduce the effect of impingement). Addition of corrosion inhibitors, adjustment of temperature, and removal of oxygen may decrease the corrosivity of the environment, but this approach may not be economically feasible in all conditions. Filtering and removing solid particles decreases the erosivity of the environment. Hard facing and weld overlays increase resistance to erosion, as long as the materials used for this purpose also have corrosion resistance. Cathodic protection prevents corrosion and is effective only when corrosion plays major role in erosion-corrosion.

5.12 Fretting corrosion Fretting corrosion is a special type of erosion-corrosion which occurs in the atmosphere rather in aqueous solutions. Fretting corrosion occurs due to vibration and slip in contact areas between

5.13 Underdeposit corrosion

After

Before

Oxide layers

275

Exposed metal Oxide particles

FIGURE 5.14 Mechanism of Fretting Corrosion.18 Reproduced with permission from McGraw-Hill.

materials under load. It appears as pits or grooves surrounded by corrosion products. Fretting corrosion may also be known as friction oxidation, wear oxidation, chafing, or false Brinelling (because of the appearance of pits similar to the indentations created in a Brinell hardness test). It may subsequently accelerate corrosion fatigue by creating excess strain and pits (which increase stress), and it occurs frequently at bolted tie plates and in long distance shipments (e.g., staggered pipes). Fretting corrosion occurs at the interface between components under load due to repeated motion or vibration between two surfaces (Figure 5.14).18 Continuous motion does not lead to fretting corrosion. Slip or displacement as low as 10 8 cm is enough. The slipped or displaced interface undergoes corrosion. Sequential formation of oxide by corrosion reaction and its destruction by wear causes fretting corrosion. Fretting corrosion may be controlled by applying lubricants which reduce friction between the surfaces. Grease is normally used. Porous coatings, e.g., phosphate coating, may be used along with grease, as the porous coating retains grease for a longer duration. Other methods to control fretting corrosion include use of hard materials that resist wear, use of a gasket that absorbs vibration, increasing the load (which will decrease relative motion) and increasing roughness and so increasing friction between the materials (increasing the friction decreases the relative motion between the materials).

5.13 Underdeposit corrosion Corrosion taking place beneath a solid material deposited on another material is known as underdeposit corrosion. Underdeposit corrosion may be a form of crevice corrosion. The deposit may either be a product of a corrosion reaction or a suspended solid in the solution. Some common deposits are scale, sand, other solid particles (e.g. clay, FeS, and FeCO3), elemental sulfur, and biofilm. A corrosive space (see Figure 5.15)19 between the deposit and the surface is established by the formation of deposits with void. Conductive fluid accumulates in the space, either by permeation across the deposit or by lateral transportation between the deposit and the metal surface. Corrosion occurs in the space. If the product of the corrosion reaction deposits on the metal surface, corrosion ceases.

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CHAPTER 5 Mechanisms

M -> Mn++neO2 -> ne- +OH-

Solution

Metal

FIGURE 5.15 Mechanism of Underdeposit Corrosion.19

On the other hand, if the corrosion reaction depletes the corrosive species (e.g., oxygen, CO2, and H2S), a differential aeration cell is established. The metal exposed to the oxygen-depleted solution under the deposit becomes anodic, and the metal exposed to oxygen-saturated fluids outside the deposit becomes cathodic. To neutralize the metal cations (e.g. Fe2þ) produced by the anodic reaction, anions (e.g., chloride ion) migrate into the space under the deposit; this process sustains the anodic nature of the metal surface under the deposit. The rate of corrosion depends on the difference in the concentration of oxygen (or any other corrosive species) in the solution under the deposit and in the bulk. Underdeposit corrosion may be controlled by avoiding deposit formation, by avoiding the formation of spaces between deposits, and by avoiding the accumulation of solution in these spaces. For example, if solution reaches the species under the deposit laterally, the point at which solution comes in contact with the surface should be plugged. The formation of deposits may be avoided, either by filtering off the solids, or by treating the solution with chemicals to dissolve corrosive species. Finally the deposited solids may be removed, e.g., by pigging (see section 7.2).

5.14 Microbiologically influenced corrosion Microbiologically influenced corrosion (MIC) occurs when microbial activity increases the rate of corrosion. Two mechanisms frequently used to explain microbial action are the classical mechanism and the modern mechanism.

5.14.1 Classical mechanism According to the classical mechanism, microbial activities produce chemicals that participate in a corrosion reaction, accelerating it. Predominantly four microbial species are known to influence MIC; sulfate-reducing bacteria (SRB), acid producing bacteria (APB), iron-reducing bacteria (IRB), and iron-oxidizing bacteria (IOB). SRB bacteria convert sulfate into sulfide, and this reaction requires hydrogen atoms. Thus in the presence of SRB, cathodic hydrogen reduction accelerates (as the hydrogen atoms produced in

5.14 Microbiologically influenced corrosion

277

corrosion are consumed by SRB activities), and consequently, the corrosion rate increases. The sequence of anodic and cathodic reactions in the presence of SRB is as follows: Taking the example of dissolution of iron, the anodic reaction is: Fe/Fe2þ þ 2e

(Eqn. 5.8)

In acidic pHs, the hydrogen ion undergoes a cathodic reaction as: Hþ þ e /H

(Eqn. 5.9)

Hydrogen atoms combine to form hydrogen molecules which evolve as gas. But SRB consume hydrogen atoms in the process of converting the sulfate ion into sulfide: SO4 2 þ H/S2 þ H2 O

(Eqn. 5.10)

Thus, when SRB are active, the cathodic reaction accelerates and consequently the corrosion rate increases. Thus SRB accelerate corrosion only if the cathodic reaction is the rate determining step; i.e., the slowest step in the ACME process (see section 5.2). Ferrous ion produced during the anodic reaction (Eqn. 5.8) combines with sulfide ions (Eqn. 5.10) to produce iron sulfide: Fe2þ þ S2 /FeS

(Eqn. 5.11)

Thus when SRB are active, FeS is the common corrosion product. In contrast, APB influence corrosion by converting organic materials into CO2, which hydrates in water to produce carbonic acid (see section 4.5 for corrosion due to carbonic acid). Thus when APB are active, iron carbonate is the predominant product. It should however be noted that carbon dioxide may also occur naturally. Therefore sometimes influence of APB is not predominant. IRB influence corrosion by reducing insoluble Fe3þ oxide layer to soluble iron ions (Fe2þ). The result is the dissolution of the protective oxide layer. IOB, on the other hand, oxidize soluble Fe2þ to insoluble Fe3þ. If the formation of the insoluble Fe2O3 layer is uniform, corrosion will be reduced, but often the layer is not uniform; consequently localized corrosion takes place.

5.14.2 Modern mechanism Microbiologically influenced corrosion mostly results in localized corrosion. the modern MIC mechanism proposes that the initial step is the formation of a biofilm. Figure 5.16 presents a schematic diagram of biofilm formation.20–21 The planktonic bacteria floating in the solution attach onto a solid surface using exopolymers. The attached bacteria (i.e., sessile bacteria) further grab planktonic bacteria through their exopolymer group thereby growing the biofilm. The biofilm may therefore be composed of several species of bacteria and, consequently, several reactions may take place. Figure 5.17 presents some reactions taking place within the biofilm.22 Bacterial activity reduces the oxygen content within the biofilm, so the surface of the metal covered by biofilm becomes anaerobic, even when the solution is aerobic (i.e., saturated with oxygen). Thus the biofilm provides a secluded area for bacteria to thrive and to influence corrosion. Microbiologically influenced corrosion may be controlled by cleaning the surface to remove the biofilm (pigging – see section 7.2), applying biocides to control the bacterial activity in the solution (see section 7.5), and increasing the cathodic protection potential (see section 9.3.4). Pigging and

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CHAPTER 5 Mechanisms

2. 1.

Sessile bacteria

Conditioning film

EPS (Exopolymer)

4. 3.

= Sessile = Planktonic FIGURE 5.16 Schematic Diagram Illustrating Formation of Biofilm.21,22 Reproduced with permission from Woodhead Publishing.

FIGURE 5.17 Schematic Diagram Illustrating Typical Reactions Occurring within a Biofilm.22

5.15 High temperature corrosion

279

biocides are effective in controlling MIC inside an infrastructure, and studies have indicated that increasing the cathodic protection potential from the typical 0.85 V (Vs. CCS) to 0.95 V is effective in controlling MIC occurring on external surfaces.23

5.15 High temperature corrosion High temperature corrosion can broadly be classified into two types: that occurring in gaseous environments, and that occurring in liquid (molten) environments.

5.15.1 Gaseous environments Corrosion occurring when a metal is exposed to a gaseous environment at elevated temperature is known as high temperature corrosion. It may also be known as high temperature oxidation, high temperature tarnishing, or high temperature scaling. High temperature corrosion occurs in the absence of liquid electrolyte. Although it may start at approximately 480 F (w250 C), it normally occurs at temperatures above 840 F (w450 C). The product of reaction between metal and gas normally deposits on the metal surface as scale. The scale is protective when: it forms as solid that completely covers the metal surface; it is adherent onto the metal surface; it has high melting point so that it withstands higher temperature; and diffusion of species (e.g., metal cations or other anions) across it is low. When a scale with above characteristics is formed, the corrosion rate progressively decreases with time. On the other hand, if the scale is non-compact, metal cations and anions can diffuse across it. The rate at which ions diffuse across the scale depends on its porosity as well as the diffusion rate of species, electrical potential difference, and concentration gradient across it. The protectiveness of the scale also depends on the temperature. The scale is protective below its melting point and under this condition the corrosion rate may decrease progressively with time. The scale becomes nonprotective above its melting point and under this condition the corrosion damage increases linearly with time. Depending on the type of scale, high temperature corrosion may be classified as oxidation, sulfidation, nitridation, chlorination, or carburization.

5.15.1a Oxidation Oxidation is the most common mode of high temperature corrosion. Metals undergo oxidation in the presence of air, oxygen, and steam to produce oxide scales. The protectiveness of the oxide scale depends on the metal, environment, temperature, and other impurities. For example, Figure 5.18 illustrates the effect of the chromium content of steel on the type of oxides formed at high temperatures.24

5.15.1b Sulfidation Sulfidation is the formation of metal-sulfur scales in the presence of H2S or other sulfur-containing gaseous environments. Most sulfur-containing environments also contain oxygen; therefore both oxide and sulfide scales form together. The kinetics of sulfide scale formation are faster than that of oxide scale. The melting point of sulfide scale is lower than that of oxide scale; therefore formation of sulfide scale leads to increased corrosion.

280

CHAPTER 5 Mechanisms

Fe3O4 FeO

Parabolic rate constant, g2 . cm–4. s–1

10–6

10–7

Fe – 2Cr

Fe2O3 Fe Fe2O3 Fe3O4 FeO Fe/Cr oxide

Fe2O3 (Fe,Cr)2O3

10–8

Fe – 9Cr

Fe3O4

10–9

Fe2O3 Cr2O3

Fe – 16Cr

Fe Fe(2 – x)CrxO4

10–10 Cr2O3 Fe – 28Cr

10–11 0

10

20

30 40 50 60 70 Alloy chromium content, wt%

80

90

100

FIGURE 5.18 Schematic Diagram Illustrating the Effect of Chromium Content in Steel on the Type of Oxides form at High-Temperature.24 Reproduced with permission from ASM International.

5.15.1c Nitridation Nitridation is the formation of metal nitrides. Nitridation occurs in the presence of nitrogen or ammonia. The kinetics of nitridation in an ammonia atmosphere are slower than those in a nitrogen atmosphere. Nitridation increases localized corrosion due to the precipitation of metallic nitrides (e.g., nitrides of aluminum, titanium, niobium, and chromium). Nitridation will cause metal dusting in stainless steels.

5.15.1d Chlorination Chlorination is the formation of metallic chlorides. Metallic chlorides are volatile because of their appreciable vapor pressures at elevated temperatures, therefore their formation destroys otherwise stable oxide scale. In addition, the metallic chlorides react with oxygen in the gaseous phase to form chlorine gas (Eqn. 5.12), which increases localized corrosion by destroying the metal oxide scale: 2FeCl2 þ O2

> Cl2 þ 2FeO

(Eqn. 5.12)

5.15 High temperature corrosion

281

5.15.1e Carburization Carburization is the formation of metallic carbides by the reaction between metal and carbon at temperatures of 1,300–1,500 F (w700–800 C). Carburization commonly occurs in hydrocarboncontaining atmospheres. The high temperature decomposition of hydrocarbon (e.g., methane) forms carbon (Eqn. 5.13). Under most conditions, the metal surface is protected by oxide scale; however in hydrocarbon atmospheres carburization occurs at temperatures exceeding 1,300–1,550 F (w700–850 C): > 2H2 þ C (Eqn. 5.13) CH4

5.15.1f Metal dusting Metal dusting is a form of damage that occurs in high temperature environments. The oxide that develops on the stainless steel catalyzes graphite growth. The graphite causes the oxide to be spalled off the surface and rapid oxidation occurs. The new oxide is then spalled off and the process continues until failure occurs. Nickel is a prime catalyst in the process so alloys with high nickel contents are most susceptible. In cases where ethylene is present carburization may occur producing dust containing graphite and metal species. This occurs at very high temperatures. The metal species may further act as catalysts to decompose carbon monoxide and carbon sustaining the reaction. Consequently the localized corrosion rate increases rapidly.

5.15.1g Green rot Green rot is another special form of carburization. It commonly occurs in Cr-Ni alloys when they are cyclically exposed to carburization and oxidation atmospheres. Under this condition Cr-Ni alloys undergo severe metal loss, with the formation of a greenish chromium oxide residue. The kinetics of high temperature corrosion also depend on gas velocity, pressure, and impurities. Increasing gas velocity accelerates high temperature corrosion by promoting erosion-corrosion. On the other hand, a high gas velocity may decrease corrosion by removing less volatile oxides (e.g., vanadium pentoxide and molybdenum trioxide) from the metal surface. The influence of pressure on high temperature corrosion is insignificant, except when the operation pressure is within the dissociation pressure of the corrosion products. Under this condition, pressure significantly increases high temperature corrosion. The presence of impurities generally destabilizes the oxide scale, because of the formation of several types of heterogeneous scales. High temperature corrosion may be controlled by controlling the atmosphere to which metals are exposed and by using non-metallic coatings. The non-metallic coatings used to control high temperature corrosion are called refractory materials. Refractories are non-metallic materials whose chemical and physical properties do not change even when exposed to temperatures above 1,000 F (538 C).25

5.15.2 Liquid (Molten) environments The mechanism of corrosion in molten salts is analogous to that of aqueous corrosion. However, the molten environment is not prevalent in oil and gas industry operational conditions except in two special conditions as described in the following paragraphs. In fire situations (that occur in refineries) there have been cases where molten zinc had dripped from galvanized structural elements onto stainless steel piping and caused the pipes to fail from liquid

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CHAPTER 5 Mechanisms

metal embrittlement. This only happens when the stainless steel is at temperatures higher than 1,100 F (600 C). The other condition involves mercury that is present in extremely low concentrations in natural gas. When the gas is being liquefied, the mercury freezes out on the heat exchange surfaces. When the exchanger is subsequently cleaned, the mercury melts and attacks the aluminum heat exchanger. It amalgamates the surface and causes catastrophic corrosion (see section 4.14).

5.16 Corrosion fatigue Section 3.2.1e discusses metal fatigue. When a metal undergoes cyclic stress in a corrosive environment, the number of cycles required to cause failure is low. This acceleration of fatigue failure in the presence of corrosive environments is known as corrosion fatigue. Localized corrosion (e.g., pitting corrosion) increases susceptibility to corrosion fatigue more than general corrosion. Figure 5.19 presents a typical stress-number of cycle (S-N) curve of a metal in a corrosive environment;26 it is obvious that the number of cycles needed before failure occurs in a corrosive environment is lower than that in air. In the corrosive environment in certain extreme cases, the endurance limit (the stress level below which failure by fatigue does not occur) is eliminated, so the metal is susceptible to corrosion fatigue at any level of cyclic stress. During corrosion fatigue, usually multiple cracks initiate; whereas in pure fatigue normally only one crack initiates. Corrosion fatigue cracks are usually transgranular (see section 5.17). When a metal or alloy protected by a surface layer is subjected to cyclic stress, the surface layer is destroyed. The environment corrodes the unprotected metal surface, which undergoes further stress during the subsequent cycle. The cyclic action of corrosion and stress propagates corrosion fatigue.

30 Ordinary Fatigue Curve

Stress (ksi)

25

20 15

Corrosion Fatigue In Air In Tap Water

10 5

0 104

105

106

107

108

109

Number of Cycles

FIGURE 5.19 S-N Curve for Corrosion Fatigue.

26

Reproduced with permission from NACE International.

5.17 Stress-corrosion cracking (SCC)

283

If corrosion leads to the formation of pits, these act as stress raisers, accelerating the fatigue further. The rate of corrosion fatigue is higher than the sum of the rates of corrosion and fatigue taking place individually, i.e., corrosion fatigue is a synergistic combination of corrosion and fatigue. Corrosion fatigue may be prevented by reducing stress and by cathodic protection (CP) (see section 9.3). However for metals susceptible to hydrogen embrittlement, the application of CP accelerates corrosion fatigue. Shot-peening (inducing compressive stresses in the surface layer by bombarding with a steel shot) reduces corrosion fatigue by inducing compressive stresses in the surface. Application of coatings and corrosion inhibitors protects the surface from corrosion but not from fatigue.

5.17 Stress-corrosion cracking (SCC)27–29 Stress-corrosion cracking (SCC) is defined as the brittle fracture of a material (which is usually ductile) under stress in a corrosive environment. SCC is a type of environmentally assisted cracking which normally propagates transgranularly; i.e., the crack progresses across the grain structure (Figure 5.20). This propagation direction is different from intergranular corrosion, in which the corrosion feature follows the grain boundaries. SCC may also propagate intergranularly. Susceptibility to SCC depends on metal-stress environments. For example, stainless steel is susceptible to SCC in a chloride environment but not in ammonia, whereas brass is susceptible to SCC in ammonia but not in chloride environment. Cracks normally initiate after an induction time. The cracks may be single or multiple and branched. Generally, SCC cracks occurs in groups, and they are usually tortuous and branched. Straight cracks generally arise from fatigue. Cracks generally proceed in a direction perpendicular to stress. Normally, the corrosion rate in SCC-susceptible environments is low, and when the corrosion rate is high, susceptibility to SCC is low. However if the corrosion products trap and exert stress, the SCC susceptibility is high when the corrosion rate is high. Increasing temperature in general increases SCC growth. However, if the temperature is too high cracking will not occur; in this case, the rate of general corrosion is too high for a sharp crack to initiate. A crack initiates at the tip of a pit or trench, or other discontinuity on the surface. In order for this to happen, the tip of the discontinuity should be anodic and free from protective layers. Tensile stress ruptures a protective layer, thus facilitating crack initiation. Stress concentration at the tip of the discontinuity (e.g., pit or trench or notch) increases as the radius of the discontinuity decreases. The tip of a growing crack has a smaller radius and higher stress concentration. The high stress results in the plastic deformation of the metal in front of the crack tip. Corrosion may facilitate crack growth, provided that the tip of the crack is anodic, and the side walls of the crack are cathodic. If corrosion products plug the tip of the crack, the crack stops growing (dormant crack). If the grain boundary region is anodic, the SCC crack propagates intergranularly; otherwise it propagates transgranularly. In order for SCC to take place, three elements are needed: a susceptible metal, stress, and a corrosive environment. Further, sufficient exposure time is required to initiate the process. The susceptibility of a metal to SCC depends on its chemical composition, the orientation of grains, the composition and distribution of precipitates, dislocation, and transformation. Grain boundaries are small in the longitudinal direction and they do not link up to form a continuous corrosion path in this direction. On the other hand, grain boundaries are elongated in the transverse direction and they link up to form continuous path in this direction. Table 5.7 presents some overall observations on the

284

CHAPTER 5 Mechanisms

FIGURE 5.20 Photograph Showing the Transgranular Nature of SCC.28,29

susceptibility of materials to SCC, and Table 5.8 provides an overview of the SCC susceptibility of austenitic stainless steel in various refinery environments.30 Materials may be subjected to different forms of stress; common among them are tensile stress, compressive stress, shear stress, and residual stress. Tensile stress pulls apart or elongates adjacent sections of material on either side of a stress plane (Figure 5.21A). Compressive stress is the reverse of tensile stress; it presses adjacent sections of a material on either side of the stress plane against each other (Figure 5.21B). Shear stress slides two adjacent sections of a material across one another (Figure 5.21C). Residual stress exists from fabricating processes including drawing, punching, rolling,

5.17 Stress-corrosion cracking (SCC)

285

Table 5.7 Susceptibility of Materials to SCC Material Pure metals High strength aluminum alloys (2000 and 7000 series) Aluminum alloys

Copper and copper alloys Carbon steel pipelines 18e8 grade stainless steel

Nickel alloys

Titanium alloys

Environment/Stress

Marine environment and in the presence of chloride ions Stressed in the direction of rolling or extrusion (longitudinal direction) Stressed in the transverse direction Ammonia solution Chloride solutions, hot caustic solutions, and polythionic acid (formed by the interaction of H2S, SO2, water, and air) Concentrated caustic solution at temperatures above 200 C and HF acid in the presence of oxygen Organic chlorides above 290 C

Susceptibility Less susceptible More susceptible Less susceptible More susceptible More susceptible Susceptible More susceptible

More susceptible

More susceptible

mismatch, spinning and welding. Residual stress remains in the material unless it is relieved, for example, by annealing or by other heat treatments. Compressive and shear stresses do not cause SCC, but tensile and residual stresses facilitate SCC. Many sources contribute to tensile stress, including applied, thermal, welding, and pressure fluctuations. For some materials a minimum stress level is required for SCC to occur. This minimum stress, commonly known as the threshold stress level, depends on the material and the environment. However, for many materials there is no such minimum threshold stress. Some metals under stress are susceptible to SCC in certain environments, but not in others under the same amount of stress. For example, the presence of chloride ions increases susceptibility to SCC; this is commonly known as chloride SCC. In SCC susceptible environments, the surface layer is ruptured by the stress; on the other hand in environments not susceptible to SCC, the surface layer is strong enough to withstand the stress, or it does not exist at all. The potential difference between the surface layer covered area and the layer-free surface is high enough to drive the crack. Further, a favorable anode-cathode ratio, i.e., a smaller anodic area and a larger cathodic area, is established. The presence of oxygen or other oxidizing species is critical for SCC. In some laboratory experiments, the removal of oxygen stopped cracking, and the introduction of oxygen initiated SCC – indicating that the formation of an oxide (or any other surface) layer is critical for SCC. Cyclic exposure to wet and dry atmospheres increases the severity of SCC in comparison with exposure only to wet atmospheres. This is because the wet cycle forms the surface layer whereas the dry cycle cracks it. SCC may be controlled by selecting materials appropriate for the given environment. For materials with a threshold stress level for SCC to initiate, the susceptibility is low below the threshold stress. The SCC material may be protected with coatings and further by applying CP. External stress may be relieved by reducing the load and internal stress (residual stress) may be reduced by annealing.

Table 5.8 Susceptibility of Austenitic Stainless to SCC in Refinery Units30 Onstream Cracking

Shutdown Cracking

Cracking Service Uncertain

Crude

Hydrosulfurizer

Crude

Hydrosulfurizer

Crude

Hydrosulfurizer

Equipment

Failures

still

and Reformer

Chemical

Miscs.

Still

and Reformer

Chemical

Miscs

Still

and Reformer

Chemical

Miscs

Exchanger

31

2

4

6

7

0

10

0

1

0

1

0

0 0

tubes Piping

9

0

0

2

1

1

4

0

0

0

1

0

Thermowells

9

5

0

0

0

0

3

0

1

0

0

0

0

Bellows

5

1

1

0

2

0

1

0

0

0

0

0

0

Cladding

4

0

0

0

0

0

4

0

0

0

0

0

0

Springs

2

0

1

0

1

0

0

0

0

0

0

0

0

Bubble caps

2

0

1

0

0

0

0

0

1

0

0

0

0

Wire screen

2

0

0

0

0

0

1

1

0

0

0

0

0

Level

1

1

0

0

0

0

0

0

0

0

0

0

0

Channel

1

0

1

0

0

0

0

0

0

0

0

0

0

Stud

1

0

0

0

0

0

1

1

0

0

0

0

0

Flange

1

0

0

0

0

0

0

0

0

0

1

0

0

Shell

1

0

0

0

0

0

0

0

0

0

0

0

0

Bolt

1

0

0

0

0

0

0

0

0

0

0

0

0

controller

Elbow

1

0

0

0

1

0

0

0

0

0

0

0

0

Subtotal

71

9

8

10

12

1

24

1

3

0

3

0

0

Total

71

39

29

3

Note: The alloys that failures included 301, 303, 304, 304L, 309, 316, 321, 347 and alloy 800. Intergranular SCC has occurred primarily in 304, although 321 and 347 may fail intergranularly when improper heat treatments are applied

5.18 The hydrogen effect

Force

287

Force

Stress plane Force

(A) Tensile

(B) Compressive

(C) Shear

FIGURE 5.21 Types of Stresses.31

Environmental factors may be controlled by eliminating the species causing SCC, or by adding chemicals (corrosion inhibitors).

5.18 The hydrogen effect32 The hydrogen effect is caused by the diffusion of atomic hydrogen into the metal. Hydrogen atoms, being small in size, diffuse through the metal lattice, but hydrogen molecules are larger, and so cannot. The primary source of hydrogen atoms is the cathodic reduction reaction (Hþ þ e /H) taking place during corrosion of metals in acidic solution. There are three environments that are primarily responsible for hydrogen effects in ambient temperature corrosion processes: hydrogen sulfide (H2S), hydrogen fluride (HF), and hydrogen cyanide (HCN). Another source of hydrogen atoms are high temperature, high-pressure gaseous environments containing hydrogen gas. Normally the hydrogen atoms produced in the cathodic reaction combine readily to form molecular hydrogen (2H / H2). However, when the recombination reaction is prevented or decreased, the concentration of atomic hydrogen increases. Certain chemicals, including sulfide ions, phosphorous, and arsenic, poison the recombination reaction of atomic hydrogen and hence increase the concentration of atomic hydrogen inside the metal. The presence of atomic hydrogen in the metal or alloy lattice causes several types of damage, which can be broadly classified into hydrogen blistering (HB), hydrogen induced cracking (HIC), hydrogen embrittlement (HE), sulfide stress cracking (SSC), high temperature hydrogen induced cracking (HTHIC), and hydrogen induced disbondment (HID). These terms may sometimes be used

288

CHAPTER 5 Mechanisms

interchangeably and other terms such as hydrogen stress-cracking (HSC) may also be used to identify the hydrogen effect. Table 5.9 presents characteristics of different types of hydrogen effects. In general, hydrogen effects may be prevented by using appropriate materials; by using a protective coating that is impermeable to hydrogen atoms and is resistant in the environment; by using corrosion inhibitors to control the corrosion rate and hence to reduce the production of hydrogen atoms; and by removing poisons that prevent recombination of hydrogen atoms to form hydrogen molecules.

5.18.1 Hydrogen blistering (HB) HB may also be known as soft zone cracking (SZC). Relatively soft steels blister in corrosive environments in which the cathodic reaction is hydrogen ion reduction (Figure 5.22). Normally, the blisters are about one inch in (25.4 mm) diameter, but blisters as large as four feet (1.2 meter) in diameter have been observed. Hydrogen blistering may occur in low-yield strength steel or in steel containing local ‘soft zones’. In the presence of hydrogen, these soft zones may yield and accumulate plastic strain locally, increasing the susceptibility to cracking of an otherwise crack-resistant material. Such soft zones are typically associated with welds in carbon steels.

5.18.2 Hydrogen induced cracking (HIC) HIC occurs in carbon or low-alloy steels when atomic hydrogen diffuses into it and forms molecular hydrogen. Formation of molecular hydrogen may be facilitated by inclusions or trap sites. Therefore HIC can occur in the absence of any stress. The formation of molecular hydrogen internally pressurizes the material and initiates cracking. For this reason, HIC may also be known as hydrogen pressure induced cracking (HPIC). Trap sites causing HIC include impurities, inclusions, and microstructure (e.g. banding) produced by segregation of impurity and alloying elements in the steel. Inclusion significantly influences HIC. During rolling of steel (during fabrication) inclusions are elongated and voids are created, thus increasing the susceptibility to HIC. Soft inclusions (e.g., MnS) are elongated to a higher extent than hard inclusions (Al2O3) (Figure 5.23). For every material there is a minimum threshold hydrogen concentration [(CH )TH] below which the material is not susceptible to HIC (Figure 5.24). The concentration of diffusible hydrogen (CH ) depends on steel chemistry, temperature, solution pH, and the partial pressure of H2S. Sometimes individual cracks in adjacent parallel planes may link up in a step-wise pattern, and this is commonly known as step-wise cracking (SWC) (Figure 5.25). The presence of stress at discrete locations may cause individual ligaments of crack to form in a stacked array. This array normally orients perpendicular to the applied stress. This pattern of SSC is often identified as stress-oriented hydrogen induced cracking (SOHIC) (Figure 5.26) and it mostly forms in the heat-affected zone (e.g., welds).

5.18.3 Hydrogen embrittlement (HE) HE is the loss of ductility and strength due to the entry of atomic hydrogen into the metal lattice. HE causes brittle fracture and HE cracks are always intergranular. Certain metals (e.g., iron, titanium, and nickel) are more susceptible to HE than others (e.g., copper, aluminum, and austenitic stainless steel). Removal of the metal from the source of hydrogen and heat treatment (to about 200 C) restores its mechanical properties. Therefore it is assumed that HE is caused by hydrogen atoms when they do not combine to form hydrogen molecules.

Table 5.9 Types of Hydrogen Effects Types of Hydrogen Effect Effect of Environment Strength of material Hydrogen External stress May also be identified as Other variation

Soft material or soft zone of the materials Molecular form Yes Soft zone cracking (SZC)

Regions of soft zones; mostly in welded regions Affects

Hydrogen Induced Cracking

Hydrogen Embrittlement

High corrosivity Low strength steel

High strength steel

Molecular form No Hydrogen pressure induced cracking (HPIC) Stress-oriented hydrogen induced cracking (SOHIC) Step-wise cracking (SWC) Depends on microstructure Significantly affects • NACE TMO284 • ISO 15156 • EFC 16

Atomic form Yes

Sulfide Stress Cracking Low corrosivity High strength steel (Above Rockwell hardness C22) Atomic form Yes Hydrogen embrittlement

SSC

Perpendicular to external stress Affects

Perpendicular to external stress Affects

• ASTM F1624 • NACE TMO177 • NACE TMO198 • EFC 16 • ISO 15156

• • • •

NACE TMO177 NACE TMO198 EFC 16 ISO 15156

5.18 The hydrogen effect

Crack orientation/ location Non-metallic impurities Standards used to evaluate the effect

Hydrogen Blister

289

290

CHAPTER 5 Mechanisms

FIGURE 5.22 Schematic Diagram of Hydrogen Blistering.33 Reproduced with permission from McGraw-Hill.

Cavity

Hard Inclusion (Al2O3)

Before rolling

Soft Inclusion (MnS)

FIGURE 5.23 Effect of Inclusions on SSC.34

After rolling

5.18 The hydrogen effect

291

FIGURE 5.24 Hydrogen Induced Cracking Susceptible Regions (Y axis is hydrogen concentration).34

FIGURE 5.25 Step-Wise Cracking (SWC).34

HE may be a result of the accumulation of hydrogen near dislocation sites or microvoids. Susceptibility to HE increases as the concentration of atomic hydrogen increases. In certain metals, e.g., titanium, hydrogen reacts to form brittle hydrides, but for other metals, e.g., iron, the exact interaction between hydrogen atoms and the metal is not completely understood. Higher strength materials are more susceptible to HE than lower strength materials. Susceptibility to HE (i.e., loss of ductility) can

292

CHAPTER 5 Mechanisms

FIGURE 5.26 Stress-Oriented Hydrogen Induced Cracking (SOHIC).34

only be detected in slow strain tests, or in a static stress test on a notched coupon, but not in a Charpy impact test (see section 3.2.1d).

5.18.4 Sulfide stress cracking (SSC) SSC became an issue in 1950s in the sour gas fields in Western Canada.35 There were two opinions on the mechanism (stress-corrosion or hydrogen embrittlement) within the committee that was formed to understand this phenomenon. Therefore the term ‘sulfide corrosion cracking’ was coined. At that time, this term implied that the failures were of a spontaneous nature occurring in certain metal equipment items when exposed under stress (internal or external or both) to environments containing H2S. Subsequently the term sulfide stress cracking (SSC) became synonymous with cracking in oil and gas production conditions in the presence of H2S. This committee produced the NACE 1B 163 publication which was forerunner to NACE MRO175/ISO 15151. Both applied stress and yield strength increase susceptibility to SSC. Steels with hardness of Rockwell C22 or higher are susceptible to SSC in sour environments. The steel’s hardness creates internal stress, which increases its susceptibility to SSC. The presence of inclusions initiates and propagates SSC. Most materials are susceptible to SSC at around 90 F (w30 C).

5.18.5 High temperature hydrogen induced cracking (HTHIC) Materials exposed to a hydrogen atmosphere at high temperatures (typically above 430 F (w220 C)) may suffer from HTHIC. At these temperatures, the hydrogen molecule dissociates spontaneously to produce hydrogen atoms.37 The hydrogen atom entering into the steel reacts with carbon, producing methane. This phenomenon is commonly known as the methanation of steel.38 Methane molecules are larger than hydrogen atoms, and hence they cannot diffuse through steel. As a consequence, microfissures form which eventually combine to form cracks. This phenomenon is known as HTHIC. High temperature HIC is cumulative (unlike HE which is reversible by proper treatment). Shorter exposure to a hydrogen environment at high temperature may not result in failure, because there is an incubation period. However, repeated short exposure to hydrogen at high temperatures produces increasing amounts of methane gas within the steel, which ultimately leads to cracking. Therefore the total duration of the exposure to a hydrogen atmosphere is important in determining a material’s susceptibility to HTHIC. High temperature HIC can be avoided by proper material selection and by proper heat treatment. For example, addition of carbide-forming elements (e.g., Cr, Mo, and Nb) reduces the amount of

5.19 Liquid metal cracking (LMC) or liquid metal embrittlement (LME)

293

carbon available to react with hydrogen; thereby reducing susceptibility to HTHIC. Standards providing guidelines to understand HTHIC include: •

API 941, ‘Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants’

5.18.6 Hydrogen induced disbondment (HID) HID, occurs in stainless steel clad carbon steel in the presence of hydrogen at high temperatures and high-pressures, especially in refinery hydrotreating units. This type of failure occurs when molecular hydrogen accumulates at the metallic bond between steel and stainless steel layer. When steel is supersaturated with hydrogen, it flakes or cracks. This phenomenon occurs when the reactor is being shutdown. The most susceptible conditions include concentration of hydrogen in steel exceeding 3 ppm, temperature being lower than 300 F (150 C), tensile strength exceeding 100,000 psi (690 MPa), and wall thickness being higher than 6 inch (150 mm). The internal hydrogen flaking or cracking can be avoided by proper shutdown procedures, i.e., slowly depressurizing the reactor and then slowly cooling it.

5.18.7 Hydrogen grooving Hydrogen grooving normally occurs in units handling sulfuric acid, in situations when the sulfuric acid flow rate is less than 1 feet/s (0.3 m/s). Hydrogen grooving occurs due to a flow pattern that results from the continuous stream of hydrogen bubbles rising up along a vertical or inward sloping carbon steel surface in concentrated sulfuric acid. This causes an accelerated dissolution of the iron sulfate film in the area impacted by the movement of the bubbles. As a result, the corrosion rate increases leading to an enhanced formation of bubbles at that location. At flow rate higher than 1 feet/s (0.3 m/s), the bubbles will not partition to the top; hence hydrogen grooving does not occur.

5.19 Liquid metal cracking (LMC) or liquid metal embrittlement (LME) Metals exposed to molten metals suffer from liquid metal cracking (LMC). LMC is often called liquid metal embrittlement (LME). Copper and nickel alloys are most often affected by mercury; but mercury will cause catastrophic corrosion of aluminum alloys (see section 4.14). Zinc will cause LME in austenitic stainless steels if the metal temperature is above about 1,100 F (600 C). However unlike HE, LME is not reversible. LMC caused by mercury is most frequent because Hg exists in the liquid state at atmospheric pressure and temperature. Mercury (or any other liquid metal) contacts a metal surface and subsequently adsorbs onto the metal surface. The presence of surface layers, e.g., oxide layers, may prevent the adsorption of Hg. Under these conditions the metal is not susceptible to LMC. However, if the surface layers are removed by erosion, abrasion, or any other means, mercury adsorbs on to the metal. The adsorption of mercury breaks the atomic bonds of the metal surface, leading the metal to lose its ductility. If the metal surface with adsorbed mercury is under stress, cracks initiate: the stress level for cracks to initiate on metal surfaces containing adsorbed liquid metal is far lower than the normal yield stress required to initiate cracks. The cracks subsequently propagate along the grain boundary (intergranular cracking), leading to LMC.

294

CHAPTER 5 Mechanisms

Liquid metal cracking may be controlled by minimizing the contact of liquid metal with the metal surface; by altering the metallurgy of metals (e.g., addition of phosphorous to MonelÔ or of lanthanides to steels reduces the susceptibility of these metals to LMC); cladding the solid surface more resistant materials (e.g., ceramic coatings); and reducing the stress level below the level that causes LMC.

5.20 Corrosion under protective coating and corrosion under insulation (CUI) The external surface of much oil and gas underground infrastructure is protected by polymeric coatings and further backed up by cathodic protection (see sections 9.2 and 9.3 for details). When the protective coatings disbond (e.g., polyethylene tape), but do not pass cathodic protection current, corrosion takes place beneath the protective coatings. Similarly, external surfaces of aboveground infrastructure which operates at high temperatures (typically 300 F (150 C)) is protected by thermal insulators. Similar situations can develop beneath insulators. Similar type of corrosion may occur beneath thin film; commonly known as filiform corrosion. The basic mechanism is the same. The metal surface is secluded by the disbonded coating or insulator. Water or other conductive aqueous phase accumulates in the area between the metal surface and the coating or insulator, creating conditions conducive for corrosion. Further, the electrical insulating nature of the coating or insulator does not allow passage of current from CP system, if used. Consequently the corrosion beneath the coating or insulator continues to take place. Corrosion under insulation may be controlled by proper coating selection, by properly preparing the surface before application of coating or insulator, by plugging the point of entry of water, by using impervious insulation materials such as foamed glass, and by using aluminum foils wrapping to prevent chloride SCC under insulation with hot stainless steel piping.

5.21 Stray current corrosion One of the effective methods of controlling external corrosion is the application of CP (see section 9.3 for more details). Stray current corrosion occurs in locations where two or more infrastructures are protected by different power sources. The current from an outside source (commonly known as a stray current) enters the infrastructure (e.g., pipeline) in one area, flows along the pipeline for some distance, and then leaves the pipeline. The location where the current leaves the pipeline undergoes corrosion. Sources of static (non-varying) or dynamic (varying) stray current may include: impressed current cathodic protection (CP) systems on other pipelines, direction current (DC) transit systems, DC mining operations, DC welding operations, and high voltage DC transmission systems (see section 9.3.7 for more discussion of stray current corrosion and strategies to mitigate it).

5.22 Telluric current corrosion39 Telluric current corrosion is a special type of stray current. This results from the interaction of two magnetic fields: the earth’s magnetic field and a magnetic field produced by an electric current above the

5.23 Alternating current (AC) corrosion

295

earth. The magnetic field produced above the earth superimposes on the earth’s own electric field, producing a telluric current. Thus telluric currents result primarily from the geomagnetic field variations produced by electric currents in the ionosphere (i.e., 60 miles (100 km) above the earth’s surface). They are sporadic in nature and are mostly observed near northern and southern magnetic fields. Telluric currents also produce erratic cathodic protection potential surveys. If pipe-to-soil potentials are measured when the telluric current is active, the results will be erratic and inexplicable. Figure 5.27 provides typical rectifier current and pipe-to-soil potential measurements when telluric current is active. A telluric current will affect transmission pipeline corrosion in two ways: • •

It may shift the potential of cathodically protected carbon steel pipeline in the positive direction, i.e., making it an anode. If may shift the corrosion potential in the negative direction, i.e., more negative than 1,200 mV vs. copper-copper sulfate electrode. At this high negative potential hydrogen reduction reaction may take place in acidic solution.

Telluric current is inductive in nature; therefore pipeline coatings cannot shield against it. In fact pipeline coatings may lead to large potential drops when the current flows into the ground. Insulating flanges also produce the same effect. One approach to minimizing the effect is to provide ground connections to let the telluric current flow easily on and off the pipeline without creating large changes in the pipe-to-soil potential.

5.23 Alternating current (AC) corrosion40 Transmission of electric power in AC mode is efficient and is normally used. In DC mode electric charge flows in only one direction, whereas in AC, the direction of flow of electric charge changes periodically. The rate at which AC changes in direction is its frequency. The frequency of transmitting electric power varies in different parts of the world, but the most common values are 50 Hz and 60 Hz. Railway transportation systems may use lower frequencies (typically 16.7 Hz or 25 Hz), whereas offshore, military, and space systems may use higher frequencies (typically 400 Hz). AC corrosion normally occurs when the frequency is less than 130 Hz. An AC source (e.g., electrical transmission cable) may induce corrosion in nearby infrastructure (e.g., pipeline). The corrosion induced by the AC is known as AC corrosion. Oil and gas transmission pipelines sharing a corridor with electrical transmission lines may suffer from AC corrosion. Field experience indicates that AC corrosion does not occur at AC current densities lower than 20 A/m2; it may occur at AC current densities between 20 and 100 A/m2, and definitely occurs at AC current densities higher than 100 A/m2. AC corrosion rates are highest at holidays (discontinuities in the coating) having a surface area of 1–3 cm2. The corrosion rate increases with decreasing AC frequency and increasing chloride ion concentration, and decreases with increasing DC cathodic protection, current density, time, and aeration.40 Figure 5.28 compares the AC flow with direct, variable, and pulsating current flows. The AC current flows in one direction for some time and then it flows in the opposite direction. When this AC is applied to infrastructure, the structure is polarized – first in one direction and then in the opposite direction; i.e., it is polarized equally in the anodic and cathodic directions. During anodic polarization,

296

Magnetic Field (nT)

04/20/2000 12:00

04/21/2000 0:00

04/21/2000 12:00

04/22/2000 0:00

04/23/2000 0:00

By (E-W), nT

04/22/2000 12:00

04/23/2000 12:00

04/24/2000 0:00

04/24/2000 12:00

04/25/2000 0:00

04/25/2000 12:00 Apr.26

04/26/2000 0:00

CHAPTER 5 Mechanisms

Apr.20

12

11

9

10

8

7

6

5

4

3

2

1

100 80 60 40 20 0 -20 -40 -60 -80 -100

Amplifier Current (A) 0 0

-100

-200

-300

-400

-500

-600

-700

-800

-900

-1000 04/20/2000 0:00

Time (Atlantic)

FIGURE 5.27 Effect of Telluric Current on the Cathodic Protection System.39

Pipe Potential wrt ZRE (mV)

Bibliography

297

FIGURE 5.28 Flow of Direct Current (DC) and Alternating Current (AC).

the metal undergoes corrosion; the application of DC cathodic protection decreases the influence of this anodic polarization to some extent. Smaller holidays increase current density and hence increase the corrosion rate. At higher frequencies, insufficient time is available for the metal to polarize and hence the effect of AC decreases. In aerated solutions the corrosion rate is under diffusion control (not charge control – see section 5.2), therefore AC has minimal effect. AC corrosion may be controlled by reducing the AC density; installing another metallic structure (e.g., zinc ribbon) (which will undergo the AC induced corrosion); and increasing DC density (i.e., cathodic protection current density).

5.24 Top-of-the-line corrosion (TLC) Corrosion takes place in locations where a water phase precipitates. Normally, the water phase is present at the bottom of the pipeline, i.e., between 4 and 8 o’clock positions. However, under certain conditions, water condenses between the 10 and 2 o’clock positions in the pipeline and causes corrosion. This type of corrosion is known as top-of-the line (TLC) corrosion, and it typically occurs in sweet, wet-gas pipelines in stratified flow regimes when the gas contains 500 to 3,000 ppm of organic acids (formic acid, acetic acid, propionic acid, and butanoic acid – see section 4.13.1). TLC is sometimes regarded as more serious than traditional bottom-of-the-line corrosion because controlling them with addition of corrosion inhibitor is relatively difficult. It occurs in pipelines within the first few kilometers of the inlet where the temperature drops rapidly. In these locations, the temperature drops below the dew point due to the removal of external insulators or concrete coatings, or due to environmental conditions (river, sea, or cold air). For this reason, TLC is sometimes also known as coldspot corrosion (CPC). TLC normally occurs when the water condensation rate is above 0.15 to 0.25 g/ m2s. It is controlled by restoring external insulators so that the temperature remains above the dew point. If the condensation of water on the top-of-the-line cannot be avoided, then corrosion inhibitors may be injected to control corrosion (see also section 7.4.2).

Bibliography 1. Wagner C, traud wz. electrochem 1938;vol. 44:p.391. 2. Keir James. Experiments and Observations on the Dissolution of Metals in Acids, and Their Precipitations; with an Account of a New Compound Acid Menstruum, Useful in Some Technical Operations of Parting Metals. Philos. Trans. Royal Soc. London 1790;vol. 80:359–84.

298

CHAPTER 5 Mechanisms

3. Walther Hermann Nernst. Die elektromotorische Wirksamkeit der Ionen, Zeitschrift fu¨r physikalische Chemie. Sto¨chiometrie und Verwandtschaftslehre 1889;vol. 4:129–81 (Nernst received 1920 Nobel Prize for developing Nernst Equation). ¨ ber die Polarisation bei kathodischer WasserstoffentwicklungZeitschrift fu¨r physikalische 4. Tafel Julius. U Chemie. Sto¨chiometrie und Verwandtschaftslehre 1905;vol. 50:641–712 (Discovery of Tafel Equation). 5. John Alfred Valentine Butler. Studies in Heterogeneous Equilibria. Part II. The Kinetic Interpretation of the Nernst Theory of Electromotive Force. Trans. Faraday Soc. 1924;vol. 19:729–33 (First paper on Butler-Volmer equation). ¨ ber die Deutung von Korrosionsvorga¨ngen durch U ¨ berlagerung von 6. Wagner Carl, Traud Wilhelm. U ¨ ber die Potentialbildung an Mischelektroden. Zeitschrift fu¨r elektrochemischen Teilvorga¨ngen und U Elektrochemie and angewandte physikalische Chemie 1938;vol. 44:391–402 (First paper on mixed potential theory). 7. Hickling Archie. Studies in Electrode Polarisation. Part IV.-The Automatic Control of the Potential of a Working ElectrodeTransactions of the Faraday Society; 1942. Vol. 38, pp 27–33. 8. Stern Milton, Geary AL. Electrochemical Polarization. I. A Theoretical Analysis of the Shape of the Polarization Curves. J. Electrochem. Soc. 1957;vol. 104:56–63. 9. Dean SW, Grab GD. Corrosion of Carbon Steel by Concentrated Sulphuric Acid. Mater. Perform. 1985;24 (9):p.21–25. 10. Slusser JW, Dean SW, Watkins WR, Goff SP. The Effects of Gas Impurities and Salts on Metal Corrosion: Laboratory Studies, CORROSION 93, Paper #217. Houston, TX: NACE International; 1993. 11. Hoffman JJ, Lin M, Watkins WR, Dean SW. Observation of Metal Dusting Attacks in Fe and Ni Base Alloys in Industrial Syn Gas Environments" CORROSION 2009, Paper #9161. Houston, TX: NACE International; 2009. 12. Dean SW. Caustic Cracking from Potassium Hydroxide in Syngas. Materials Performance 1999;38 (1):73–6. 13. Dean SW, Grab GD. Corrosion of Carbon Steel in Concentrated Sulfuric Acid Service. Materials Performance 1986;25 (7):p.48–52.

References 1. Corrosion Basics – An Introduction: Chapter 2 – Basics of Corrosion. p. 23. Houston, TX: NACE; 1984. ISBN: 0–915567–02–4. 2. Fontana MG, Greene ND. Corrosion Engineering. Chapter 2: Corrosion Principles, p. 7. McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. ISBN: 0–07–021461–1. 3. Lefrou C, Nogucira F, Huet RP, Takenuti H. Chapter 1.02: Electrochemistry. p. 13. In: Cottis B, Graham M, Lindsay R, Lyon S, Richardson T, Scantlebury D, Stott H, editors. Shreir’s Corrosion. Basic Concepts, High Temperature Corrosion, vol. 1. Radarweg 29, 1043, NX Amsterdam, The Netherlands: Elsevier B.V.; 2010. ISBN: 978–0-444–52788–2. 4. ASTM G3. ‘Standard Practice for Conventions Applicable to Electrochemical Measurements in Corrosion Testing’ ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428-2959 USA. 5. Revie RW, Uhlig HH. Corrosion and Corrosion Control: An Introduction to Corrosion Science and Engineering. 4th ed.; 2008. Table 3.2, p. 31, John Wiley & Sons, ISBN: 978–0–471–73279–2. 6. Revie RW, Uhlig HH. Corrosion and Corrosion Control: An Introduction to Corrosion Science and Engineering. 4th ed.; 2008. Figure 5.1, p. 54, John Wiley & Sons, ISBN: 978–0-471–73279–2. 7. Yves J. Reference Electrode: Theory and Practice. Academic Press; 1961. 8. NACE Corrosion Engineer’s Reference Book. 2nd ed., In: Treseder, R.S., Baboian, R., Munger, C.G. (Eds.), page 67, ISBN: 0–915567–67–9.

References

299

9. Papavinasam S. Chapter 3: ‘Electrochemical Polarization Techniques’. In: Yang L, editor. Techniques for Corrosion Monitoring. Woodhead Publishing Limited; 2008. ISBN: 1–84569–187–3, p. 47–85. 10. Fontana MG, Greene ND. Corrosion Engineering. Chapter 9: Modern Theory – Principles, Figure 9.17, p. 314. McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. ISBN: 0–07–021461–1. 11. Fontana MG, Greene ND. Corrosion Engineering. Chapter 9: Modern Theory – Principles, Figure 9.22, p. 319. ISBN: 0–07–021461–1: McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. 12. Fontana MG, Greene ND. Corrosion Engineering. Chapter 9: Modern Theory – Principles, Figure 9.13, p. 310. McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. ISBN: 0–07–021461–1. 13. ASTM G46. Standard Guide for Examination and Evaluation of Pitting Corrosion, Figure 1: Variations in the Cross-Sectional Shape of Pits. ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428-2959 USA. 14. Fleischmann M, Thirsk HR. The Growth of Thin Passivating Layers on Metallic Surfaces. Journal of the Electrochemical Society 1963;110:688. 15. Jones RH, Ricker RE. Stress-Corrosion Cracking. In: Korb LJ, Olson DL, editors. ASM Handbook. Corrosion, vol. 13. ASM International; 1987. Figure 5 (a), p. 148. ISBN: 0–87170–007–7. 16. Roberge P. Erosion-Corrosion. Corrosion Testing Made Easy, Figure 2.4, p. 6, ISBN: 1–57590–173–0. Houston, TX: NACE; 2004. 17. Yamakawa K. Corrosion and Corrosion Resistant Materials in the Oil and Gas Industry. Figure 7, p. 134. Japan National Oil Corporation, TRC Special Publication #7; 1998. ISSN: 0919–6609. 18. Fontana MG, Greene ND. Corrosion Engineering. Chapter 3: Eight Forms of Corrosion, Figure 3.52, p. 89. McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. ISBN: 0–07–021461–1. 19. http://www.metallurgicalviability.com/underdeposit.htm. 2010. Under-deposit CorrosionMetallurgical Viability, Inc. [accessed on Oct.15]. 20. Microbiological degradation of materials – and Methods of protection, European Federation of Corrosion, Number 9; 1992. The institute of Materials, ISBN: 0–901716–02–2, London, England. 21. Microbiologically Influenced Corrosion and Bioddeterioration. In: Dowling NJ, Mittleman MW, Danko JC, editors. Institute for Applied Microbiology. The University of Tennessee, Center for Materials Processing, The Universityh of Tennessee, American Welding Society, Materials Properties Council, and NACE; 1990. ISBN: 0–9629856–0-0. 22. Borenstein SW. Microbiologically Influenced Corrosion Handbook. Figure 1.4, p. 4. Abington, Cambridge, CB1 6AH, England: Woodhead Publishing Limited, Abington Hall; 1994. ISBN: 1–85573–127–4. 23. Beavers JA, Garrity KC. Chapter 4: Criteria for Cathodic Protection. p. 49. In: Bianchetti RL, editor. Peabody’s Control of Pipeline Corrosion. 2nd ed. Houston, TX: NACE; 2001. ISBN: 1J-57590–092–0. 24. Wright IG. High-Temperature Corrosion. In: korb LJ, Olson DL, editors. ASM Handbook. Corrosion, vol. 13; 1987. Figure 37, page 97, ASM International, ISBN: 0–87170–007–7. 25. ASTM C71. ‘Standard Terminology Relating to Refractories’ ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428-2959 USA. 26. Corrosion Basics – An Introduction: Chapter 5 – Localized Corrosion, Figure 5.24, 1984. p. 104, NACE, Houston, TX, ISBN: 0–915567–02–4. 27. Parkins RN. Intergranular and Transgranular Stress Corrosion Cracking of High Pressure Gas Pipelines Similarities and Differences. In: Proceedings of NACE Northern Area Eastern Conference. Ontario, Canada: Ottawa; Oct. 24–27, 1999. p. 1–22. 28. Zheng W, Elboujdaini M, Revie RW. Stress Corrosion Cracking in Pipelines. In: Raja VS, Shoji T, editors. Stress Corrosion Cracking: Theory and Practice. Cambridge CB22 3HJ, UK: Woodhead Publishing in Materials, 80, High Street, Sawston; 2011. ISBN: 978–1-84569–673–3.

300

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29. Zheng W, Chen W. Progress in Understanding SCC of Existing Pipelines and Relevance to the New Pipelines in the Canadian North. Journal 2005 Aug. 15, 2005; (Issue 11) [accessed on 16.02.13.], http://www2.nrcan. gc.ca/PICon/journal/2005. 30. White RA. Materials Selection for Petroleum Refineries and Gathering Facilities. Table 3.1, p. 74, ISBN: 1–57590–032–7. Houston, TX: NACE; 1998. 31. Drawn based on figure in Properties of Materials: Stress, Integrated Publishing, DOE-HDBK-1017/1-93. http://nuclearpowertraining.tpub.com/h1017v1/css/h1017v1_56.htm [accessed on 14.07.13]. 32. NACE 8X194. ‘Materials and Fabrication Practices Pressure Vessels Used in the Wet H2S Refinery Service’ NACE International, Houston, TX. 33. Fontana MG, Greene ND. Corrosion Engineering. Chapter 3: Eight forms of corrosion (Hydrogen damage), Figure 3.75, p. 111. McGraw-Hill Series in Materials Science and Engineering, McGraw-Hill Book Company; 1978. ISBN: 0–07–021461–1. 34. Elboujdaini, M. Corrosion and Corrosion Control Course, MAAE 4906C, Carleton University, Ottawa, Canada, Winter-2005. 35. NACE Technical Practices Committee 1-G on sulfide stress corrosion, Calgary, Western Canada. 36. H2S Corrosion in Oil and Gas Production – A compilation of classic papers. Tuttle RN, Kane RD. NACE; 1981. 37. API 941. ‘Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants’. American Petroleum Institute, 1220 L Street, NW, Washington DC, 20005-4070, USA. 38. White RA. Materials Selection for Petroleum Refineries and Gathering Facilities. Chapter 3: Hydroprocessing, Catalytic Reforming, and Flue Gas, p. 55, ISBN: 1–57590–032–7. Houston, TX: NACE; 1998. 39. Boteler DH. Telluric Currents and Their Effect on Cathodic Protection of Pipelines. Houston, TX: CORROSION 2004, Paper #: 04050, NACE; 2004. 40. Wakelin RG, Gummow RA, Segall SM. AC Corrosion – Case Histories, Test Procedures, and Mitigation. Houston, TX: CORROSION 1998, Paper #: 565, NACE; 1998.

CHAPTER

Modeling – Internal Corrosion

6

6.1 Introduction The primary functions of corrosion professionals are to predict whether a given material is susceptible to a particular type of corrosion in a given environment; to estimate the rate at which the material would corrode in that environment; and to develop, if necessary, mitigation methods to control the corrosion rate in that environment. Chapter 3 discusses materials and their classifications, Chapter 4 describes various environments that may prevail in the oil and gas industry, and Chapter 5 discusses various types of corrosion that might take place. The suitability of various materials for the given environment with respect to all types of corrosion must be evaluated before a particular material is selected. This may be a daunting task. Fortunately, several rules of thumb, models, predictive tools, or guidelines have been developed based on several years of field experience and laboratory experiments. Such predictive tools provide the corrosion professionals with quick answers. But before using such predictive tools, their applicability and ability to the particular material, and to the particular type of corrosion in the given environment should be evaluated. This chapter presents models for predicting hydrogen effects, general corrosion, pitting corrosion, erosion-corrosion, microbiologically influenced corrosion (MIC), high-temperature corrosion, and top-of-the line corrosion (TLC).

6.2 Hydrogen effects One primary criteria for selecting a material to construct an oil and gas industry infrastructure is its ability to withstand the effects of hydrogen (see section 5.18). Many variables influence the effects of hydrogen. No quantitative models are available to accurately predict the various effects of hydrogen. However, based on extensive laboratory testing and field experience, many guidelines have been developed in the form of international standards. Table 6.1 summarizes the standards for evaluating the susceptibility of a material to hydrogen in a given environment. In general, the effects of hydrogen depend on the susceptibility of the material and the severity of the environment. Some quantitative parameters used to predict hydrogen effects are discussed in the following paragraphs. Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00006-6 Copyright Ó 2014 Elsevier Inc. All rights reserved.

301

302

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Table 6.1 Laboratory Methods to Determine the Susceptibility of a Material to the Effect of Hydrogen Type of Hydrogen Effect

Standard

Specific Tests

Remarks

Sulfide stress cracking (SSC) Stress-oriented hydrogen induced cracking (SOHIC)

MRO175/ISO 15156e2) MRO175/ISO 15156e3)) MRO175/ISO 15156e2)

NACE TMO177 EFC Publication 16 NACE TMO177

Samples are stressed (Applied stress). The occurrence of these types of failures is relatively rare and is not well understood. Therefore test methods are not standardized.

Soft-zone cracking (SZC) Step-wise cracking (SWC) Hydrogen induced cracking (HIC)

MRO175/ISO 15156e2)

NACE TMO177

MRO175/ISO 15156e2)

NACE TMO284

MRO175/ISO 15156e2)

NACE TMO284

Samples are not stressed (No applied stress). Samples are not stressed (No applied stress).

)

For carbon steel For CRAs

))

6.2.1 Susceptibility of the material The susceptibility of a given material to hydrogen depends on its hardness and the hydrogen atom concentration within it. Many studies have conclusively indicated carbon steel with more than 22 hardness on Rockwell scale C (HRC) is susceptible to sulfide stress cracking (SSC) or hydrogen induced cracking (HIC). The hardness may be different in various locations (i.e., weld, heat-affected zone, and base material) of the material. In order to withstand hydrogen effects, the hardness in any location of the material should not be above 22 HRC. Hardness may also be reported in other units, such as Vickers (HV) or Brinell (HBW). Factors to convert hardness from one unit to other are available (see Table 3.1).1–3 The hardness requirements of Corrosion-Resistant Alloys (CRAs) are also available.4 In order for HIC to initiate, a minimum hydrogen atom concentration is required in the metal. This is commonly known as the threshold hydrogen atom concentration (CTHo), and it varies from material to material. For HIC-susceptible materials CTHo is low; whereas for resistant material it is high. Thus, the first step in predicting HIC susceptibility is to experimentally determine the hydrogen atom concentration in a metal (CHo). If this is greater than CTHo, the metal will be susceptible to HIC. The principle behind measuring the hydrogen concentration is described in the following paragraphs, and experimental details for determining CHo are described in section 8.2.1. The distribution of hydrogen atoms inside a material is not uniform. The hydrogen concentration at the inner surface is maximum because hydrogen atoms are generated there (assuming that the cathodic reaction occurring at the inner surface is hydrogen reduction). At the outer surface the concentration is closer to zero, because the hydrogen atomic hydrogen will combine at the outer surface to produce molecular hydrogen. It is normally assumed that the concentration varies linearly across the thickness

6.2 Hydrogen effects

303

HYDROGEN ATOM CONCENTRATION CH

CH = C0H CH = 0 CH = ½ C0H

at X = 0 at X = L at X = ½ L

CH

HYDROGEN ATOM CONCENTRATION GRADIENT

0

L = Wall thickness X = Distance from internal surface

DISTANCE FROM INTERNAL SURFACE, X

O O

STEEL (CROSS-SECTION)

L

ATMOSPHERE

SOUR ENVIRONMENT EXTERNAL SURFACE

INTERNAL SURFACE

FIGURE 6.1 Hydrogen Atom Concentration Gradient in Material.5 Reproduced with permission from Wiley.

of the material (L) as shown in Figure 6.1.5 To calculate CHo, the diffusion coefficient (D) is required. Several equations are used to calculate the diffusion coefficient:6 L2 6tl

(Eqn. 6.1)

D¼

L2 7:2t1=2

(Eqn. 6.2)

D¼

L2 15:3tH;b

(Eqn. 6.3)

D¼

D¼

"

ktrap L2 : 1 þ Ntrap puntrap 6tl

!#

2

6 :6 41

 ktrap 2 Ntrap CH puntrap 

3

7 h i þ .7  5: ktrap 2 1 þ Ntrap puntrap

(Eqn. 6.4)

where L is the thickness of the specimen (cm), tl is the time at which the permeation rate reaches 63% of the steady state rate, t1/2 is half-life time for hydrogen diffusion to reach steady state, tH,b is the breakthrough time, CH is the concentration of lattice-dissolved hydrogen, Ntrap is the concentration of traps in steel, ktrap is the kinetic parameter for the trapping reaction, and puntrap is the kinetic parameter for the untrapping reaction. Equation 6.4 reduces to Eqn. 6.1 when hydrogen trapping does not occur (i.e., when Ntrap ¼ 0 or ktrap/puntrap ¼ 0).

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The hydrogen atom concentration in a material is determined by measuring the permeation current density (Imax) as: imax :L (Eqn. 6.5) DF where imax is the peak current density; F is the Faraday constant (96,487 C/mol), and D is calculated using one of Eqns.6.1 through 6.4. Section 8.2.1 describes the apparatus and procedure for measuring imax. CH o ¼

6.2.2 Severity of the environment The severity of the environment with respect to SSC in carbon steel depends on the H2S partial pressure and in situ pH, and for CRAs it depends on the H2S partial pressure, in situ pH, chloride and sulfur concentrations, and temperature. Figure 6.2 provides the relationship between H2S partial pressure and in situ pH with respect to SSC resistant of carbon steel.7 The in situ pH is relatively difficult to measure; therefore, empirical correlations and equations are used to predict it. Figures 6.3 through 6.7 provide in situ pH as a function of partial pressure of H2S, partial pressure of CO2, temperature, bicarbonate, and calcium ions.8–12 Equation 6.6 provides in situ pH as a function of partial pressure of H2S, partial pressure of CO2, temperature, and bicarbonate, ion concentrations (see sections 4.12 and 6.3.1).13

FIGURE 6.2 Correlation between H2S Partial Pressure and in Situ pH with Respect to SSC Resistance of Carbon Steel.7 (X axis is H2S partial pressure in kilopascals and Y axis is in situ pH; 0 region 0 (No SSC), 1 SSC region 1, 2 SSC region 2, and 3 SSC region 3). Reproduced with permission from NACE International.

6.3 General corrosion of carbon steel

305

FIGURE 6.3 Effect of Partial Pressures of H2S and CO2 on in Situ pH.8 (1 at 20 C and 2 at 100 C). Reproduced with permission from NACE International.

pH ¼ Constant

logðpH2 S þ pCO2 Þ þ log½HCO3 Š

(Eqn. 6.6)

where [HCO3 ] is the concentration of bicarbonate ion, and pH2S is the partial pressure of H2S, and pCO2 is the partial pressure of CO2. The value of the constant depends on temperature and units used in the equation.

6.3 General corrosion of carbon steel Once the material is selected (as per section 6.2), its corrosion characteristics in the given environment should be determined. Internal corrosion of carbon and low alloy steels caused by CO2 and H2S is a major threat. An industry standard approach for assessing the risk of internal corrosion does not exist at the present time, although some guidelines are provided by the following standards: • •

NACE Standard Practice SP0106, ‘Control of Internal Corrosion in Steel Pipelines and Piping Systems’ NACE Standard Practice SP0206, ‘Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)’

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FIGURE 6.4 Combined Effects of Partial Pressures of H2S and CO2 and Bicarbonate Ions on in Situ pH.9 (1 is at 0 meq/L of HCO3 ; 2 is at 0.1 meq/L of HCO3 ; 3 is at 1 meq/L of HCO3 ; 4 is at 10 meq/L of HCO3 ; 5 is at 100 meq/L of HCO3 ; 6 is at 100 C; and 7 is at 20 C). Reproduced with permission from NACE International.

• • • •

NACE Standard Practice SP0110, ‘Wet Gas Internal Corrosion Methodology for Pipelines’ NACE Standard Practice SP 0208, ‘Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines’ CAPP Best Management Practice 2009–13, ‘Mitigation of Internal Corrosion in Sour Gas Pipeline Systems’, June 2009 CAPP Best Management Practice 2009–14, ‘Mitigation of Internal Corrosion in Sweet Gas Pipeline Systems’, June 2009.

Several models have been developed, which differ considerably in terms of parameters considered (partial pressure of CO2, partial pressure of H2S, temperature, flow rate, total pressure, chloride ion, acetic acid, oil type, and gas type), approach (empirical, mechanistic, and simulation), and the influencing factors that are considered (surface layers: FeCO3, FeS, Fe3C, and Fe3O4).14–17 As a consequence of these variations, the numerical corrosion rates predicted by the various models can differ considerably, even though most agree with one another on the influence of a particular variable on the corrosion rate. The characteristics of some recognized models are described in the following paragraphs.

6.3 General corrosion of carbon steel

307

FIGURE 6.5 Combined Effects of Partial Pressures of H2S and CO2 and Calcium Carbonate Ion on in Situ pH at 20 C.10 (1 is at 1,000 meq/L of Ca2þ; 2 is at 100 meq/L of Ca2þ; 3 is at 10 meq/L of Ca2þ; 4 is at 10 meq/L of HCO3 ; 5 is at 30 meq/L of HCO3 ; 6 is at 100 meq/L of HCO3 ; In 7 Ca2þ < HCO3 ; In 8 Ca2þ ¼ HCO3 ; In 9, Ca2þ > HCO3 ). Reproduced with permission from NACE International.

6.3.1 The de Waard-Milliams models18–21 de Waard and Milliams developed the first and most frequently referenced model to predict sweet corrosion. During the early 1970s, failures in pipelines transporting wet natural gas containing CO2 prompted them to investigate the corrosivity of carbonic acid. Assuming the cathodic reduction of hydrogen is the rate determining step, they correlated the corrosion current (Icorr) with pH as: logIcorr ¼

ADM :pH þ BDM

(Eqn. 6.7)

where ADM and BDM are de Waard and Milliams constants. Based on two sets of laboratory experiments conducted at CO2 saturated (Table 6.2 presents the experimental conditions) they found the value of ADM as 1.3 and consequently, rewritten the Eqn. 6.7 (Eqn. 6.8): logicorr ¼

1:3:pH þ BDM

(Eqn. 6.8)

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CHAPTER 6 Modeling – Internal Corrosion

FIGURE 6.6 Combined Effects of Partial Pressures of H2S and CO2 and Calcium Carbonate Ion on in Situ pH at 60 C.11 (1 is at 1,000 meq/L of Ca2þ; 2 is at 100 meq/L of Ca2þ; 3 is at 10 meq/L of Ca2þ; 4 is at 10 meq/L of HCO3 ; 5 is at 30 meq/L of HCO3 ; 6 is at 100 meq/L of HCO3 ; In 7 Ca2þ < HCO3 ; In 8 Ca2þ ¼ HCO3 ; In 9, Ca2þ > HCO3 ). Reproduced with permission from NACE International.

Based on the variation in temperature, they found linear relationship between pH and temperature for sweet system to be (Eqn. 6.9):   (Eqn. 6.9) pH pCO2 ¼ 1 ¼ 4:17  10 3 T þ 371

They observed that a black layer covered some samples under stagnant conditions at temperatures above 100 F (40 C), and consequently the corrosion rate decreased to a low value. Under flowing conditions, they observed this effect above 140 F (60 C). They explained their findings by proposing the cathodic reduction of carbonic acid (Eqn. 6.10), rather than the direction reduction of hydrogen ions: H2 CO3 þ e /H þ HCO3

(Eqn. 6.10)

Based on these results they developed a nomogram (Figure 6.8), which has gained wide acceptance as the starting point for predicting the corrosion rate of carbon steel in sweet environment.

6.3 General corrosion of carbon steel

309

FIGURE 6.7 Combined Effects of Partial Pressures of H2S and CO2 and Calcium Carbonate Ion on in Situ pH at 100 C (See Fig. 6.6 for Description of 1 through 9). Reproduced with permission from NACE International.

Table 6.2 Experimental Conditions of the Original de Waard and Milliams Model18 Conditions

Short-Term Experiment

Long-Term Experiment

Specimen

Polished X52 carbon steel bar (length 45 mm and diameter 6 mm) 0.1% NaCl saturated with mixture of CO2 and specially purified oxygen-free N2 1 liter Glass 1 m/s Linear polarization resistance (LPR) method 1 Room to 90

Grit-blasted X52 carbon steel

Environment

Solution volume Container Velocity Corrosion rate measurement Duration, days Temperature,  C

0.1% NaCl saturated with mixture of CO2 and specially purified oxygen-free N2 Autoclave Mass loss and LPR 7 Room to 90

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CHAPTER 6 Modeling – Internal Corrosion

Temperature ºC 140 130 120 110 100 90 80 70 60

CO2 pressure 10 bar Scale Factor 0.1 20 1

1

10

1

50 40

0.1

Example: 30 0.2 bar CO2 at 120ºC gives 10 × 0.7 = 7 mm/y

0.1

20 10

0.02

0

FIGURE 6.8 Nomogram to Predict Sweet Corrosion.

0.01

18–21

Reproduced with permission from NACE International.

Subsequently they derived a simple equation to predict the corrosion rate (Ccorr) in sweet systems as (Eqn. 6.11): logCcorr ¼ 5:8

  1710 þ 0:671:log pCO2 T

(Eqn. 6.11)

where T is temperature and pCO2 is the partial pressure of CO2. They further simplified the nomogram and included a ‘scale correction’ factor to account for the decrease of corrosion rate due to the formation of surface layer (Figure 6.8). Their co-workers subsequently modified the basic model to include many other effects; as described in the following paragraphs.

6.3.1a Effect of total pressure The increase in corrosion rate with increasing pressure was accounted for by multiplying the corrosion rate predicted by Eqn. 6.11 by a factor based on fugacity of the gas (Fg) as shown in (Eqn. 6.12):   1:4 P (Eqn. 6.12) logFg ¼ 0:67 0:0031 T where P is the operating pressure and T is the temperature.

6.3.1b Effect of surface layer The precipitation of FeCO3 (or Fe3O4) in itself does not necessarily result in the formation of a protective layer. At lower temperatures (typically lower than 140 F (60 C)) the layer has a smudge-like appearance

6.3 General corrosion of carbon steel

311

and is easily removed by flowing liquids. At higher temperatures, the layer is different in texture and is more protective. The effect of surface layers is accounted for by multiplying the corrosion rate predicted by Eqn. 6.11 by a factor Fscale calculated as given in (Eqn. 6.13): logFscale ¼

2400 T

where FCO2 is the fugacity of carbon dioxide.

  0:6log fCO2

6:7

(Eqn. 6.13)

6.3.1c Effect of temperature The temperature at which the corrosion rate starts to decrease due to the formation of protective layers is defined as the scaling temperature. The scaling temperature depends on flow rate; a higher flow rate will result in a higher scaling temperature. The scaling temperature, Tscale, is predicted by Eqn. 6.14 Tscale ¼

2400 6:7 þ 0:6logð fCO2 Þ

(Eqn. 6.14)

Figure 6.9 presents the variation of scaling temperature with CO2 partial pressure; the scaling temperatures appear as sharp peaks (Y axis: Corrosion rate, mm/y).

6.3.1d Effect of velocity The protective surface layer can be removed by flowing fluid. For wet gas transport at a superficial gas velocity of 20 m/s (66 feet/s) the protective surface layers are completely removed, i.e., at that velocity the corrosion rate continues to increase with increasing temperature.

14 12 10 8 3

6

1 0.1 bar CO2

0.3

4 2 0 20

40

60

80

100

120

140

Temperature, ºC

FIGURE 6.9 Variation of Scaling Temperature with CO2 Partial Pressure.18–22 Reproduced with permission from NACE International.

312

CHAPTER 6 Modeling – Internal Corrosion

6.3.1e Effect of hydrocarbon The presence of crude oil has a beneficial effect on corrosion. The steel is assumed to be wetted with oil if the water is entrained in the crude. Such situation occurs when the flow rate is 1 m/s or higher, and if the water cut is below 30%. At flow rates lower than 1 m/s and water cut higher than 30%, water drops out. It is also assumed that light hydrocarbon condensates (for example, natural gas liquids) do not offer any protection regardless of the water content.

6.3.1f Effect of glycol Glycol is often added to wet gas pipelines to prevent the formation of hydrates. Monoethylene glycol (MEG), diethylene glycol (DEG), and triethylene-glycol (TEG) are used for this purpose. The glycol reduces corrosion rate by absorbing water from the gas phase. To correct corrosion rate for the effect of glycol, it is multiplied by a glycol factor, Fglyc (Eqn. 6.15):   logFglyc ¼ aglyc :log Wglyc 2aglyc (Eqn. 6.15)

where Wglyc is the amount of glycol and aglyc is a constant. A value of 1.6 is commonly used for aglyc for most glycols.

6.3.1g Effect of flow velocity In the earlier versions of the model, the only influences of fluid velocity taken into account were its effect on crude and water separation, and on protective corrosion product layers. When these effects were excluded, there was no significant effect of liquid flow velocity on CO2 corrosion rate; i.e., the corrosion reaction appeared to be activation-controlled (see section 5.2). However, the observed corrosion rates in some cases were about twice the rate predicted. With increasingly turbulent flow, more reactive species will reach the surface; consequently, the corrosion rate will become flow-independent. Under this condition it is assumed that the actual corrosion rates can be approximately twice as high as that originally predicted.

6.3.1h Effect of microstructure Cementite (Fe3C) accelerates corrosion rate (see section 4.5.3); this effect is more pronounced when it forms a coherent network on the surface. In normalized steels, cementite forms a coherent network, whereas in tempered martensite it does not. Therefore cementite affects the corrosion rate of normalized steel but not that of tempered steel. In general, the corrosion rate of carbon steel decreases with increase in chromium content due to the formation of protective chromium oxide. However, when chromium combines with carbon to form chromium carbide, the beneficial effect of chromium is lost. It should be noted that the influence of microstructure of various low alloy steels predicted by this model only applies to conditions in which protective films do not form. Furthermore, the development of a carbide network on the surface of normalized steel is a time-dependent process; hence the predicted rate depends on whether the network has been established or not.

6.3.2 The Srinivasan model22 The de Waard and Milliams model presented in the nomogram form can be used to understand the influence of partial pressure of CO2, temperature, and surface layers. But the influence of other factors

6.3 General corrosion of carbon steel

313

cannot be determined in a user friendly way using the nomogram. With the advancement of computer technology and the application of a user-friendly interface, software products have been developed. The first successful software to predict internal corrosion in oil and gas production environments was developed by Srinivasan et al. The characteristics of Srinivasan’s model are provided in the following paragraphs. The Srinivasan model is derived from principles established by de Waard-Milliams relationship for CO2 corrosion. The Srinivasan model first predicts in situ pH as a function of acid gas partial pressures, bicarbonates and temperature and then superimposes several other effects as shown in Figure 6.10. The effects considered in the first version of the model included the surface layer, H2S partial pressure, temperature, chloride, bicarbonate, gas-to-oil ratio, velocity, oil-gas-water ratio, aeration, and sulfur.

FIGURE 6.10 Flow Chart of Srinivasan’s Model.22 Reproduced with permission from NACE International.

314

CHAPTER 6 Modeling – Internal Corrosion

The following sections discuss the effects of these parameters on corrosivity, and provide information describing why it is critical to examine the parameter interactions prior to capturing the synergistic effects of these parameters on corrosion.

6.3.2a Effect of pH The following assumptions have been made with respect to the effects of pH and CO2. The CO2 corrosion mechanism is dissimilar to that of strong acids like HCl, by being much more severe at the same pH; the presence of higher concentrations of acid gases lowers the pH and consequently increases the corrosion rate; the presence of buffering chemicals maintains a higher pH and hence decreases the corrosion rate, even in the presence of higher concentrations of acid gases; and it is more meaningful to determine the effective CO2 partial pressure from the system pH. The in situ pH is predicted using Eqns. 6.16 and 6.17: At 20 C (68 F) in the absence of bicarbonate ion: pHð1Þ ¼ C1

logðpH2 Sþ pCO2 Þ

and in the presence of bicarbonate ion:      pH 2 ¼ C2 log pH2 Sþ pCO2 þ log HCO3

(Eqn. 6.16)

(Eqn. 6.17)

where C1 and C2 are constants, pH2S and pCO2 are partial pressures in bars and [HCO3 ] is the concentration of bicarbonate ion. The system pH is given by the larger of pH(1) and pH(2). Once the system pH is determined, the effective CO2 partial pressure is determined using Eqn. 6.18:   C1 pH (Eqn. 6.18) log pCO2ðeff Þ ¼ 2 where pCO2(eff) is the effective partial pressure of CO2 and is used in the de Waard and Milliams model to determine an initial corrosion rate.

6.3.2b Effect of surface layer The corrosion rate obtained in section 6.3.2a is modified to account for the formation of a FeCO3 layer (or Fe3O4 at higher temperatures). The correction factor presented in Figure 6.8 is used for this purpose.

6.3.2c Effect of H2S

The effect of H2S adopted in the model is presented in Figures 6.11 and 6.12.23 It is recognized that the effect of H2S depends on its partial pressure. At H2S partial pressures less than 0.01 psi (w 0.07 kPa), CO2 is the dominant corrosive species and the presence of H2S has no significant impact; under this condition, the corrosion rate and surface layer formation are functions of FeCO3. Above the H2S partial pressure of 0.01 psia and when pCO2 to pH2S ratio is greater than 200, an iron carbonate layer can form depending on pH and temperature; once formed as intact layer, it can mitigate corrosion. When the ratio of pCO2 to pH2S ratio is less than 200, there is a preferential formation of a iron sulfide layer when compared to FeCO3. This iron sulfide layer is protective at temperatures between 60 and 120 C (140 and 250 F). At temperatures below 60 C (140 F) and above 120 C (250 F), H2S increases the corrosion rate because FeS is not stable under these conditions, and, furthermore, the iron sulfide layer does not allow the formation of FeCO3.

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FIGURE 6.11 Effect of Acid Gases on the Corrosion Rate of Carbon Steel.22,23 Reproduced with permission from NACE International.

FIGURE 6.12 Effect of H2S and Temperature on the Corrosion Rate of Pure Iron.22,23 Reproduced with permission from NACE International.

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6.3.2d Effect of temperature In CO2 dominated systems (pCO2/pH2S is greater than 200) the variation of corrosion rates with temperature is assumed to follow the trend presented in Figure 6.9. In H2S-dominated systems (pCO2/ pH2S is less than 200) it is assumed that the iron sulfide is protective up to 120 C (250 F) and above this temperature localized corrosion may occur.

6.3.2e Effect of chloride ion In de-aerated environments, the corrosion rate increases with increasing chloride ion concentration in the range 10,000 ppm to 100,000 ppm. The magnitude of this effect increases with increasing temperature above 60 C (140 F).

6.3.2f Effect of bicarbonate ion High levels of bicarbonates increases the pH and decreases corrosion rates even when the partial pressures of CO2 and H2S are high.

6.3.2g Effect of velocity Fluid flow velocities affect both the composition and extent of corrosion products. Typically, velocities higher than 4 m/s (13 feet/s) remove surface layers mechanically. Figure 6.13 presents the corrosion rate as a function of flow velocity and temperature.24 In multiphase (that is, gas, water, liquid hydrocarbon) production, the flow rate influences the corrosion rate of steel in two ways: by flow behavior and flow regime. Figure 6.14 presents the effect of flow rate on the corrosion rate.25 Velocities lower than 1 m/s (3.3 feet/s) are considered static. Under these conditions, corrosion rates can be higher than those observed under moderately flowing conditions. This occurs because under static conditions, there is no natural turbulence to assist the mixing and dispersion of protective liquid hydrocarbons or inhibitor species in the aqueous phase. Additionally, corrosion products and other deposits can settle out of the liquid phase to promote crevice attack and underdeposit corrosion.

FIGURE 6.13 Effect of Velocity on Corrosion Rate of Carbon Steel.24 Reproduced with permission from NACE International.

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FIGURE 6.14 Effect of Flow on the Corrosion Rate.25 Reproduced with permission from NACE International.

Between 1 and 3 m/s, the flow effect is considered as moderate. It is assumed that stratified conditions generally still exist. However, the increased flow promotes a sweeping away of some deposits and increasing agitation and mixing. As can be seen from Figure 6.14, the corrosion rates of steel in chemically inhibited fluids increase only slightly between flow rates between 3 and 10 m/s (10 and 33 feet/s). This is attributed to the mixing of the hydrocarbon and aqueous phases. At 5 m/s (16 feet/s), the corrosion rates increase with increasing velocity. Above about (10 m/s or 33 feet/s) (Figure 6.14), the corrosion rates of carbon steel even in inhibited solutions start to increase due to the removal of protective surface films by the high velocity flow.

6.3.2h Effect of oil-gas-water ratio The model classifies the systems as oil-dominated or gas-dominated on the basis of the gas/oil ratio (GOR) of the production environment.

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FIGURE 6.15 Effect of Acid Number on Crude Oil Wettability.26,27 (y Secondary Axis is Interfacial Tension). Reproduced with permission from NACE International.

If the GOR is less than 890 m3/m3 (5000 scf/bbl), the corrosion rate is low due to the inhibiting effect of oil. However, this effect depends on the oil phase being persistent and acting as a barrier between the metal and the corrosive environment. The persistence of the oil phase is a strong factor in providing protection, even in systems with high water cuts. A persistent oil phase on steel surface may protect it from corrosion even in the presence of 45 percent water cut. The relative wettability of the oil phase versus the water phase has a significant effect on corrosion. Metal surfaces that are oil-wet show significantly lower corrosion. The model classifies the oils as persistent, mildly persistent, and not persistent, and corrects the corrosion rate, up to a factor of 4, based on the type of oil phase. The degree of protection, however, can be quantified only as a function of water cut and velocity. The persistence determination is a more complex task and requires knowledge of the kerogen type and hydrocarbon density. It is also important to understand the type of crude oil in terms of the organic compounds. Figure 6.15 correlates the acid number of the crude and oil wettability26 and Figure 6.16 correlates corrosion rate and type of crude oils.27 While the effect of the persistence of the oil medium is significant on corrosion rates, it is even more difficult to quantify precise compositional elements of oil that contribute to wettability and persistent oil film formation. Such quantification may be possible by rigorous laboratory testing of different actual, uncontaminated (that is, de-aerated) production water samples. In oil systems, the water cut determines the level of protection from the hydrocarbon phase. However, at very low water cuts (less than 5%), corrosive severity is low due to the absence of an adequate aqueous medium required to promote the corrosion reaction.

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FIGURE 6.16 Effect of Crude Oil Type on Corrosion Rate.27 Reproduced with permission from NACE International.

In gas-dominated systems, there are two measures to evaluate the availability of the aqueous medium. If the operating temperature is higher than the dew point of the environment, no condensation is possible, and this will give low corrosion rates. Corrosion under condensing conditions (that is, operating temperature less than the dew point) is a function of the rate of condensation and transport of corrosion products from the metal surface. If the water to gas ratio is lower than 11.3 m3 water/Mm3 gas (2 bbl water/MSCF gas), the corrosivity is low.

6.3.2i Effect of aeration The presence of oxygen significantly increases the corrosivity of the environment in production systems. Figure 6.17 presents corrosion rate as a function of oxygen concentration at different temperatures28 and Figure 6.18 presents the effect of flow rate on the corrosion rate of carbon steel in the presence of oxygen.29

6.3.2j Effect of sulfur The influence of elemental sulfur on corrosion rate is similar to that of oxygen since elemental sulfur also acts as a strong oxidizing agent.

6.3.3 The crolet model29,30 Both de Waard and Milliams and Srinivasan developed their models based solely on laboratory data. On the other hand, Crolet et al. developed their model based mainly on operational data and experience

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FIGURE 6.17 Effect of Oxygen Concentration on the Corrosion Rate of Carbon Steel.22,28 Reproduced with permission from NACE International.

FIGURE 6.18 Effect of Flow Rate on Oxygen Corrosion of Carbon Steel.22,29 (Maximum economic corrosion rate is the rate up to which the use of carbon steel is considered economical). Reproduced with permission from NACE International.

from production wells in France. The Crolet model uses CO2 partial pressure, in situ pH, Ca2þ/HCO3 ratio and the free acetic acid as influencing factors for downhole tubular corrosion. It categories downhole tubulars into three classes: low, medium or high, based on the likelihood of perforation within 10 years. Crolet considers three parameters for localized corrosion to occur: contact of water with the metal; potential corrosivity (PC), and favorable conditions for localized corrosion, i.e., active, stable

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anodic sites surrounded by cathodic areas. Based on these parameters, the model categorizes the wells into three types: corrosive (significant corrosion, whose lifetime is under two to three years under current operating conditions), possibly corrosive (in these wells, minor corrosion was experienced in the past and currently the water cut exceeds 20–30%) and non-corrosive (wells for which no corrosion problems have been experienced for the past eight years, in spite of the water cut exceeding 20–30%).

6.3.3a Contact of water with metal At low pressure, contact of water with metal, and hence the probability of corrosion, is low as long as the water cut is lower than 25 to 40%. At high pressure, water contacts the metal surface to initiate corrosion at a water cut of between 0.5 and 5%.

6.3.3b Potential corrosivity Potential corrosivity is the corrosivity of the water, i.e., it is the maximum rate at which uniform corrosion occurs in the medium in the absence of any protective effect. The corrosion rate is low if the PC is low and high if the PC is high. It is recognized that PC can be readily measured in the laboratory using simple techniques, and that a considerable amount of data is already available in the literature. The Crolet model considers the cathodic reaction as the rate determining step, and calculates the corrosion rate using pH, H2CO3, CO2, acetic acid, temperature,and flow rate. Detailed equations are not publicly available, but the PC predicted by the model compares well with the corrosion rate predicted by the de Waard and Milliams model (Figure 6.19).30

PC 0.1

1

10

mm/y 10

10

1

1

1 0.1

0.1 0.1

1

Corrosion rate 10 mm/y

FIGURE 6.19 Comparison of Crolet Model’s ‘Potential Corrosivity’.30 (Y Axis) and de Waard and Milliams Model’s Corrosion Rate (X Axis). Reproduced with permission from NACE International.

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6.3.3c Favorable conditions for localized corrosion It is recognized that the nature and physical chemistry of CO2-containing production waters influence the localized corrosion. The following field data are considered as relevant for predicting favorable conditions for localized corrosion to occur: reservoir data (pressures and temperatures, GOR, and bubble point of the oil); production water (concentrations of all major inorganic cations and anions as well as organic cations (acetates and propionates); gases (partial pressures of CO2 and H2S); production data (well-head temperatures, pressures, and flow rates); type of gas lift; nature of well equipment (diameters and specification of the equipment); corrosion experience of field operators in terms of operating problems attributable to corrosion; damage observed (for example, results of caliper inspections); and time elapsed since attainment of a water cut above 25–30%. Based on the input data, the following parameters are calculated: CO2 partial pressure; in situ pH of the production water; in situ acetic concentration; and potential corrosivity. The Crolet model only predicts a general corrosion rate and only conditions favorable for localized corrosion. Further detailed calculations are not available in the public domain.

6.3.4 The Nesic model31–33 Nesic developed a mechanistic model using electrochemical reactions at the metal surface and the transport process of the species towards that surface. The electrochemical reactions considered in the model involve Hþ, CO2, H2CO3 and Fe2þ. The transport process is based on the mass transfer coefficients of diffusing species. It is assumed that the species are diffusing independently of the diffusion rates of other species. Glass cell experiments involving a rotating cylinder electrode were used to determine the constants required for the model. The model proposes the CO2 corrosion mechanism by the following equations. Dissolution of CO2 in water produces carbonic acid (Eqn. 6.19): (Eqn. 6.19) CO2 þ H2 O4H2 CO3 The carbonic acid (H2CO3) dissociates in two steps, producing a reservoir of hydrogen ions: H2 CO3 4H þ þ HCO3

(Eqn. 6.20)

HCO3 4H þ þ CO3 2

(Eqn. 6.21)

Thus, under acidic pH conditions (pH less than 4), the hydrogen ions produced from the dissociation of carbonic acid undergo cathodic reduction: H þ þ e /H

(Eqn. 6.22)

In the intermediate pH range between 4 and 6, in addition to hydrogen ion reduction, direct reduction of carbonic acid takes place (Eqn. 6.23): (Eqn. 6.23) H2 CO3 þ e /H þ HCO3 This additional cathodic reaction is the reason that carbonic acid is more corrosive than a completely dissociated acid at the same pH. When the concentrations of Fe2þ and CO23 ions exceed the solubility limit, they combine to form a solid iron carbonate surface layer (Eqn. 6.24):  (Eqn. 6.24) Fe2þ þ CO3 2 /FeCO3 s

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It is recognized that the nucleation of a crystalline surface layer is a very difficult process to model mathematically, and that the rate of precipitation is controlled by the crystal growth rate rather than the nucleation rate. Two different equations (Eqns. 6.25 and 6.26) are used to predict the rate of iron carbonate surface layer growth. 2  54:8 123 1 (Eqn. 6.25) RFeCO3 ¼ A:e RT :Ksp S0:5 FeCO3   52:4 119 1 (Eqn. 6.26) RFeCO3 ¼ A:e RT :Ksp ðSFeCO3 1Þ 1 SFeCO 3

where RFeCO3 is the rate of growth of the iron carbonate surface layer, A is the surface area available for precipitation per unit volume, R is the gas constant, T is the temperature, Ksp is the precipitation rate constant, and SFeCO3 is supersaturation rate of iron carbonate. Accordingly, iron carbonate precipitation can occur on the steel surface or within the pores of a porous surface layer. In the porous layer, A is equal to the surface area of the pores per unit volume. In the presence of an iron carbonate layer, the value of surface area ‘A’ is assumed to be 105 m 1. The solubility product, Ksp, for iron carbonate is modeled as a function of temperature, and the ionic strength is based on thermodynamic calculation. When the precipitation rate is much smaller than the corrosion rate (expressed in the same units) a porous and unprotective surface layer forms, and when the precipitation rate is much higher than the corrosion rate, it is very likely that a dense protective iron carbonate surface will form. The model requires the following inputs: temperature, pH, CO2 partial pressure, oxygen concentration, steel composition, and flow geometry (rotating cylinder electrode or pipe). The model prediction agrees with the de Waard and Milliams model. Compared with previous models, it is claimed by Nesic et al. that the present theoretical model gives a much clearer picture of the corrosion mechanisms and of the effect of key parameters. Most of the constants in the model can be determined experimentally and are physically meaningful.

6.3.5 The Mishra model34 The Misha model considers corrosion of steel in CO2 solutions as a chemical reaction-controlled process and derives the corrosion rate equation on the basis of fundamental reaction rate theory. According to the model, the corrosion rate depends on the pH, partial pressure of CO2, and temperature. The model is best represented by Eqn. 6.27:  1:33 n Corrosion:rate ¼ a H þ (Eqn. 6.27) :pCO2 0:67 :e RT

where a is a constant and can be modified based on material, environment, and flow velocity, Hþ is hydrogen ion concentration, pCO2 is the partial pressure of CO2, n is the number of electrons, R is the gas constant, and T is the temperature. Equation 6.27 is similar in form to empirically developed rate equations and, similar to other such equations, it cannot be used when surface layers form.

6.3.6 The Dayalan model35 The Dayalan model is a computational model for predicting the corrosion rates of carbon steel in solutions containing CO2. The model first predicts a uniform corrosion rate in the absence of surface layers on metal, and then extends to conditions where a FeCO3 surface layer forms.

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Table 6.3 Factors Considered in Dayalan’s Computational Corrosion Model in the Absence of aq FeCO3 Surface Layer35 Step I: Formation of Reactants (Chemical Species in the Bulk) CO2 ¼ H2O ¼ H2CO3 H2CO3 ¼Hþ þ HCO3 HCO3 ¼ Hþ þ CO23 Step II: Transportation of Reactants (Bulk to Surface) H2CO3 (bulk) 0 H2CO3 (surface) HCO3 (bulk) 0 HCO3 (surface) Hþ (bulk) 0 Hþ (surface) Step III: Electrochemical Reactions at the Surface Cathodic Reactions 2H2CO3 þ 2e ¼ H2 þ 2HCO3 2HCO3 þ 2e ¼ H2 þ 2CO32 2Hþ þ 2e ¼ H2 Anodic Reaction Fe ¼ Fe2þ þ 2e Step IV: Transportation of Products (Surface to Bulk) Fe2þ (Surface) 0 Fe2þ (bulk) CO23 (Surface) 0 CO23 (bulk)

The overall CO2 corrosion process is divided into four steps (Table 6.3): dissolution of CO2 in the aqueous solution to form the various reactive species; transportation of these species to the surface of the metal; cathodic and anodic electrochemical reactions on the metal surface; and transportation of the products of the corrosion reaction into the bulk of the solution. At steady state, equilibrium is established between these steps so that the rate of mass transfer of reactants, sum of the rates of cathodic reactions, rate of anodic reaction, and the rate of mass transfer of products are all equal. The inputs required to a calculate corrosion rate are the bulk concentrations and equilibrium constants of the various species taking part in the corrosion reaction; the mass transfer rates (mass transfer coefficients) for transportation of reactants/products and the rates of cathodic and anodic electrochemical reactions (electrochemical reaction rate constants) at the metal surface. The general corrosion rate (without the effect FeCO3 layer) is computed in three steps: computation of the concentrations of various chemical species in the bulk of the solution under the given conditions; computation of the mass transfer coefficients for the required chemical species; and prediction of corrosion rates using the information from the two previous steps. In the presence of a FeCO3 layer it is assumed that only a fraction of the metal surface is available for the anodic reaction, and that the cathodic reactions take place on the surface layer. Consequentially, the factors considered include (Table 6.4): the concentrations of various species at the scale surface, in

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TABLE 6.4 Factors considered in Dayalan’s computational model in the presence of a FeCO3 surface layer35 Step I: Formation of reactants (chemical species in the bulk) CO2 þ H2O ¼ H2CO3 H2CO3 ¼ Hþ þ HCO3 HCO3 ¼ Hþ þ CO23 Step II: Transportation of reactants (bulk to scale surface) H2CO3 (bulk) / H2CO3 (scale surface) HCO3 (bulk) / HCO3 (scale surface) Hþ (bulk) / Hþ (scale surface) Step III: Transportation of reactants (scale surface to metal surface) H2CO3 (scale surface) / H2CO3 (metal surface) HCO3 (scale surface) / HCO3 (metal surface) Hþ (scale surface) / Hþ (metal surface) Step IV: Electrochemical reactions at the scale surface 2H2CO3 þ 2e ¼ H2 þ 2HCO3 2HCO3 þ 2e ¼ H2 þ 2CO23 2Hþ þ 2e ¼ H2 Step V: Electrochemical reactions at the metal surface Cathodic reactions 2H2CO3 þ 2e ¼ H2 þ 2HCO3 2HCO3 þ 2e ¼ H2 þ 2CO23 2Hþ þ 2e ¼ H2 Anodic reactions Fe ¼ Fe2þ þ 2e Step VI: Transportation of products (metal surface of scale surface) Fe2þ (metal surface) / Fe2þ (scale surface) CO23 (metal surface) / CO23 (scale surface) Step VII: Transportation of products (scale surface to bulk) Fe2þ (scale surface) Fe2þ (bulk) CO23 (scale surface) CO23 (bulk)

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addition to their concentrations at the metal surface; mass transfer processes for reactants and products between the metal surface and the layer surface; additional mass transfer processes through scale; area of the surface available for anodic and cathodic reactions; cathodic electrochemical reactions on the scale surface; kinetics of cathodic reactions on the surface of the scale; and anodic reactions on the metal surface. In a steady state, equilibrium is established between these steps, so that the rate of mass transfer of the reactants (from bulk to scale surface), the sum of the rates of cathodic reactions (on metal surface and scale surface), the rate of anodic reaction, and the rate of mass transfer of products (from metal surface to bulk) are all equal. The equations are computationally solved by an iterative approach in two steps. First the corrosion rate is calculated assuming that there is no surface layer on the metal; i.e., the fraction of the metal surface that is covered by surface layer is set to zero. Then the surface concentrations of the products Fe2þ and CO23 are calculated from saturation factor (Fsat) and corrosion rate. If the Fsat value is less than 1, the conditions are not right for scale formation. If the Fsat value is greater than 1, then a predetermined value greater than zero is assumed for ASc (fraction of surface covered with layer); which consequently decreases the value for AMe from unity (fraction of surface bare) and the value for the mass transfer coefficients through the layers. The computation then provides new values for Fsat at the metal surface and scale surface, the value at the scale surface being equal to or smaller than that at the metal surface. If the Fsat value at the metal is greater than 1, the calculation is repeated by incrementing the value for ASc (and AMe and mass transfer coefficients through layer). The iteration is repeated until the value of Fsat at the metal surface becomes equal to or slightly less than 1, which corresponds to an equilibrium condition for which further layer growth ceases.

6.3.7 The Anderko model36–38 Anderko computed the corrosion rates of carbon steel in the presence of CO2, H2S, and aqueous brines. The model combines a thermodynamic model (which provides speciation of aqueous system) and an electrochemical model (which provides partial cathodic and anodic processes on the metal surface). The reactions considered in the model include the oxidation of iron and the reduction of hydrogen ions, water, carbonic acid and hydrogen sulfide. The model also includes the formation of iron carbonate and iron sulfide surface layers and their effect on the rate of general corrosion as a function of temperature and solution chemistry. The model has been verified by comparing calculated corrosion rates with laboratory data under conditions that may or may not be conducive to the formation of protective scales. Good agreement between the calculated and experimental corrosion rates has been obtained. The model has been incorporated into a program that makes it possible to analyze the effects of various conditions such as temperature, pressure, solution composition or flow velocity on corrosion rates.

6.3.8 The Oddo model39 The Oddo model accounts for the effects of both iron carbonate surface layer as well as inorganic surface layer (e.g., calcium carbonate scale). It first uses Eqn. 6.28 to account for the influence of FeCO3 layer:   2; 400 0:6log10ðPFCO2 Þ 6:7 Log10 Fscale ¼ (Eqn. 6.28) T

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where Fscale is a scale correction factor with a value between 0 and 1, P is the total pressure, and FCO2 is the fugacity of carbon dioxide. Formation of calcium carbonate (calcite) scales further reduces corrosion. To account for this, another correction factor, the calcite correction factor, Fcalcite, is used. The value of Fcalcite may vary between 0 and 1. It is zero when the saturation index for calcium carbonate deposition (SIc) is greater than 0.4; under this condition, field experience indicates that calcium carbonate scales deposit in a nonturbulent flow condition. The value of Fcalcite is unity when the SIc is less than 0.4. Finally when the value of SIc is between 0.4 and 0.4, Fcalcite is calculated using Eqn. 6.29: 

SIc þ 0:4 (Eqn. 6.29) Fcalcite ¼ 1 0:8 It should be recognized that local turbulence (e.g., presence of a choke, constriction in the pipe, or an elbow), may alter the scaling tendency. Such effects are not included in Eqn.6.29.

6.3.9 The Pots model40–45 The Pots model includes the effect of flow on the CO2 corrosion rate. The model first calculates a limiting corrosion rate (LCR) based on mass transport. The LCR is the theoretical upper limit of the corrosion rate when the rate determining step is the transport of protons as well as carbonic acid in the diffusion and reaction boundary layers. The model then links LCR with corrosion rate when charge transfer is the rate determining step; the corrosion rate under charge transfer conditions is numerically calculated based on chemical and electrochemical reactions. Further it considers the effect of flow and oil in sweeping the water out using Eqn. 6.30: Doil VL z 0:65 (Eqn. 6.30) Fr ¼ DDo w gdpipe where Fr is the Froude number, Doil is the density of oil, DDo-w is the density difference between oil and water, g is the acceleration due to gravity, dpipe is the hydraulic diameter of pipe, and VL is the velocity of the liquid. Several other factors are also considered in the Pots model (Table 6.5). The corrosion rates predicted by this model agree with the de Waard and Milliams model at flow velocities below 1 m/s and nonscaling conditions. At higher flow velocities (typically above 3 m/s), the corrosion rates predicted by this model are lower than those predicted by the de Waard and Milliam model. It is rationalized that under higher flow conditions, the charge transfer kinetics determine the corrosion rate; therefore the rates predicted by this model are more realistic than those predicted only on the basis of the diffusion process. The Pots model further predicts the corrosion rate in a sour environment based on that in the sweet environment (Eqn. 6.31): (Eqn. 6.31) Ccorr:sour ¼ PF:Ccorr:sweet where PF is the pitting factor (Table 6.6), Ccorr.sour is the corrosion rate in the sour environment and Ccorr.sweet is the corrosion rate in the sweet environment.

6.3.10 The Garber model46 The Garber model is based on the analysis and optimization of operating conditions in gas condensate wells. This model predicts corrosion rates based on field operating conditions, temperature and flow rates.

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Table 6.5 Factors Considered in the Pots Model41 Factors

Effect

Corrections

Remarks

Oil

May inhibit corrosion by entraining water

Based on main oil line in Oman

Water-sweep rate

Oil may sweep water out from low areas Glycol or methanol e when used as hydrate inhibitors e also reduces corrosion May increase pitting susceptibility

• Critical velocity water to entrained into oil is between 1 to 1.5 m/s • At these flow rates, below 40% water cut oil may protect the surface • Water may drop out from condensates even at 2.5 m/s • At and above a Froude number of 2, water will be entrained fully in oil • Corrosion rate may decrease by an order of magnitude

Alcohol

Sour

Oxygen in sour environment

Increases corrosion rate

Oxygen in sweet environment

Organic acids

Increase corrosion

See Eqn. 6.30

Similar to de Waard and Milliam’s model

• Pitting factor is a function of chloride ion and elemental sulfur • When elemental sulfur forms, it is assumed that oxygen is present in the system because H2S reacts with oxygen producing sulfur • Treated as a separate mechanism. • Oxygen dissolved in glycol and methanol increases corrosion rate • In the field in the presence of 150 to 700 ppm of organic acids, corrosion rates as high as 5 mm/y were observed

Table 6.6 Values of Pitting Factor (PF) used in Pots Model to Convert Sweet Corrosion Rate into Sour Corrosion Rate FP Chloride, ppm

Scale e No

Scale e Yes

Less than 500 500 to 5,000 Greater than 25,000

0.73 1.1 2.6

1.7 3.8 6.1

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6.4 Pitting corrosion of CRAS CRAs normally do not suffer from general corrosion, but they may be susceptible to pitting corrosion (see section 5.5 for the mechanism of pitting corrosion). Pitting corrosion is the fundamental form of localized corrosion; therefore predicting it provides a method for predicting other forms of localized corrosion. For these reasons, several approaches are used to evaluate the susceptibility of CRAs to pitting corrosion, and these may be broadly classified into: Pitting Resistance Equivalent Number (PREN), standard laboratory methodologies, and electrochemical models.

6.4.1 PREN The Pitting Resistance Equivalent Number (PREN) provides a qualitative method for predicting the susceptibility of CRAs to pitting corrosion. It is calculated on the basis of the chromium (Cr), molybdenum (Mo), tungsten (W), and nitrogen (N) content of an alloy. PREN is commonly used to rank the susceptibility of stainless steel and nickel-base alloys, and is defined as (Eqn. 6.32):47 PREN ¼ Cr þ 3:3ðMo þ 0:5WÞ þ 16N

(Eqn. 6.32)

Larger numbers indicate higher resistance to pitting corrosion. PREN is only considered as a good starting indication of susceptibility to pitting corrosion. The PREN values does not take into account the variation of the surface metallurgy (e.g., duplex stainless steel with varying ferrite and austenite ratios). Other definitions of PREN that are slightly different from Eqn. 6.32 are also available.

6.4.2 Laboratory evaluation In this approach, it is assumed that values of certain parameters can be used to predict the susceptibility of CRAs to pitting corrosion. Laboratory experiments need to be carried out under simulated field conditions. Commonly used such parameters include critical pitting potential (CPP) and critical pitting temperature (CPT). The CPP is the minimum anodic potential at which stable propagating pitting occurs; the more noble this potential is, the less susceptible is the CRA to pitting corrosion. Similarly the CPT is the minimum temperature at which stable propagating pitting occurs. Standards providing procedures to evaluate the susceptibility of CRAs to pitting corrosion and to determine values of CPP and CPT include: • • • • •

ASTM G150, ‘Standard Test Method for Electrochemical Critical Pitting Temperature Testing of Stainless Steel’ ASTM F746, ‘Standard Test Method for Pitting or Crevice Corrosion of Metallic Surgical Implant Materials’ ASTM G61, ‘Standard Test Method for Conducting Cyclic Potentiodynamic Polarization Measurements for Localized Corrosion Susceptibility of Iron-, Nickel-, or Cobalt-based Alloys’ ASTM G100, ‘Standard Test Method for Conducting Cyclic Galvanostaircase Polarization’ ASTM G59, ‘Standard Test Method for Conducting Potentiodynamic Polarization Resistance Measurements’

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6.4.3 Electrochemical models In this approach the pitting corrosion process is sequenced and theoretical equations are derived from electrochemical principles to predict the susceptibility of a metal or alloy to pitting corrosion. As discussed in section 5.5, the surface layer is inherent for CRAs. This air-formed surface layer is usually the oxide of the metal or alloy that is compact, adherent to the metal surface, and protects it from further corrosion. When this surface layer breaks down, the metal or alloy is susceptible to pitting corrosion. This takes place in three distinguishable stages: formation of a passive film on the metal surface; initiation of pits at localized regions on the metal surface where film breakdown occurs; and propagation of pits. It should be noted that very sophisticated and detailed analysis of electrochemical parameters has been carried out, in order to understand pitting corrosion and to develop complex models. Only selected features and basic principles of certain models are presented in this section. Readers are encouraged to review the original papers for detailed calculations, and to view other equally important electrochemical models.48

6.4.3a Passivity models Passive films generally form as bi-layers, with a compact layer adjacent to the metal and an outer layer comprised of a precipitated phase. Since passivity is still observed in the absence of the outer salt layer, passivity is attributed to the compact inner layer. The outer layer may incorporate anions and cations from the solution. The outer layers are often unstable. Although these layers can have a dramatic effect on the inner layers, their influence is not considered in the passivity models. Only selected passivity models are presented in this chapter.

i The Griffin model49 The Griffin model relates the features measured during electrochemical test (i.e., cyclic voltammetry – see section 8.2.2) to the passivation process. The assumptions made in this model are that the oxidative hydrolysis of surface metal atoms produces adsorbed cations, and these cations dissolve away from the electrode surface; passivation occurs when the rate of cation dissolution decreases as the cation coverage increases; and the only feature that distinguishes an isolated adsorbed cation from a cation in the oxide layer is the presence of a full complement of nearest-neighbor cations. The Griffin model defines equations to determine the factors that stabilize the passive layer.

ii The Fleischmann model50 Defining passivation as the consequence of an ordered monomolecular two-dimensional film of a definite chemical phase, Fleischmann proposed that measurement of current at high frequencies at constant potential will yield valuable information about the initial stages of passivation; the passivating film grows two-dimensionally on surfaces; the passivating centers are cylindrical in shape; and the nuclei of the passivating film are distributed over the surface in a completely random manner (i.e., the prediction of passivation should involve a statistical approach) (see Fig. 5.9). The Fleischmann model presents rate constants to determine the probability for the nucleation of the passivation films and their growth.

iii The Sato model51 The Sato model assumes that the surface oxide is an ordered structure and that the rate of its formation can be calculated using concentrations of chemical species in solution, activation energies for passive film formation, and potential gradients across the passivating films. The Sato

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model defines equations to calculate thermodynamic parameters for passive film formation using potentiostatic and galvanostatic tests.

iv The Sarosala model52 The Sarosala model assumes that a solid insulating passive film spreads over the surface from random nuclei, and that the rate of reaction depends on the resistance of the electrolyte in the defects or pores in the passive film. This model provides equations to calculate the thickness of the passivating film and the degree of surface coverage.

v The Macdonald model53 Macdonald advanced a ‘point defect’ model (PDM) to explain the growth and breakdown characteristics of passive films. The assumptions of this model are that whenever the external potential is more noble than the passivation potential, a continuous passive film will form on the surface of a metal; a passive film is an oxide of the metal; the passivation potential is the lowest potential at which the metal can be covered by an oxide film; the passive film contains a high concentration of point defects, metal vacancies, electrons, and holes; the passive films have high electrical fields (106 V/cm); the electric field strength depends on the chemical and electrical characteristics of the film but not on film thickness; and the rate-controlling step is the transport of the vacancies across the film. The Macdonald model provides equations to calculate the passive film thickness.

vi The Ambrose model54 The Ambrose model describes events that take place following rupture of passive film. According to the model, the repassivation process involves film coverage as well as anodic metal dissolution; the rate of repassivation determines the corrosion morphology; and low rates of repassivation lead to considerable active metal dissolution, leading in turn to pit initiation. This model provides equations to calculate the penetration rate of localized corrosion immediately after mechanical passive film rupture.

6.4.3b Initiation models There is much current debate concerning the initiation of pitting corrosion. One approach puts an emphasis on the inherent microscopic defects on the metal surface including grain boundaries, inclusions, and scratches (a priori), whereas the other acknowledges that a non-uniformity on the metal surface and its development to visible dimensions occur after a passive metal is placed in a corrosive medium (a posteriori). The priori approach assumes that heterogeneities are present on the passive metal, whereas the posteriori approach assumes an induced heterogeneity after the metal has been placed into the corrosive medium. In connection with a posteriori assumptions, the significance of stochastic or fluctuation processes have been stressed as the initial step in pitting. Experimental pit initiation results show significantly more scatter than those for other types of corrosion, although the origin of this scatter is still open to discussion.55

i The Okada model56 The Okada model describes a passive metal in a corrosive environment where aggressive ions are transported and adsorbed through the passive film with spatial fluctuations. According to this model, the metal ions initially dissolve uniformly through the passive film, and the resultant passage of current transports halide ions. If this transport is perturbed for some reason, the metal dissolution

332

CHAPTER 6 Modeling – Internal Corrosion

rate changes locally causing variations in the ion flux; if the perturbation increases with time, the passive film is destroyed locally and pits initiate; however, the passive metal dissolves uniformly and no pits initiate; if the perturbation decreases. Increase or decrease in the disturbance determines whether pits initiate or not. Thus, the pit initiation process is a probability event. This model provides equations to calculate the transfer rate of solution species (e.g., chloride) initiating corrosion across the passive film.

ii The Shibata model57 The Shibata model considers pit initiation as a stochastic, i.e., random, process. This model presents several equations to calculate the probability of pit initiation. The model application requires laboratory tests to determine the time needed for a pit to initiate. The data must be fitted to Shibata model equations by numerical or graphic simulation. From the best fit, the influence of film properties, such as thickness, on pit initiation may be inferred.

iii The Baroux model58 The Baroux model analyzes pit initiation in two stages: pit nucleation and pit initiation. Nucleation of pits leads to local breakdown of the passive layer, resulting in direct contact between the base metal and the corrosive solution. The current increases markedly, and some of the dissolved metallic cations are hydrolyzed, resulting in local acidification. If this dissolution current is high enough to maintain sufficient acidity despite the cation dissolution into the bulk solution, the nucleated pits cannot repassivate. Thus, the pit nucleation process is described as a deterministic process characterized by an incubation time. The second stage is known as the stabilization process, and is considered to be probabilistic in nature. The Baroux model provides equations to determine the rate of pit generation.

iv The Salvarezza model59 According to the Salvarezza model, the system becomes irreversible, and stable pits are formed when the current exceeds a given value. On the other hand, if the current does not exceed this value, then the pits will be repassivated. The rate of pit nucleation strongly depends on the properties of the passivation layer and the presence of inclusions at that point. The Salvarezza model provides equations to determine the frequency of nucleation and the probability of pit death.

v The Williams model60 The Williams model is based on the assumptions that the initiation of pitting corrosion requires the production and persistence of gradients of acidity and electrode potential on the surface of the metal; fluctuations in the gradients, leading to the birth and death of events, could arise because of fluctuations in the boundary layer in the liquid at the metal surface; a pit becomes stable when its depth significantly exceeds the thickness of the solution boundary layer; the solution boundary layer has two parts, one part being defined by the roughness of the surface, and the other by the hydrodynamic boundary layer; local acidification would arise as a result of the hydrolysis of metal ions in the solution due to slow dissolution of the passive metal; this passive metal dissolution current varies over the surface because of inhomogeneities in the alloy composition or because of inclusions; a critical local pH is required for the initiation of pitting corrosion; and the nucleation rate depends on the time required to establish this critical local pH. The Williams model provides equations to determine the frequency of nucleation and the probability of pit death.

6.4 Pitting corrosion of CRAS

333

vi The Bertocci model61 The Bertocci model explains that the current transients are due to breakdown. This breakdown causes anodic oxidation of the exposed metal, part of which forms a new passive film. The passive film is weak and more susceptible to further breakdown at least in the initial stage, and for a limited time. This model provides equations to determine the probability of passive layer breakdown.

vii The Oldfield-Sutton model62 Oldfield-Sutton developed a deterministic approach to characterizing localized corrosion. This model was originally developed for the crevice corrosion of stainless steels, but the theoretical treatment can be applied to pitting corrosion and to other metals. According to this model, pitting corrosion occurs in four stages: the environment becomes deoxygenated due to restrictions on the transport of oxygen or other corrosive species; the cathodic reaction switches to the outside of the crevice; the solution inside the crevice becomes sufficiently aggressive for the permanent breakdown of the passive film and the onset of rapid corrosion; and the crevice begins to propagate. This model provides equations to calculate the critical pH at which the corrosion progression is continuous.

viii The Pickering model63,64 The Pickering model assumes that the electric field varies through the surface layer and across its thickness. The electric field within the film may be calculated by solving a boundary value problem. The surface layer breaks down to initiate pits when the electrostatic pressure at the film/solution interface exceeds the compressive film strength. This model provides equations to determine the depth of the pit that is active, and hence is susceptible to propagation.

ix The MacDonald model65,66 MacDonald further developed the deterministic model (see section 6.4.3a.v) to describe the statistical nature of passive film breakdown and pit nucleation. According to the model, a solute-vacancy interaction is needed to account for the effects of minor alloying elements, such as Mo and W, on the pitting resistance of iron-based alloys; the passivity breakdown occurs because of an enhanced flux of cation vacancies from the film/solution interface to the metal/film interface. The excess vacancies arriving at the interface between the metal and the film cannot be absorbed into the metal at a sufficiently high rate; accordingly, the vacancies accumulate to form a vacancy condensate at the metal/film interface, which then grows to a critical size; and the film then collapses locally to form a pit that will continue to grow if conditions are not conducive for repassivation. The MacDonald model presents equations to calculate the surface layer breakdown.

6.4.3c Propagation models The final stage of pitting corrosion is the formation and continuous propagation of stable pits. In propagation models, the growth of pits is treated as deterministic. When the pit becomes sufficiently large, the conditions and processes taking place are closely related to those occurring in crevice corrosion. Several pitting corrosion models are available to predict pit propagation,67–76 but only five pit growth rate models are presented here as illustration. Also detailed equations of these models are not presented; the reader can obtain the information from the references. Characteristics of five pit growth rate models are described in the following paragraphs.

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CHAPTER 6 Modeling – Internal Corrosion

i The Tester model77 The Tester model distinguishes two distinct phases of growth of pits in nickel and stainless steel in concentrated chloride solutions. According to this model, the electrode surface is flush with the surface of the cavity in the early period of dissolution, and a semi-infinite approach has been used to model the diffusion process that causes the electrolyte concentration to increase at the metal surface. After the initial period of saturation of the dissolving cation species at the metal-solution interface, a quasisteady state period of diffusion control commences. The time-dependent depletion of corrosive species can be obtained from this model.

ii The Beck model78 The Beck model proposes that the geometry and migration effects exert opposite and nearly equal influences on the dissolution rate, and that these cancel one another out. Using this model, the depth of pit can be calculated as function of time.

iii The Ateya model79 The Ateya model analyses the effects of ohmic, mass transfer, and concentration polarizations on the current, concentration, and potential profiles inside a pit or crack in iron, nickel, and copper. The model assumes that negative potentials are maintained within the pits so that cathodic reactions occur only at the outer surface; the depth of the pit is greater than its width; and mass transfer in the electrolyte within the pit takes place by molecular diffusion and ionic migration. Using the model the depth or width of pits can be callused as function of time.

iv The Ben Rais model80 The Ben Rais model calculates the current as a function of time for aluminum undergoing pitting corrosion. The model assumes that the bulk solution is very dilute and saturated at the bottom of the pit. However, this model does not consider the effects of supersaturation, pH variation, ionic strength, or metal hydrolysis. From the current, the model predicts pit depth as a function of time.

v The Galvele model81–83 The Galvele mdoel analyzes the transport processes for pitting, and proposes that surface layer breakdown is associated with depletion of hydroxyl ions at the metal-solution interface. The model calculates the change of pH, and from the change in pH predicts pit depth as a function of time.

6.5 Localized pitting corrosion of carbon steel Section 6.3 discusses sweet and sour corrosion of carbon steel models developed to primarily address general corrosion of carbon steel under oil and gas industry operating conditions. Failures of carbon steel in oil and gas industry operational conditions rarely occur due to general corrosion; almost all failures are localized pitting corrosion. Although some models presented in section 6.3 recognize the importance of localized corrosion, they do not adequately describe localized pitting corrosion processes, nor do they present equations to predict them. More importantly these models do not explain why certain locations suffer from pitting corrosion whereas the neighboring areas are intact. The morphology of corrosion features may include circular depressions, usually with tapered and smooth

6.5 Localized pitting corrosion of carbon steel

335

sides (often described as pits); stepped depressions with a flat bottoms and vertical sides (often referred to as mesa corrosion); and formation of silts (sometimes referred to as knife line); and parallel grooves extending in the flow direction (commonly known as flow-induced localized corrosion (FILC)).84 Some characteristics of localized pitting corrosion of carbon steel corrosion include the fact that no intact passive or surface layer is present when the carbon steel material is first placed into service (unlike CRAs in which the passive layer is an integral part of the metal (see section 6.4)); initially carbon steel undergoes uniform or general corrosion, and when sufficient amounts of iron carbonate or iron sulfide surface layer form on the carbon steel, the corrosion rate decreases. (The kinetics of FeS formation is higher than that of FeCO3 formation). The types, morphology, and kinetics of layer formation depend on several operating variables, including flow rates and compositions of oil, gas, and brine, partial pressures of acid gases, total pressure, temperature, microbial activities, and duration of operation (typically the incidences of failure are higher in the initial years of operation (Figure 6.20));85 and the failures are localized and are characterized by loss of metal over discrete areas of the surface, with surrounding areas essentially unaffected or subject to general corrosion. All these observations may be explained by assuming that the corrosion of carbon steel may proceed through a non-classical, localized, pitting corrosion (NCLPC) mechanism. The localized pitting occurring in carbon steel could be non-classical because the primary passive layer that is traditionally associated with pitting corrosion of CRAs (see section 6.4) is not present. But, intact surface layers may form during operation. This layer may be considered as the precipitated outer layer as defined in the classical pitting corrosion mechanism. More importantly, carbon steel undergoes uniform corrosion until

FIGURE 6.20 Failure Statistics of 150 Sour Gas Pipeline Failures between 1998 and 2002 in Alberta, Canada.85 (Note: 55% of failures happened within first three years of operation).

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CHAPTER 6 Modeling – Internal Corrosion

the surface layer is formed. No corrosion occurs if the surface layer completely and permanently covers the entire surface. The addition of corrosion inhibitors and the presence of an oil layer on the metal surface may offer additional protective layer or may reinforce the surface layer. More importantly carbon steel may suffer localized pitting corrosion when the surface layer is incomplete. Table 6.7 presents a general overview of various models used to predict the general and localized corrosion of carbon steel, and a model used to predict the localized pitting corrosion of carbon steel is presented in the following section.

6.5.1 The Papavinasam model86–99 The Papavinasam model first predicts locations which are susceptible to localized pitting corrosion. As discussed in section 5.2, wet corrosion occurring under electrochemical principles requires the presence of water (i.e., a conductive, electrolytic phase). Therefore the locations where water accumulates are those susceptible to corrosion. Flow establishes locations where water accumulates. Standards providing guidelines for determining such locations: • • •

NACE SP0206, ‘Internal Corrosion Direct Assessment Methodology for Pipeline Carrying Normally Dry Natural Gas (DG-ICDA)’ NACE SP0208, ‘Internal Corrosion Direct Assessment Methodology for Liquid Pipelines (Liquids-ICDA)’ NACE SP0110, ‘Internal Corrosion Direct Assessment Methodology for Pipeline Carrying Wet Gas (WG-ICDA)’

The calculations presented in these standards are used in the model under the following conditions: the equation presented in DG-ICDA standard is used when the gas-to-liquid production rate ratio is higher than 5,000, i.e., when:   P:R:gas > 5000 (Eqn. 6.33) P:R:oil þ P:R:water where P.R.gas, P.R.oil, and P.R.water are the production rates of gas, oil, and water respectively. The equations presented in Liquids-ICDA standard are used when 95% of the fluid is oil, i.e., when:   P:R:oil > 0:95 (Eqn. 6.34) P:R:oil þ P:R:water þ P:R:gas Multiphase flow is assumed under conditions where Eqn. 6.33 and 6.34 do not apply. Section 4.2 describes multiphase flow, types of flow regimes, and their characteristics. The information presented in section 4.2 is used to establish locations where water accumulates in multiphase flow. The localized pitting corrosion rate is predicted once the locations of water accumulations are established. The model assumes that the carbon steel surface is susceptible to corrosion only when in contact with water. If the products of corrosion dissolve in the environment then the corrosion rate will be uniform, i.e., general corrosion will occur. If the corrosion product layers deposit and form intact layers that cover the surface (commonly known as surface layers), then the corrosion rate will decrease to a minimum or negligible value. Either of the two extreme conditions, i.e., uniform corrosion or the formation of an intact, compact, and protective layer seldom occurs.

Table 6.7 An Overview Models to Predict Sweet and Sour Corrosion) Srinivasan

Crolet

Nesic

Mishra

Dayalan

Anderko

Oddo

Pots

Garber

Papavinasam

CO2 Partial pressure

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

H2S Partial pressure

No

Yes

Yes

No

No

No

Yes

No

No

No

Yes

Total pressure

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Temperature

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Ph

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Flow rate

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Scale factor

Yes

Yes

Yes

Yes

No

Yes

Yes

Yes

Yes

Yes

Yes

Water wetting

Yes

Yes

Yes

Yes

No

No

No

No

No

No

Yes No

Ca2þ

No

Yes

Yes

No

No

No

No

Yes

Yes

No

Bicarbonate

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Acetic acid

No

No

Yes

Yes

No

No

No

No

No

Yes

Indirect

Field data

No

Yes

Yes

No

No

No

No

Yes

Yes

Yes

Yes

Localized pitting corrosion rate

No

No

Indirect

No

No

No

No

No

Indirect

No

Yes

Unique characteristics

Nomogram

User-friendly Software

Field experience

Mechanistic model

Chemical model

Simulation

Simulation

Effect of inorganic scale

Effect of flow

Field data

Field validation

)

Based on the version presented in the reference cited; later version of the models may have additional features

6.5 Localized pitting corrosion of carbon steel

de Waard and Milliam

Parameters

337

338

CHAPTER 6 Modeling – Internal Corrosion

In practice, the carbon steel becomes susceptible to localized pitting corrosion when the following sequence of events occurs: • •

• • •

Surface layers (single or multi) are formed due to corrosion of carbon steel exposure to the environment; Under the operating conditions of most oil and gas infrastructure either one or the combinations of all of the following three surface layers are possible: iron oxide, iron carbonate, and iron sulfide; Surface layers are removed at localized areas of the steel surface, but the surface layers are left in the rest of the surface; The areas where the protective layer are removed become anodic with respect to the rest of the surface and the surrounding areas become cathodic; and The corrosion reaction taking place at the localized anodic areas is insufficient for complete reformation of the surface layer.

If this sequence of events occurs, then pits initiate, propagate, and can lead to premature failures. The probability and the rate of the localized pitting corrosion depend on the stability of local anode and bulk cathode and their relative areas. Complete removal of the surface layer may be beneficial, because under that condition the anode and cathode ratio are uniformly distributed, resulting in uniform corrosion (as opposed to localized corrosion). Parameters influencing the above sequence, as included in the model, are discussed in the following paragraphs.

6.5.1a Effect of carbon steel grade Minor alloying elements can have a profound effect on the susceptibility of a metal or alloy to localized corrosion, including pitting (see section 4.5.3). In general, if a micro-alloying element that is anodic to carbon steel is present on the steel surface, then there is a greater possibility that the passive layer formed right on top of the micro-alloying element is less stable, producing an area susceptible to pit initiation, i.e., susceptible to the initiation of anodic site, leading to stabilization of smaller local anodic areas surrounded by larger cathodic areas. Although carbon steels differ in composition, their corrosion performance is considered to be similar in the model.100

6.5.1b Effect of oil-water emulsion The probability of corrosion is low if water forms an emulsion with oil. There are two types of emulsion: oil-in-water (O/W) and water-in-oil (W/O). In W/O emulsions, the oil is the continuous phase; therefore its conductivity is low, so it does not sustain corrosion. On the other hand, the probability of corrosion is high in O/W emulsions, because in this type of emulsion, the conductive water is the continuous phase. Procedures discussed in section 4.3 are used to predict the occurrence of this type of emulsion.

6.5.1c Effect of oil wettability Three categories of surface can be established, depending on the affinity of the oil for the carbon steel: an oil-wet surface, a water-wet surface and a mixed-wet surface. Mixed-wet and water-wet surfaces are susceptible to corrosion, but an oil-wet surface is not. The procedures discussed in section 4.3 are used to predict the type of wettability.

6.5.1d Effect of wall shear stress The production rates of oil, water, and gas affect the flow rate. The effect of flow rate is considered in the model using wall shear stress (WSS). The calculation of WSS described in section 4.2 is used for this purpose.

6.5 Localized pitting corrosion of carbon steel

339

6.5.1e Effect of solids Two detrimental effects of solids are considered in the model. In low flow regimes, deposits may form on the surface and produce conditions for underdeposit corrosion. Under moderate flow conditions, solids may abrade the surface leading to a surface profile conducive for pitting. In both situations, the presence of solids increases the probability of localized pitting corrosion. The locations where solids deposit considered in the model are based on the solid deposition model discussed in section 4.2.4. In higher flow regimes, the presence of solids leads to erosion-corrosion. However, the effect of erosion is not included in this model.

6.5.1f Effect of temperature The effect of temperature is manifold. Higher temperatures generally increase the corrosion rate because of the accelerated electrochemical and chemical reactions. However, the rate of precipitation increases with temperature; hence, elevated temperatures reduce the corrosion rate at which protective layers are formed. The influence of temperature on protective layer formation depends on whether the protective layer is physically or chemically adsorbed. For layers that physically adsorb onto the metal surface, protection decreases with increasing temperature, because elevated temperature facilitates desorption. For those layers that chemically adsorb onto the metal surface, the chemical bond strength increases with temperature, and hence, protection increases with temperature up to the point after which thermal degradation of the layer occurs. In addition, increasing temperature increases the diffusivity of both pitting (e.g., chloride ions) and inhibitive species (e.g., corrosion inhibitors, sulfate ions) across the surface layer.

6.5.1g Effect of pressure Pressure exerts two opposing effects. It may increase the corrosion rate if it increases the dissolution of metal, and it may decrease the corrosion rate if it facilitates the formation of intact surface layers.

6.5.1h Effect of H2S partial pressure The acid formed by the dissolution of H2S is about three times weaker than that formed by the dissolution of CO2 (i.e., carbonic acid), but H2S is about three times more soluble than CO2 gas. As a result, the contributions of CO2 and H2S partial pressures in lowering the pH are basically similar. The effect of H2S on pitting corrosion rate depends on the formation and stability of iron sulfides.

6.5.1i Effect of sulfate ion The sulfate ion effect is predominant only in the presence of H2S. Sulfate ions may inhibit localized pitting corrosion by developing a sulfate layer.

6.5.1j Effect of CO2 partial pressure Dissolution of gaseous CO2 leads to the formation of carbonic acid. This weak acid reacts with iron to form iron carbonate. The effect of CO2 on the localized pitting corrosion rate depends on the formation and stability of iron carbonates. With increasing partial pressure of CO2 the surface layers become compact; as a result the localized pitting corrosion rate decreases with CO2 partial pressure.

6.5.1k Effect of bicarbonate ion The bicarbonate ion effect is prominent only in the presence of CO2. Carbon dioxide dissolved in water combines with it to form carbonic acid. The carbonic acid then dissociates into hydrogen and bicarbonate ions. The excess bicarbonate shifts the equilibrium to the left; i.e., it decreases the formation of carbonic acid and thereby decreases the rate of CO2 corrosion. Another effect of bicarbonate is its

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CHAPTER 6 Modeling – Internal Corrosion

buffering action. The bicarbonate buffer can absorb Hþ ions and neutralize the acids produced by CO2 dissolution.

6.5.1l Effect of chloride ion Pitting is most commonly induced by chloride ions. Like other halides, chloride ion is a very potent agent for destroying the surface layers. Therefore an increase in chloride ion normally increases the probability of localized pitting corrosion.

6.5.1m Combined effects Each one of the parameters discussed in sections 6.5.1a through 6.5.1l can individually influence the localized pitting corrosion rates. Extensive laboratory and field tests have been carried out to quantify the individual effect of each of the parameters. Based on the test results, individual rate equations have been developed for each parameter. Table 6.8 presents these equations. The ultimate rate at which the pits will propagate depends on the combined effect of all of the operational parameters. Whereas the individual effect of each of the parameters can be predicted deterministically, determining the combined effect of these variables requires the application of statistical principles, because the driving force for the pitting corrosion is a ‘distributed parameter’. It is assumed that each operational variable produces an individual pit growth rate (resulting in 11 different pitting corrosion rates, Table 6.8) and that the pit growth rate that results from variables that have not been considered (e.g., acetic acid effect) is assumed to be the mean value of these 11 pit growth rates, i.e., PCRadditional. The PCRadditional parameter does not have any effect on the predicted pitting corrosion rate; however, it does increase the uncertainty of the prediction. The feature of this model enables one to include the effects of additional parameters without vastly modifying the model. The actual localized pit growth rate taking place is the ‘distributed function’ that is the mean value of the 12 pit growth rates. The resulting pit growth rate is the rate at which the pits will start to grow in the localized anodic region where the surface layers are removed.

Table 6.8 Effect of Individual Parameter on Localized Pitting Corrosion Rate as per Papavinasam Model Effect of

Localized Pitting Corrosion Rate Equation

Oil

PCRoil ¼

Water

PCRwater ¼ 0:51:W% þ 12:13

Gas

PCRgas ¼ 0:19Wss þ 64

0:33qCAw þ 55

Solid

PCRsolid ¼ 50 þ 25Rsolid

Temperature

PCRtemperature: ¼ 0:57T þ 20

Pressure

PCRpressure: ¼

Partial pressure of H2S

PCRH2S ¼

0:54pH2 S þ 67

Partial pressure of CO2

PCRCO2 ¼

0:63pCO2 þ 74

Concentration of sulfate ion

PCRsulphate: ¼

Concentration of bicarbonate ion

PCRbicarbonate ¼

Concentration of chloride ion

PCRchloride ¼

0:081P þ 88

0:013½SO24 Š þ 57 0:014½HCO3 Š þ 81

0:0007½Cl Š þ 9:2

6.5 Localized pitting corrosion of carbon steel

341

Using the 11 calculated pitting corrosion rates (Table 6.8) and PCRadditional, the mean initial pitting corrosion rate, PCRmean, is calculated using: Eqn.6.35 PCRoil þ PCRwater PCRgas þ PCRsolid þ PCRtemperature þ PCRPressure þ PCRH2 S PCRmean ¼

þ PCRsulphate þ PCRCO2 þ PCRBicarbonate þ PCRChloride þ PCRAddition 12

(Eqn. 6.35) The standard deviation obtained based on Eqn. 6.35 presents uncertainty of the prediction. The magnitude of standard deviation represents the uncertainty in predicting the formation of smaller anodic area surrounded by large cathodic areas (which in turn represents the uncertainty in predicting localized pitting corrosion).

6.5.1n Effect of duration Pitting corrosion does not progress at a constant rate for various reasons, including reformation of the surface layers, local solution saturation, change of corrosion potential, and local increases in pH. Normally the pit growth rate diminishes parabolically as a function of time. If the operating conditions are constant over the years, the average pitting corrosion rate for multiple years is calculated using Eqn.6.36. PCRaverage ¼

PCRmean 1

þ PCR2mean þ PCR3mean þ .:: þ PCRt mean t

(Eqn. 6.36)

where 1, 2, 3 etc. are years 1, 2, 3 etc., respectively and t is the number of years for which the localized pitting corrosion rates is predicted. If the operating conditions change for a particular year the ‘value of ‘t’ is set to unity for that year and the ‘t’ values for subsequent years increase as per Eqn.6.36. Table 6.9 provides the boundary conditions to determine whether the operating conditions change or not.

6.5.1o Effect of flow regime In multiphase flow, the flow regimes may change the corrosion rate based on the duration in which the water phase is in contact with the carbon steel surface. Therefore a correction factor is required. Table 6.10 provides the correction factors to account for flow regimes (see section 4.2.2) on corrosion rate. These correction factors have been established based on the analysis of field data. The average localized pitting corrosion rate predicted by Eqn. 6.36 is further adjusted using the correction factor presented in Table 6.10, to produce PCRnon-mic. This rate includes all non-microbiological activities which influence the localized pitting corrosion rate.

6.5.1p Effect of microbes Section 6.7.6 describes the Sooknah model as used to predict the risk of MIC. To account for MIC, the PCRnon-mic is modified according to Eqn. 6.37:   RMIC (Eqn. 6.37) PCRfinal ¼ PCRnon-mic  50 where PCRfinal is the localized pitting corrosion rate combining the effects of both non-MIC and MIC activities and RMIC is the risk factor due to MIC (see Table 6.11).101–103

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CHAPTER 6 Modeling – Internal Corrosion

Table 6.9 Boundaries to Determine Operating Conditions Changes in the Papavinasam Model Parameter Temperature

Boundaries ( C)

Less than 25 Between 25 and 50 Greater than 50

Pressure (psi)

Less than 100 Between 100 and 500 Greater than 500

H2S (psi)

Less than 2.5 Between 2.5 and 10 Between 10 and 50 Greater than 50

CO2 (psi)

Less than 2.5 Between 2.5 and 10 Between 10 and 30 Between 30 and 100

SO24 (ppm)

Greater than 100 Less than 750 Between 750 and 1000 Between 1000 and 1500 Between 1500 and 2500 Greater than 2500

HCO3 (ppm)

Less than 500 Between 500 and 1000 Between 1000 and 2000 Between 2000 and 4000 Greater than 4000

Cl (ppm)

Less than 10000 Between 10 000 and 20 000 Between 20 000 and 40 000 Between 40 000 and 60 000 Between 60 000 and 80 000 Between 80 000 and 100 000 Between 100 000 and 120 000 Greater than 120 000

6.5 Localized pitting corrosion of carbon steel

343

Table 6.10 Variation of Localized Pitting Corrosion Rate as a Function of Flow Regimes According to the Papavinasam Model Flow Regime Type

PCRnon-mic

Slug Flow Plug Flow Bubble Flow Dispersed Flow Oscillatory Flow Annular Flow Churn Flow Wave Flow Stratified Flow

No Change PCRAverage x PCRAverage x PCRAverage x PCRAverage x PCRAverage x PCRAverage x PCRAverage x PCRAverage x

0.98 0.96 0.94 0.92 0.90 0.88 0.86 0.84

Table 6.11 Risk Scores for MIC According to the Sooknah Model101,102 Influence of Parameter

Range of Parameter

Unit of Parameter

MIC Risk Score

Flow rate

Above 3 2e3 1e2 0e1 Less than 10 10e15 15e45 45e70 70e120 Above 120 Greater than 20 Less than 20

m/s

1 2e12 12e18 18e20 0 1 7e10 7e4 4e1 0 10 2

Temperature

Acid gas partial pressure pH

Langelier Saturation Index (LSI)

Less than 1 1e4 4e9 9e14 Above 14 Less than 6 6e 1

1e1

C

pCO2/pH2S

0 5 10 1 0 10 10e5

Remarks

Only if the H2S content is greater than 10 mol/kmol (1%) by volume.

MIC tendency decreases as the LSI value increases in the negative direction because the tendency of non-MIC increases.

0 Continued

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CHAPTER 6 Modeling – Internal Corrosion

Table 6.11 Risk Scores for MIC According to the Sooknah Model101,102 Continued Influence of Parameter

Range of Parameter

Unit of Parameter

1e8

Total Suspended Solids (TSS)

1e8

Greater than 8 Present

8 10

Present

Total Dissolved Solids (TDS)

Redox potential (Eh) Sulfur

Absent Less than 15,000 15,000e150,000 Greater than 150,000 Less than -15 15eþ150 Greater than 150 Present Absent

MIC Risk Score

0

ppm

mV

Remarks MIC tendency increases as the LSI value increases as more scales are formed. If the flow rate is between 0 to 3 m/s. If the flow rate is above 3 m/s.

0 1 1e10 10 1 1e10 10 10 1

)

The sum of all the MIC risks is 100

6.6 Erosion-corrosion A common guideline used in industry is API RP 14E, which defines the velocity below which erosion does not occur. Although the relevance of the API RP 14E erosion equation has been questioned, it is still extensively used, as no other better tool is currently available. According to API RP 14E, above a certain velocity the gas flow may cause erosion to the pipe wall. The erosion velocity of a compressible fluid is given as Eqn. 6.38:104 a Ue ¼ pffiffiffiffiffiffiffiffiffi (Eqn. 6.38) DGL

where Ue is the erosion velocity, ft/sec, a is a constant with values varying between 75 and 150 (for gas transmission pipeline it is assumed to be 100), and DGL is the gas and liquid mixture density. These values are reduced when solid particles like sand are present. For corrosive fluids, erosion-corrosion may take place at velocities lower than those indicated by the formula. This formula is widely used as a guideline in the oil and gas industry for setting limiting production velocities. In addition to this standard, certain models, based on laboratory testing results, may be used to predict erosion-corrosion; some of which are presented in this section.

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345

6.6.1 The Zhou model105 The Zhou model considers erosion as a mechanical process caused by the impact of solid particles on a metal surface, and corrosion as an electrochemical process caused by the environment. This model considers synergistic interactions between erosion and corrosion. The synergism is defined as the excess mass loss caused by erosion-corrosion over the sum of the masses lost by erosion and corrosion when the two processes act separately. It provides an erosion-corrosion enhancement factor (EFEC) for the combined effects of erosion and corrosion: ECEF ¼ 1 þ 0:11U0:22

(Eqn. 6.39)

where U is the flow rate.

6.6.2 The Nesic model106 The Nesic model considers the effect of erosion when pipes of different diameters join. The effects of erosion-corrosion for a flow through an expanding pipe section are given in Eqns. 6.40 and 6.41:   mp up sina Ucrit  For angle  18:5 : Qerosion ¼ (Eqn. 6.40) 2r  2 mp uP sina Ucrit cos2  : 2 (Eqn. 6.41) For angle  18:5 : Qerosion ¼ 12r sin a where Qerosion is the metal loss rate, m3; mp is the mass of particles; UP is the velocity of particles; Ucrit,E is the critical velocity constant (for erosion to occur) and normally assumed to be 0.668 m/s; rparticle is the density of particles; and a is the impact angle.

6.6.3 The Shadley model107 The Shadley model analyses erosion-corrosion of carbon steel elbows in CO2-containing solutions, and identifies three zones of erosion-corrosion: at low velocities the surface layer is intact and hence the corrosion rate is low; at intermediate velocities, localized points where sand particles impinge deep pits form but the surface layer on the remaining areas of the elbow is intact; and at high velocities sand particles impinge and prevent the formation of a surface layer on the entire surface of the elbow, and the corrosion rate is high but uniform. Table 6.12 presents the boundaries between these three zones.

6.7 Microbiologically influenced corrosion Sections 4.9 and 8.2.4 discuss mechanism and monitoring of MIC respectively. This section presents specific models to predict the occurrence of MIC.

6.7.1 The Checkworks model108,109 The Checkworks model serves as a guide to define and compare the potential for MIC at different locations. This model provides a susceptibility ranking for components or specific sites (e.g., piping, elbows, welds, heat exchanger tubes, tube sheets, pumps, and valves). This model ranks the

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Table 6.12 Boundary Conditions between Different Erosion-Corrosion Zones as Predicted by the Shaldley Model107

pH < 5.5

> 5.5

Boundary between Low Corrosion and Pitting Corrosion Zones

Boundary between Pitting Corrosion and Higher Corrosion Zones

  0:9 4:8dpipe W% 2 0:5375P:R:Sand

  2:5 4:8dpipe W% 2 0:5375P:R:Sand

  7 4:8dpipe W% 2 9:5P:R:Sand

  8:5 4:8dpipe W% 2 9:5P:R:Sand

where dpipe is the pipe diameter, W% is percentage of water; and P.R.Sand is the production rate of sand

susceptibility or extent of the potential for MIC to occur. The ranking ranges from 0 (no susceptibility or very low potential) to 10 (highest susceptibility or greatest potential for occurrence of MIC). The model is mathematically expressed as Eqn. 6.42: RMIC ¼ ðMWF  TF  OF  BF  BD  DiFÞ1=a

(Eqn. 6.42)

where MWF is the materials-water factor accounting for interaction of material and aqueous phase; TF is the temperature factor accounting for the change with temperature; OF is the operation factor accounting for the component being exposed to either continuously, intermittent, or stagnant flow conditions; BF is the biocide factor accounting for the use of biocides to control microbiological growth; BD is the biocide decay factor accounting for loss of effectiveness of biocide with distance from the point of application; DiF is the discontinuity factor accounting for the increased susceptibility at discontinuities in construction such as at welds and crevices; and a is a constant. This model provides a broad framework for field operators to rank and evaluate MIC susceptibility, without quantitatively providing any range of values for various factors.

6.7.2 The union electric model110,111 The Union Electric model provides a relative ranking for the likelihood of the occurrence of MIC. This model evaluates the degree of severity of MIC under the operating conditions of the infrastructure. This model places great significance on the impact of data collection, and emphasizes that the input data are collected from the field. The model is expressed mathematically as Eqn. 6.43:     

9 D ½GallŠ 29 D½SRBŠ þ SF þ VF (Eqn. 6.43) þ 4:86 þ 6 D½ClosŠ þ RMIC ¼ 4:5446 1:5 4:83 where RMIC is the MIC risk (varies between 0–100); D[SRB] is the number of days for sulfate reducing bacteria cultures isolated from samples to turn positive; D[Clos] is the number of days for Clostridia cultures isolated from samples to turn positive; D[Gall] is the number of days for Gallionella cultures

6.7 Microbiologically influenced corrosion

347

isolated from samples to turn positive; SF is the silt factor representing the amount of sludge and silt present at the sampling site (0 ¼ no silt; 1 ¼ moderate amount of silt and 3 ¼ high amount of silt); VF is the visual factor representing a visual estimate of the amount of deposit or tubercle formation at the sampling site (0 ¼ few or none, 1 ¼ moderate soft tubercles/deposit and 3 ¼ many large hard tubercles and deposits); SRB is the sulfate reducing bacteria; CLOS is the Clostridia cultures and GALL is the Gallionella cultures. Based on the RMIC score, the MIC susceptibility is ranked as: low (0 to 25); moderate (26 to 50), high (51 to 75), and very high (76 to 100). However, the rationale for various constants used is not described.

6.7.3 The Lutey model112–115 The Lutey model places significant emphasis on the presence of specific bacteria associated with corrosion. These bacteria are SRB; slime-forming bacteria; metal oxidizing bacteria, such as Gallionella sp. and manganese oxidizing bacteria; and acid producing bacteria, such as Clostridium sp. Although other bacteria may be present and contribute to MIC, only the four bacteria listed are considered as important for MIC. If there are specific data indicating that the MIC potential is related to other types of microorganisms, such as nitrite oxidizing/ammonia producing bacteria or sulfur oxidizing bacteria, such as Thiobacillus sp., these could be added to the input data. Other criteria included in the model are the deposit and fouling factor, sedimentation factor, and materials of construction factor. These factors are considered as important because they influence the environment where the microorganisms exist. According to this model: (Eqn. 6.44) RMIC ¼ MiF þ DFF þ FF þ MF where MiF is the microbiological factor; DFF is the deposit or fouling factor; FF is the flow factor; and MF is the material factor. Table 6.13 presents the scores for various factors as defined by this model. Based on the RMIC score the MIC susceptibility is ranked as: highly likely or severe (above 150), moderate (75 and 150), and low (below 75).

6.7.4 The Pots model41 The Pots model predicts the occurrence of MIC by considering environmental conditions supporting microbial activity and biofilm formation, and operational parameters influencing microbiology. The Pots model calculates the MIC rate using Eqns. 6.45 and 6.46: 0:57 CRMIC ¼ a:fmic

(Eqn. 6.45)

0:57 fmic ¼ fmic:1 :fmic:2 .:fmic:n

(Eqn. 6.46)

where CRMIC is the corrosion rate due to microbiological activity, a is a constant (assumed to be 2 mm/y), and fmic.1, fmic. etc. are factors influencing MIC. Table 6.14 presents values of fmic.

6.7.5 The Maxwell model116 Maxwell and Campbell modified the Pots model to include the influence of SRB cell numbers, SRB growth rates, sulfide production, water content, lesser efficiency of pigging in controlling MIC,

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Table 6.13 Scores for Various Factors as Defined by the Lutey Model112e115 Factor

Value

Score

Remarks

Microbiological

Absent Large amount

0 5

Deposit or biofouling

Absent Large amount Stagnant Greater than 10 ft/sec Between 4 and 10 ft./sec Less than 4 ft./sec Very resistant Very susceptible

0 5 0 1 3 5 1 7

To be scored individually for four types of microbes identified in this model. This model does not quantify the amount of bacteria for different categories of scores. The deposits or biofouling are measured or visually noted.

Flow

Material

This model does not quantify the amount of bacteria for different categories of scores. Both base metal and welds are scored separately.

formation of corrosive biofilm, lag period before biofilm develops, and non-MIC corrosion (i.e., corrosion takes place due to non-microbial activity). The Maxwell model presents a correction factor to be included in the Pots model to account for biofilm development and sulfide production activity. Until a threshold value of the correction factor is reached, it is assumed that MIC does not occur. Once this threshold is reached, the MIC rate can be determined by the Pots model. Details of how to determine the correction factor are described in the model.

6.7.6 The Sooknah model101,102 The Sooknah model establishes boundary conditions in which MIC occurs, and then provides quantitative scores for the risk of MIC under those conditions. All bacteria require a water phase to proliferate. According to this model, in the absence of water MIC does not occur. If any minute amount of water wets the metal surface or deposits attached to the metal surface, then MIC is likely. The likelihood for the occurrence of water-wet surface is predicted according to the Papavinasam model (see section 6.5.1). On a water-wet surface, MIC is likely when the temperature is between 14 and 250 F (-10 and 120 C), organic and inorganic nutrients are available in the medium, and no antifouling procedures are regularly applied. The quantitative MIC risk score is based on nine parameters: temperature, flow rate, pressure, pH, Langemuir Saturation Index (LSI) (see section 6.8.1), total suspended solids (TSS), total dissolved solids (TDS), redox potential (Eh), and sulfur content in solids. Each parameter is assigned a numerical value between 0 and 10, except for the flow rate, which is assigned a numerical value between 0 and 20. Values approaching 0 signify low MIC risk, and values approaching the maximum signify higher MIC risk. The total MIC risk factor is calculated as the sum of scores of all nine contributing

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349

Table 6.14 Values of fmic in Pots MIC Model41 Parameters pH between 5 and 9.5 Total dissolved solids (TDS) less than 60 g/l If TDS greater than 60 g/l, do SRB grow Temperature (T) between 10 and 45 C? Sulfate greater than 10 mg/l Total carbon from fatty acid greater than 20 mg/L Nitrogen (as utilizable N) greater than 5 mg/l C:N ratio less than 10 Flow velocity less than 1 m/s Flow velocity ¼ 2 m/s Flow velocity ¼ 2.5 m/s Flow velocity ¼ 3 m/s Debris on bottom of pipeline Pigging frequency, never Pigging frequency, once 13 weeks Pigging frequency, once 4 weeks Pigging frequency, once a week Prolonged oxygen ingress, greater than 50 ppb Biocide routinely used Age of pipeline, less than half year Age of pipeline, greater than half year, downtime 1 week Age of pipeline, greater than half year, downtime 50 weeks

Value of the Factor When True

Value of the Factor When False

1 1 0.2 1 1 1 1 1 1 0.6 0.1 0.01 2 1 0.3 0.001 0.0001 5 0.2 1 1

0.001 0.2 0.0001 0.2 0.2 0.2 0.2 0.4

1

1 1

2

parameters (Table 6.11). The rationale for the numerical risk of individual parameters is described in the following sections.

6.7.6a Effect of flow rate The flow rate influences the nature of biofilm formation and the rate of nutrient delivery. As flow rate increases, layers of less adherent films are removed, so ultimately only strongly adherent films remain on the metal surface. As a consequence, biofilms become compact as flow increases. However, above a certain flow rate, most biofilms are stripped off and their reformation is limited. Many studies indicate that biofilms are stripped off at flow rates between 2 and 3 m/s (6.5 and 9.8 ft/s). At the other extreme, stagnant flow promotes attachment and colonization of microorganisms onto the metal surface, facilitates biofilm formation and growth, and creates conditions for the formation of tubercles under which MIC occurs. For this reason, MIC occurs often in stratified water, during downtime of operations, and in dead legs.

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6.7.6b Effect of temperature Temperature influences microbial growth in a several ways: low temperatures (typically less than 14 F ( 10 C)) may inhibit cellular metabolic processes; high temperatures (typically more than 250 F (120 C)) may thermally denature the protein constituents of the cell causing them to die; microbes survive between temperatures 14 and 250 F ( 10 and 100 C), but individual microbial species survive in narrower temperature ranges. Depending on the temperature range over which the microbes are active, they can be classified as follows: • • •

•

Psychrotroph: Grow below 60 F (w15 C). MIC has been found in extremely cold environments (below 13 F ( 25 C)) in pipes in Alaska. Mesophile: Grow between 60 and 115 F (15 and 45 C). Mesophile bacteria are the predominant species causing corrosion. Thermophile: Grow between 115 and 140 F (45 and 60 C). A few thermophilic types of SRB grow more efficiently at more than 140 F (60 C), and one type is capable of growing at more than 210 F (100 C). Shifting operating temperatures within the pipeline or seasonal temperature variations may be expected to cause changes in the dominant microbial strains within the biofilm. Hyperthermophile: Grow above 140 F (60 C). Hyperthermophilic microbial activity can occur, but generally they thrive in specialized habitats where the temperature remains relatively constant or fluctuates in a harmonic manner. The highest temperature at which microbial activity can occur is in pressurized water systems at higher pressures and temperatures than boiling water at sea level.

While microorganisms grow more favorably in their typical temperature ranges, they can also grow in other temperature ranges.

6.7.6c Effect of acid gas partial pressure Microorganisms are relatively simple forms of life, and can adapt to radical changes in pressure. Experiments have proved that microbial species have survived for up to 18 hours at a depth of 12,500 feet (3,800 m) below sea water. MIC is considered as a factor only in sweet systems, but not in sour systems. Studies using molecular biological techniques have identified at least 15 different microorganisms from samples collected from a sour gas pipeline. But there is no consensus regarding the overall contribution of MIC in sour systems, though the sour system itself may be created by SRB activity.

6.7.6d Effect of pH Microorganisms grow over the full spectrum of pH, but individual microorganisms normally adapt to specific pH ranges. Depending on pH range in which they are active, microorganisms are classified into: 1) 2) 3) 4) 5)

extreme acidophiles acidophiles neutrophiles alkalophiles extreme alkalophiles

pH between 1.0 and 4.0 pH between 4.0 and 6.0 pH between 6.0 and 9.0 pH between 9.0 and 10.0 pH between 10.0 and 14.0

The extracellular polymeric outer layer buffers the pH within a biofilm, thereby reducing the influence of bulk water pH to some extent. In general, maximum microbial activity occurs within the biofilm when the pH of the bulk is between 4.0 and 9.0. The biofilms are capable of buffering the pH within in this range in solution within them even when the bulk pH strays out of this range.

6.8 Scaling

351

6.7.6e Langelier saturation index (LSI) The Langelier Saturation Index (LSI) is an indication of the extent of saturation of water with respect to formation of calcium carbonate (see section 6.8.1 for more details on LSI). Scales provide an avenue for microbes to establish a biofilm, and to cause underdeposit corrosion.

6.7.6f Total suspended solids (TSS) Water often contains suspended solids which settle when the flow rate is low. The settled solids provide environments for microbes to thrive. Therefore, if the flow rate is less than 10 feet/s (w3 m/s) and if TSS is high, the tendency for MIC to occur is high.

6.7.6g Total dissolved solids (TDS) TDS indicates the mineral content of the water. The main dissolved cations in oil field water are sodium, ferrous, potassium, magnesium, and calcium, and the major dissolved anions are chloride, nitrate, bicarbonate, and sulfate. The TDS values of oil and gas industry water may typically range between 15,000 and 150,000 ppm. Higher TDS values indicate greater potential for microbes to survive.

6.7.6h Redox potential (Eh) Redox potential (Eh) is a measure of the potential of a reversible reduction-oxidation electrode (typically platinum) using a stable reference electrode. If the oxidizing or reducing species contacts the electrode it undergoes oxidation or reduction, causing the potential of the reversible electrode to change. Generally, an oxidative state (þEh value) will support aerobic microbial activities and a reductive state ( Eh) will encourage anaerobic functions. Microbial activities occur extensively when the redox potential is between 50 and þ150 mV.

6.7.6i Sulfur The presence of sulfur in solids may be an indication of the presence of SRB. Sulfur may be present as sulfide, H2S, mercaptans, and polysulphides.

6.8 Scaling117 The formation of scales may lead to corrosion. Therefore several models, commonly known as indices, are used to predict scale formation. These indices predict whether or not scales will form. Prediction of scale formation does not necessarily mean that the scales form on metals. For example, in water containing colloidal silica or other colloidal matter, scales may form on the suspended colloidal particles rather than on the metal surface. Further, the formation of scales on metals may lead to localized corrosion or decreased corrosion. The effect of scale on corrosion depends on whether the scale forms continuously or not, and whether or not it is protective. Several indices are available to predict scale formation, but only a few of them are discussed in the following paragraphs.

6.8.1 The Langelier saturation index (LSI) The Langelier Saturation Index (LSI) is the most popular index for predicting the formation of calcium carbonate scale. It predicts conditions for the formation of calcium carbonate, but does not predict the quantity that would actually precipitate. According to this index: LSI ¼ pH

pHs

(Eqn. 6.47)

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CHAPTER 6 Modeling – Internal Corrosion

where pH is bulk pH (see also section 4.12) and pHs is the pH at saturation in calcite or calcium carbonate. The pHs is calculated using Eqn. 6.48: pHs ¼ ð9:3þ ALSI þ BLSI Þ

ðCLSI þ DLSI Þ

(Eqn. 6.48)

where ALSI is a measure of the total solids effect, BLSI is a measure of the temperature effect, CLSI is a measure of calcium carbonate content, and DLSI is a measure of alkalinity. ALSI, BLSI, CLSI, and DLSI are determined using Eqns. 6.49, 6.50, 6.51, and 6.52 respectively. log10 ½TDSŠ 1 10 ¼ 13:12:log10 ðT þ 273Þ þ 34:55  CLSI ¼ log10 Ca2þ 0:4 ALSI ¼

BLSI

(Eqn. 6.49) (Eqn. 6.50) (Eqn. 6.51)

DLSI ¼ log10 ½alkalinityŠ

(Eqn. 6.52) 2þ

where TDS is the total dissolved solids, T is temperature in centigrade, and [Ca ] and alkalinity are measured as calcium carbonate (CaCO3). The TDS may be estimated from the conductivity of solution and approximately 1 s/cm of conductivity is assumed to be approximately 0.41 mg/L of calcium carbonate. Table 6.15 presents further details of scale formation as predicted by LSI.

Table 6.15 Tendency to Form Scale117 Langelier Saturation Index (LSI)

Ryznar Stability Index (RSI)

Tendency to Scale

Above 3.0 2.0e3.0 1.0e2.0 1.0e0.5 0.5e0.2 0.2e0.0

Above 3.0 3.0e4.0 4.0e5.0 5.0e5.5 5.5e5.8 5.8e6.0

0e

6.0e6.5

Extremely severe Very severe Severe Moderate Slight Stable water, no tendency to form or dissolve scale No scaling, very slight tendency to dissolve scale No scaling, slight tendency to dissolve scale No scaling, moderate tendency to dissolve scale No scaling, strong tendency to dissolve scale No scaling, very strong tendency to dissolve scale

0.2

0.2 e

0.5

6.5e7.0

0.5 e

1.0

7.0e8.0

1.0 e

2.0

8.0e9.0

2.0 e

3.0 and above

9.0e10.0 and above

6.9 High-temperature corrosion

353

Table 6.16 Indices to Predict Scale Formation117 Index

Characteristics

Puckorius Scaling Index

Puckorius Scaling Index quantifies the relationship between saturation state and scale formation by incorporating the effect of buffering capacity of water Stiff-Davis Index modifies the LSI by including the influence of ’common ions’ effect Oddo-Tomson Index modifies the LSI by including the influence of pressure and partial pressure of CO2 Larson-Skold Index correlates water chemistry and corrosion of mild steel

Stiff-Davis Index Oddo-Tomson Index Larson-Skold Index

6.8.2 The Ryznar stability index (RSI) Ryznar stability index (RSI) quantifies the relationship between calcium carbonate saturation state and scale formation as: (Eqn. 6.53) RSI ¼ 2pHs pH Table 6.15 presents the tendency to form scale, as predicted by LSI and RSI.

6.8.3 Other indices Several other indices are available. Table 6.16 presents some common indices and their characteristics.

6.9 High-temperature corrosion118,119 Prediction of high-temperature corrosion in gas environment depends on predicting the formation and stability of oxides (see section 5.15). The Pilling and Bedworth Ratio (PBR) provides a quick method to predict high-temperature corrosion. PBR is defined as: MWscale :rscale (Eqn. 6.54) PBR ¼ nAwt rmetal where MWscale is the molecular weight of scale (corrosion product), rscale is the density of scale, n is the number of atoms in a molecule of oxide (for example for Al2O3, n ¼ 2), Awt is the atomic weight of metal, rmetal is the density of metal. Table 6.17 lists the PBR of selective metals. The PBR is an indication of relative volumes of metal and its scale. If the PBR is greater than unity, then the volume of scale is higher than that of the metal from which it is formed; such a scale covers the entire surface and is protective. For example the PBRs of chromium and aluminum are higher than unity and their scales are protective. If the PBR is less than unity, then the volume of scale is less than that of metal from which it is formed; such a scale does not cover the entire surface and is relatively non-protective. For example the PBRs of magnesium and calcium are less than unity and these scales are non-protective. Even when PBR is greater than unity, scales may become non-protective above certain temperatures and above certain thicknesses. For example, a chromium oxide scale on chromium with PBR 2.0 is protective up to 1,100 C; above this temperature the scale spalls off exposing the underlying metal

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Table 6.17 Pilling-bedworth Ratio119 Metal

Oxide

Pilling-Bedworth Ratio

Chromium Cobalt Titanium Iron Copper Nickel Aluminum Magnesium Calcium Lithium

Cr2O3 CoO TiO2 FeO CuO NiO Al2O3 MgO CaO Li2O

2.0 1.9 1.8 1.7 1.7 1.7 1.3 0.8 0.6 0.6

surface. The protectiveness of a scale also depends on the adherence of the scale to the substrate. However, the PBR does not consider the influence of adherence.

6.10 Top-of-the-line corrosion (TLC) Two key parameters of practical importance with respect to TLC are the prediction of locations where water condenses and the rate at which it does so (see section 5.24). None of the current models adequately address these two key parameters. In fact, some models require the water condensation rate as an input. Within these constrains, some models which have been developed to predict TLC are presented in this section.

6.10.1 The DeWaard model120 DeWaard proposed the first model to predict TLC as:  Ccorr ¼ Fcond :10:

5:8

1710 Tk

þ 0:67:logðpCO2 Þ



(Eqn. 6.55)

where Ccorr is the corrosion rate (mm/y), Fcond is the correction factor for water condensation and is assumed to be a constant 0.1, T is the temperature (K), and pCO2 is the partial pressure of CO2 (bar).

6.10.2 The Pots model121 Pots developed another model for TLC by considering both iron dissolution and condensation rates. According to the Pots model: MWFe  106  24  3600  365 h 2þ i WCR : Fe : (Eqn. 6.56) Ccorr ¼ rcarbonsteel rw

where Ccorr is the corrosion rate (mm/y), MWFe is the iron molecular weight (55.847 g/mol), rCarbonsteel is the density of carbon steel (7860000 g/m3), [Fe2þ] is the iron concentration (mol/l), WCR is the water condensation rate (g/m2/s), and rw is the water density (g/m3).

References

355

6.10.3 The Gunaltum model122,123 Gunaltum developed a model based on the assumption that TLC occurs by continuous formation of a water film on the surface. According to this model, the concentration of ferrous ion in the film as a function of time is given by:  



d Fe2þ 1 2þ (Eqn. 6.57) ¼  K:Ccorr ð1 KÞ:PR WCR: Fe d dt where [Fe2þ] is the concentration of iron ion (mol/m3), t is the time in sec, d is the liquid film thickness (m), K is the covering factor or proportionality constant, Ccorr is the corrosion rate (mol/m3/s), PR is the precipitation rate (mol/m3/s), and WCR is the water condensation rate (m3/m2/s).

6.10.4 The Nyborg model124 Nyborg developed a model which assumes that TLC is limited by the amount of iron dissolving in the condensing water. According to the model:    (Eqn. 6.58) Ccorr ¼ 0:004:WCR: Fe2þ 12:5 0:09  T

where Ccorr is the corrosion rate, WCR is the water condensation rate, [Fe2þ] is concentration of ferrous ion (ppm), and T is the temperature ( C).

References 1. Eliassen S, Smith L, editors. Guidelines on Materials Requirements for Carbon and Low Alloy Steels for H2S-Containing Environments in Oil and Gas Production. EFC. 3rd ed., 16; July 2009. ISBN: 978 1 90654 033 3. 2. ASTM E140, ‘Standard Hardness Conversion Tables for Metals Relationship Among Brinell Hardness, Vickers Hardness, Rockwell Hardness, Superficial Hardness, Knoop Hardness, and Scleroscope Hardness’ ASTM International, 100 Barr Harbor Drive, West Conshohocken, PA, 19428-2959 USA. 3. British Standard 860, ‘Tables for Comparison of Hardness Scales’ British Standards Institute, 389 Chiswick High Road, London, W4 4AL Satnav postcode: W4 4AL Tel: þ44 20 8996 9001. 4. ANSI/NACE MRO175/ISO 15156–3, ‘Petroleum and Natural Gas Industries – Materials for use in H2SContaining Environments in Oil and Gas Production – Part 3: Crack-resistant CRAs (CorrosionResistant Alloys) and Other Alloys’ NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 5. Elboujdaini M. Chapter 78, ‘Test Methods for Wet H2S Cracking’. In: Revie RW, editor. Uhlig’s Handbook. Wiley and Sons; 2011. Figure78.7, p. 1091, ISBN: 978–0470–87285–7, J. 6. Kim CD, Loginow AW. Techniques for Investigating Hydogen-Induced Cracking of Steels with High Yield Strength. In: Tuttle RN, Kane RD, editors. H2S Corrosion in Oil and Gas Production – A compilation of classic papers. Houston, TX: NACE International; 1981. p. 1000. 7. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2Scontaining Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Section 7.2.1.2, Figure 1, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 8. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2Scontaining Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Figure D.1, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906.

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9. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2Scontaining Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Figure D.2, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 10. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Figure D.3, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 11. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Figure D.4, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 12. ANSI/NACE MR0175/ISO 15156–2, ‘Petroleum and Natural Gas Industries – Materials for use in H2Scontaining Environments in Oil and Gas Production – Part 2: Corrosion-Resistant Carbon and Low Alloy Steels, and the Use of Cast Irons’, Figure D.5, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 13. Srinivasan S, Kane RD. Experimental Simulation of Multiphase CO2 and H2S Systems, CORROSION 99. NACE International: Houston, TX; 1999. 14. Kermani MB, Smith LM. CO2 Corrosion Control in Oil and Gas Production: Design Considerations. European Federation of Corrosion Publications; 1997. Number 23, EFC. 15. Kermani MB, Morshed A. Carbon Dioxide Corrosoin in Oil and Gas Production – A Compendium. Corrosion 2003;59(8):659. 16. Sridhar N, Dunn DS, Anderko AM, Lencka MM, Schutt HU. Effects of Water and Gas Composition on the Internal Corrosion of Gas Pipelines-Modeling and Experimental Studies. Corrosion 2001;57(3):221. 17. Papavinasam S, Doiron A, Revie RW. Model to Predict Internal Pitting Corrosion of Oil and Gas Pipelines. Corrosion 2010;66(3):35006 (11 pages). 18. de Waard C, Milliams DE. Carbonic Acid Corrosion of Steel. Corrosion, NACE May 1975;31(5):177–81. 19. de Waard C, Lotz U. Prediction of CO2 Corrosion of Carbon Steel; 1993. CORROSION 93, Paper #69, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 20. de Waard C, Lotz U, Dugstad A. Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model; 1995. CORROSION 95, Paper #128, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 21. de Waard C, Lotz U, Milliams DE. Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines. Corrosion 1991;47(12):976. 22. Srinivasan S, Kane RD. Prediction of Corrosivity of CO2/H2S Production Environments; 1996. CORROSION 96, Paper #11, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 23. Kane RD. Roles of H2S in behavior of engineering alloys. Int Met Rev 1985;30(6):291. 24. Murata T, et al. Evaluation of H2S containing environments from the view point of OCTG and line pipe for sour gas applications. Paper No. OTC 3507. Houston, Texas: 1lth Annual Offshore Technology Conference; 1979. Offshore Technology Conference10777 Westheimer Road, Suite 1075, Houston, Texas 77042. 25. Dugstad A, Lunde L. Parametric study of CO2 corrosion of carbon steel; 1994. Corrosion 94, Paper # 14, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 26. Smart JS. Wettability – A major factor in oil and gas system corrosion; 1993. Corrosion 93, Paper # 70, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 27. Efird KD. Predicting corrosion of steel in crude oil production. Mater Perform 1991;30(3):63. 28. Oilfield J, Todd B. Corrosion considerations in selecting metals for flash chambers. Desalination 1979;31:365. 29. Bonis MR, Crolet JL. Basics of the Prediction of the Risks of CO2 Corrosion in Oil and Gas Wells; 1989. CORROSION 89, Paper #466, NACE International, 1440 South Creek Drive Houston, TX USA 77084–4906.

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30. Crolet J-L, Thevenot N, Dugstad A. ‘Role of Free Acetic Acid on the CO2 Corrosion of Steels,’ Corrosion 99, Paper #24. NACE International, 1440 South Creek Drive Houston: TX USA 77084-4906; 1999. 31. Nesic S, Postlethwaite J, Olsen S. An Electrochemical Model for Prediction of Corrosion in Mild Steel in Aqueous Carbon Dioxide Solutions. Corrosion 1996;52(4):280. 32. Nesic S, Postlethwaite J, Olsen S. An Electrochemical Model for Prediction of CO2 Corrosion; 1995. CORROSION 95, Paper #131, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 33. Nesic S, Nordsveen M, Nyborg R, Stangeland A. A Mechanistic Model for CO2 Corrosion with Protective Iron Carbonate Films. Corrosion 2001. Paper #01040, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 34. Mishra B, Al-Hassan S, Olson DL, Salama MM. Development of a Predictive Model for ActivationControlled Corrosion of Steel in Solutions Containing Carbon Dioxide. Corrosion Nov. 1997;53(11):852–9. 35. Dayalan E, de Moraes FD, Shadley JR, Shirazi SA, Rybicki EF. CO2 Corrosion Prediction in Pipe Flow under FeCO3 Scale-Forming Conditions; 1998. CORROSION 98, Paper #51, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 36. Anderko A, Young R. D. ‘Simulation of CO2/H2S Corrosion using Thermodynamic and Electrochemical Models,’ CORROSION 99, Paper #31, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 37. Anderko A. Simulation of FeCO3/FeS Scale Formation Using Thermodynamic and Electrochemical Models. CORROSION 2000. Paper #00102, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 38. Anderko A, McKenzie P, Young RD. Computation of Rates of General Corrosion Using Electrochemical and Thermodynamic Models. Corrosion March 2001;57(3):202–13. 39. Oddo JE, Thompsons MB. The Prediction of Scale and CO2 Corrosion in Oil Field Systems; 1999. CORROSION 99, Paper #41, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 40. Pots BFM. Mechanistic Models for the Prediction of CO2 Corrosion Rates under Multiphase Flow Conditions; 1995. CORROSION 95, Paper #137, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 41. Pots BFM, John RC, Rippon IJ, Thomas MJJS, Kapusta SD, Girgis MM, Whitham T. Improvements of dewaard-Milliams Corrosion Prediction and Applications to Corrosion Management; 2002. CORROSION 2002, Paper 2235, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 42. Nyberg R, Andersson P, Nordsveen M. Implementation of CO2 Corrosion Models in a Three-Phase Fluid Flow Model; 2000. CORROSION 2000, Paper #48, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 43. Halvorsen AMK, Sontvedt T. CO2 Corrosion Model for Carbon Steel Including a Wall Shear Stress Model for Multiphase Flow and Limits for Production Rate to Avoid Mesa Attack; 1999. CORROSION 99, Paper #42, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 44. CO2 Corrosion Rate Calculation Model; 1998. NORSOK Standard # M-506, Norwegian Technology Standards Institution, Oscarsgt. 20, Postbox 7072 Majorstua. N-0306 Oslo, NORWAY. 45. Kermani MB, Smith LM. CO2 Corrosion Control in Oil and Gas Production, Design Considerations. European Federation of Corrosion Publications; 1997. Number 23, Chapter 6, 18–23. 46. Adams CD, Garber JD, Singh RK. Computer Modeling to Predict Corrosion Rates in Gas Condensate Wells Containing CO2; 1996. CORROSION 96, Paper #31, NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 47. ASTM G193 – NACE 12C, ‘Standard Terminology and Acronyms Relating to Corrosion’ NACE International, 1440 South Creek Drive Houston, TX USA 77084-4906. 48. Sharland SM. A Review of the Theoretical Modeling of Crevice and Pitting Corrosion. Corrosion Sci 1987; 27(3). 389–323. 49. Griffin GL. A simple phase transition model for metal passivation kinetics. J Electrochem Soc 1984;131:18.

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50. Fleischmann M, Thirsk HR. The Growth of Thin Passivating Layers on Metallic Surfaces. J Electrochem Soc 1963;110:688. 51. Sato N, Cohen M. The kinetics of anodic oxidation of iron in neutral solution. J Electrochem Soc 1964;111:512. 52. Sarasola C, Fernandez T, Jimenez Y. Potentiodynamic Passivation of iron in KOH solution: Application of the Layer-Pore Resistance Model. Electrochimica Acta 1988;33:1295. 53. Chao CY, Lin LF, Macdonald DD. A point defect model for anodic passive films. J Electrochem Soc 1981; 128. 1187 and 1194. 54. Ambrose JR. Repassivation Kinetics. Treatise on Materials Science and Technology 1981;23:175. 55. Papavinasam S, Revie RW, Friesen W, Doiron A, Panneerselvam T. Corrosion Rev 2006;24(3–4):173–230. 56. Okada T. A theory of perturbation - Initiated pitting. J Electrochem Soc 1985;132:537. 57. Shibata T. Stochastic processes of pit generation on zirconium with an anodic oxide film. Corrosion Sci 1992;33:1633. 58. Baroux B. The kinetics of pit generation on stainless steels. Corrosion Sci 1988;28:969. 59. Salvarezza RC, Cristofaro ND, Pallotta C, Arvia AJ. Stochastic and deterministic behaviors of 316 stainless steel pitting corrosion in phosphate-borate buffer containing sodium chloride. Electrochimica Acta 1987; 32:1049. 60. Williams DE, Westcott C, Fleischmann M. Stochastic models of pitting corrosion of stainless steels. J Electrochem Soc 1985;132. 1796 and 1804. 61. Bertocci U, ‘Advances in Localized Corrosion,’ Proceedings of the Second International Conference on Localized Corrosion, p. 127, 1987. 62. Oldfield W, Sutton WH. Crevice corrosion of stainless steels. Br Corrosion J 1978;13:13. 63. Xu Y, Wang M, Pickering HW. On electric field induced breakdown of passive films and the mechanism of pitting corrosion. J Electrochem Soc 1993;140:3448. 64. Xu Y, Pickering HW. The effect of electrolyte properties on the mechanism of crevice corrosion in pure iron. J Electrochem Soc 1993;140:658. 65. MacDonald DD, MacDonald MU. Theory of Steady State Passive Films. J Electrochem Soc 1990;137: 2395. 66. MacDonald DD, MacDonald MU. Distribution Functions for the Breakdown of Passive Films. Electrochimica Acta 1986;31:1079. 67. Nagatani T. Scaling structure of pit profile in pitting corrosion. J Phys Soc Jpn 1991;60:3997. 68. Matamala GR. Correlation model of the AISI 316 Stainless steel pitting potential with cellulose bleach process variables. Corrosion 1987;43:97. 69. Smyrl WH, Newman J. Mass transfer of minor components in a propagatin crack. J Electrochem Soc 1974; 121:1000. 70. Fan J.C., Richardson J., CORROSION 1994, Paper /315, "The modelling of pit propagation and its inhibition", NACE International, Houston, Texas (1994). 71. Molo EE, Mellein B, Schiapparelli EMRD, Vicente JL, Salvarezza RC, Arvia AJ. J Electrochem Soc 1990; 137:1384. 72. Doig P, Flewit PEJ. An analysis of stress corrosion crack growth by anodic dissolution. Proc R Soc 1977; A357:439. 73. Doig P, Flewit PEJ. The significance of external polarization on stress corrosion crack growth by anodic polarization. Metall Trans 1978;9A:357. 74. Melville BH. Variation of potential in stress corrosion cracks. Brit Corr J 1979;14:15. 75. Alkire R, Ernsberger D, Damon D. The role of conductivity variations within artificial pits during anodic dissolution. J Electrochem Soc 1976;123:458. 76. Hebert K, Alkire R. Formation of salt films during anodic metal dissolution in the presence of fluid flow. J Electrochem Soc 1983;130:1007. 77. Tester JW, Issac HS. Diffusional effects in simulated localized corrosion. J Electrochem Soc 1975;122:1438.

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78. Beck TR, Alkire RC. Occurrence of Salt Films during Initiation and Growth of Corrosion Pits. J Electrochem Soc 1979;126:1662. 79. Ateya BG, Pickering HW. On the nature of electrochemical reactions at a crack tip during hydrogen charging of a metal. J Electrochem Soc 1975;122:1018. 80. Ben Rais A, Sohm JC. Aluminum pit propagation in acidic media: II. Theoretical model. Corrosion Sci 1985;25:1047. 81. Galvele JM. Transport processes and the mechanism of pitting of metals. J Electrochem Soc 1976;123:464. 82. Galvele JM. Transport processes in passivity breakdown: II. Full hydrolysis of the metal ions. Corrosion Sci 1981;21:551. 83. Gravano SM, Galvele JR. Transport processes in passiviity breakdown: III. Full hydrolysis plus ion migration plus buffers. Corrosion Sci 1984;24:517. 84. Schmitt G, Mueller M. Critical Wall Shear Stresses in CO2 Corrosion of Carbon Steel. Houston, TX: NACE; 1999. CORROSION 99, Paper #44. 85. McGovern C. ‘Corrosion Modeling’, Tutorial #3, Internal Corrosion Control of Pipelines, Banff Pipeline Workshop. Obtainable through, www.banffpipelineworkshop.com [accessed on 16.08.13.]. 86. Papvinasam S, Doiron A, Panneerselvam T. Integration of Localized Pitting Corrosion and Flow Models. NACE Corrosion Conference; 2012. Paper #23794. 87. Papavinasam S, Doiron A, Li J, Park DY, Liu P. Sour and Sweet Corrosion of Carbon Steel: General or Pitting or Localized or All of the Above? NACE Corrosion Conference; 2010. Paper #14054. 88. Demoz A, Papavinasam S, Omotoso O, Michaelian K, Revie RW. Effect of Field Operational Variables on Internal Pitting Corrosion of Oil and Gas Pipelines. Corrosion 2009;65(11):741–7. 89. Papavinasam S, Doiron A, Revie RW. Effect of Surface Layers on the Initiation of Internal Pitting Corrosion in Oil and Gas Pipelines. Corrosion 2009;65(10):663–73. 90. Papavinasam S, Demoz A, Michaelian K, Revie RW. Further Validation of Internal Pitting Corrosion Model; 2008. Paper #08642, New Orleans, March 16–20, NACE, Houston, Texas. 91. Papavinasam S, Doiron A, Sizov V, Revie RW. A Model to Predict Internal Pitting Corrosion of Oil and Gas Pipelines (Part 1), Oil and Gas Journal; Nov.26, 2007. 105, 44pages 68–73. 92. Papavinasam S, Doiron A, Sizov V, Revie RW. A Model to Predict Internal Pitting Corrosion of Oil and Gas Pipelines (Part 2), Oil and Gas Journal; Dec. 2007. 105, 45pages 62–67. 93. Papavinasam S, Doiron A, Revie RW. Empirical Equations to Predict Conditions for Solid Deposition. Mater Perform 2007;46(8):58–60. 94. Papavinasam S, Doiron A, Panneerselvam T, Revie RW. Effect of Hydrocarbons on the Internal Corrosion of Oil and Gas Pipelines. Corrosion 2007;63(7):704–12. 95. Papavinasam S, Doiron A, Revie RW. A Model to Predict Internal Pitting Corrosion of Oil and Gas Pipelines. Corrosion 2007. Paper #7658. 96. Papavinasam S, Revie RW. Predicting Internal Pitting Corrosion of Oil and Gas Pipelines: HydrocarbonWet to Water-Wet Transition; March 12–19, 2006. CORROSION 2006, Paper #6641. 97. Papavinasam S, Friesen W, Revie RW, Doiron A. Predicting Internal Pitting Corrosion of Oil and Gas Pipelines: A Corrosion Engineering Approach. Houston: Texas; 2005. Corrosion 2005, Paper #05643, NACE. 98. Papavinasam S, Revie RW, Doiron A. Predicting Internal Pitting Corrosion of Oil and Gas pipelines: Review of Electrochemical Models. Houston: Texas; 2005. Corrosion 2005, Paper #05644, NACE. 99. Papavinasam S, Revie RW, Doiron A. Predicting Internal Pitting Corrosion of Oil and Gas Pipelines: Review of Corrosion Science Models. Houston: Texas; 2005. Corrosion 2005, Paper #05645, NACE. 100. Graedel TE, Frankenthal RP. Corrosion Mechanisms for Iron and Low Alloy Steels Exposed to the Atmosphere. J Electrochem Soc 1990;137(8):2385. 101. Sooknah RD, Papavinasam S, Revie RW. Modeling The Occurrence of Microbiologically Influenced Corrosion; 2007. CORROSION/2007, Paper No.07515, NACE, Houston, TX.

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102. Sooknah RD, Papavinasam S, Revie RW. Validation of a Predictive Model for Microbiologically Influenced Corrosion; 2008. CORROSION/2008, Paper No.08503, NACE, Houston, TX. 103. Haile T, Papavinasam S, Zintel T. Validation of Corrosion Models using Field Data obtained from Oil and Gas Production Pipelines. Houston, TX: NACE International; 2013. CORROSION 2013, Paper #2170. 104. Mohitpour M, Golshan H, Murray A. Pipeline Design and Construction: A Practical Approach. 3rd ed. New York: Three Park Avenue; 2007. Eqn.3.73, p. 95, The American Society of Mechanical Engineers, 10016, ISBN: 0–7918–0257–4. 105. Zhou S, Stack MM, Newman RC. Characterization of Synergistic Effects Between Erosion and Corrosion in an Aqueous Environment Using Electrochemical Techniques. Corrosion 1996;52:934. 106. Nesic S, Postlethwaite J. A Predictive Model for Localized Erosion-Corrosion. Corrosion 1991;47:582. 107. Shadley J.R., Shirazi S.A., Dayalan E., Ismail M., and Rybicki E.F., ‘Erosion-Corrosion of a Carbon Steel Elbow in a CO2 Environment’, CORROSION/95, Paper No. 119. 108. Electric Power Research Institute, ‘Microbiologically Influenced Corrosion’, TM1001, EPRI Palo Alto, CA, 1994. 109. Electric Power Research Institute, ‘CHECWorksTM Cooling Water Applications’, CWUG-1999, EPRI, Palo Alto, CA, 1999. 110. Chexal VK. Proceedings International Corrosion Conf., Paper IWC-97–84. Eng Soc W 1997. PA, Pittsburgh, PA. 111. Schultz GL, Hampton BE. Proceedings EPRI SWSRI. Charlotte, NC: EPRI NDE Center; June 22–27, 1997. 112. Lutey RW, Stein A. Proceedings 14th International Corrosion Conf; 1999. 8Paper 5.6–263, Cape Town, SA, Sept. 27. 113. Chexal VK, Bindi K. New Predictive Technology to Control Corrosion in Plant Service Water Systems. Houston, TX: Proceedings 1996 International Power Conference; Oct. 13–16, 1996. EPRI, Palo Alto, CA. 114. Lutey RW. EPRI MIC Quad Chart TM0089. Charlotte, NC: EPRI NDE Center; 1989. 115. Stott JFD. Evaluating Microbiologically Influenced Corrosion, In Corrosion Fundamentals, Testing, and Protection, ASM Handbook, vol. 13A. USA: ASM International; 2003. 644–649. 116. Maxwell S, Campbell S. Monitoring the Mitigation of MIC Risk in Pipelines; 2006. CORROSION/2006, Paper #06662, Houston, TX. 117. Davies M, Scott PJB. Oilfield water technology; 2006. p. 288, ISBN: 1–57590–204–4, NACE, Houston, TX. 118. Wright IG. High-Temperature Corrosion. In: Korb LJ, Olson DL, editors. ASM Handbook. Corrosion, vol. 13. ASM International; 1987. p. 97. ISBN: 0–87170–007–7. 119. Revie RW, Uhlig HH. Corrosion and Corrosion Control: An Introduction to Corrosion Science and Engineering. 4th ed.; 2008. Table 11.1, p. 220, John Wiley & Sons, ISBN: 978–0-471–73279–2. 120. DeWaard C, Lotz U, Milliams DE. Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines. 47(12); 1991. p. 976. 121. Pots BFM, Hendriksen ELJA. CO2 corrosion under scaling conditions – The special case of top-of-the-line corrosion in wet gas pipelines; 2000. NACE CORROSIONPaper #31. 122. Gunaltum Y, Kaewpradap U, Singer M, Nesic S. Progress in the prediction of top-of-the-line corrosion and challenges to predict corrosion rates measured in gas pipelines; 2010. NACE CORROSIONPaper #10093. 123. Vitse F, Gunaltun Y, de, Larrey TD, Duchet SP. Mechanistic Model for the prediction of top-of-the line corrosion risk; 2003. NACE CORROSIONPaper 3633. 124. Nyborg R, Dugstad A. Top-of-the line corrosion and water condensation rates in wet gas pipelines. NACE 2007. Paper # 7555.

CHAPTER

Mitigation – Internal Corrosion

7

7.1 Introduction A decision should be taken in the design stage either to use expensive corrosion-resistant alloys (CRA) or carbon steel. This decision may be based on field experience, on the evaluation of a particular material for a given environment, or on modeling. Selection of CRAs may increase capital expenditure (CAPEX), whereas selection of carbon steel may increase operational expenditure (OPEX). Thus, during the design stage a balance between CAPEX and OPEX is established; Chapter 14 discusses the strategies used to establish this balance. For either option, implementation of appropriate mitigation activities is required. This chapter discusses some time-tested and proven activities to mitigate internal corrosion, including pigging, corrosion inhibitors, biocides, internal lining and coating, cladding, cathodic protection, and process optimization.

7.2 Pigging1–6 The term ‘pigging’ is used in the pipeline sector to represent the process of using a device called a ‘pig’. The origin of the term is not known exactly, but this term was originally referred to a device used to gauge the integrity of pipe, i.e., pipeline integrity gauge (pig). It is also thought that barbed wire was wrapped around bundles of straw rise to the name “pig” from the squealing noise. Pigging involves driving the pig with the flowing fluid in the pipeline at a controlled velocity to get the optimum result without any obstruction in the flowing conditions. Depending on their functionality, pigs may be broadly classified into three types; cleaning pigs, sealing pigs, and inline inspection (ILI). Cleaning pigs are used to remove solid deposition, debris, wax, asphaltenes, biofilms, and other extraneous materials from the pipe. Sealing pigs are used to seal, to sweep liquid (mainly water), to apply corrosion inhibitors, to coat the pipe, and to separate products. Cleaning and sealing pigs are normally used in sequence to mitigate internal corrosion, which they do by cleaning the surface and by protecting it with corrosion inhibitors. Inline inspection tools are utilized to inspect pipelines, and are commonly known as intelligent pigs (Chapter 8 (section 8.4) discusses ILI tools). A pigging operation is performed during construction, operation and maintenance, inspection, repair and rehabilitation, and decommissioning. Pigs are used not only in bare metallic pipelines but also in metallic pipelines with non-metallic liners and in non-metallic pipelines (e.g., fiberglass, highdensity polyethylene, and composite). In non-metallic pipelines, a pigging operation is used to remove accumulated water and solids. Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00007-8 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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Pigs require specially designed facilities to launch (launcher) and to receive (receiver) them. Launcher and receiver are sophisticated facilities requiring careful procedures to operate. Figures 7.1 and 7.2 respectively present typical configurations of a launcher and a receiver. The launcher is installed upstream of where the pigging operation starts and the receiver is installed downstream when the pigging operation completes. The distance between the launcher and receiver depends on type of pipeline, type of products, operational history, locations of pump (in liquid pipeline) and compressor (in gas pipeline) stations, type of contamination in the pipe, and the type of pig. Normally, this distance is between 300 to 500 miles (w500 to 800 km) for an oil transmission pipeline, and 100 to 200 miles (w160 to 320 km) for a gas transmission pipeline. The distance between launcher and receiver may be

pressure gauge

E

mainline trap valve

vent valve

PIG-SIG®

X

flow

closure

A D trap kicker valve

drain

mainline bypass valve

B

C

FIGURE 7.1 Typical Basic Configuration of Pig Launcher.6 (A: Isolation valve; B: Bypass valve; C: Kicker valve; D: Drain valve; E Vent valve).

mainline trap valve flow

PIG-SIG®

E

pressure gauge

vent valve

X

B

A mainline bypass valve

trap bypass valve

D C drain

FIGURE 7.2 Typical Configuration of Pig Receiver.6 (A: Isolation valve; B: Bypass valve; C: trap bypass valve; D: Drain valve; E Vent valve).

closure

7.2 Pigging

363

Table 7.1 Influence of Internal Diameter of the Pipe on the Effectiveness of Pigging7 Pipeline 3’ linepipe 3’ linepipe with schedule 40 riser pipe 3’ linepipe with schedule 80 riser pipe Pig outer diameter

Typical Inner Diameter (Inches)

Outer Diameter of Pig Is Larger than Inner Diameter of the Pipe (%)

3.25 3.07

5 11

2.90

17

3.40

Pig diameter selected based on the outer diameter of the pipe of 3.40 inch can not be used

as little as 500 feet (w150 meter) in some instances. To use the pigs, several pipeline features are removed, including variation in the diameter of the pipeline, sharp bends, tee junctions, valves, hot taps, dents, buckles, dart in the line, and other installations (e.g., drips, bends, vortex breakers, and branch connections). Otherwise, these features restrict the flow of the pigs. In addition, logistic issues of transporting the pigs to the launcher and from the receiver should be considered. The cleaning pigs remain physically in contact with the internal surface of the pipeline, and hence undergo physical damage during use. Therefore maintaining the parts of the pigs is as important as selecting an appropriate configuration. More than 500 configurations of cleaning pigs are currently available. Each configuration is unique and serves a special purpose. Table 7.1 presents an example of selecting appropriate pig diameter based on the practical internal diameter of a pipeline. Table 7.2 and 7.3 present the suitability of different pig configurations for cleaning and for treating applications respectively. The characteristics of different pig configurations are discussed in the following paragraphs. Table 7.2 Use of Various Configurations of Pigs for Different Cleaning Applications5 Cleaning Application Pig Types

Sand/Sludge

Scale

Water

Paraffin

Bacteria

Sphere Foam e Swab Foam e Poly Cast Mandrel Brush Plow blade Bidirectional Pin wheel Multi-diameter Bypass Gel

Poor Fair Good Good Excellent Poor Poor Excellent Poor Fair Good Good

Poor Poor Fair Fair Fair Good Poor Good Good Fair Good Poor

Fair Fair Good Good Excellent Poor Poor Excellent Poor Poor Good Good

Poor Poor Poor Poor Fair Poor Excellent Fair Fair Fair Fair Poor

Poor Poor Fair Poor Fair Excellent Fair Good Fair Fair Fair Fair

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Table 7.3 Use of Various Configurations of Pigs for Different Treating Applications5 Treating Application Pig Types

Start-up

Inhibitor

Biocide

Paraffin Solvent

Sphere Foam e Swab Foam e Poly Cast Mandrel Brush Plow blade Bidirectional Pin wheel Multi-diameter Bypass Gel

Poor Good Good Good Good Poor Poor Excellent Poor Fair Poor Good

Poor Fair Fair Excellent (a) Excellent Poor Poor Good Poor Poor Poor Good (d)

Poor Poor Fair Excellent (a) Excellent Good (c) Poor Excellent Poor Poor Poor Good (d)

Poor Poor Poor Good (b) Good (b) Poor Fair Good Poor Poor Poor Fair

a

holes can be drilled in the center casting to apply chemicals check solvent/disc or cup material for compatibility use swab behind brush pig to aid in launch d speciality gels incorporate inhibitors and biocides b c

7.2.1 Sphere pigs As the name suggests the sphere pigs are spherical in shape (Figure 7.3). Spheres may also be manufactured in the inflatable form from elastomers (polyurethane, neoprene, nitrile, or VitonÔ ). These spheres are inflated up to 1 to 2% over the inner diameter of the pipeline. Sphere pigs have been used for a long time in the industry, especially in cleaning pipelines with irregular shapes, e.g., 90 degree angle, irregular turns, and bends. They are commonly used to remove

FIGURE 7.3 Photos of Typical Sphere Pigs.5

7.2 Pigging

365

FIGURE 7.4 Photos of Typical Foam or Poly Pigs.5

liquids from wet gas pipelines, to remove paraffin from crude oil pipelines, to flood the pipeline for hydrostatic testing, and to remove water after hydrostatic testing. Soluble spheres are sometimes used in crude oil pipelines plugged with wax and paraffin. These pigs clean the pipeline by reaching the plug point and by dissolving the blocking materials. Soluble spheres dissolve in a few hours, and the dissolution rate depends on temperature, velocity, friction, and the type of wax and paraffin. Soluble spheres are sometimes used in a pipeline that has never been pigged before to test its cleanliness.

7.2.2 Foam pigs Foam pigs are commonly known as poly-pigs. Foam pigs are an inexpensive and versatile type of cleaning device. They are compressible, expandable, flexible, and lightweight; therefore can negotiate irregular piping, fittings and valves. Foam pigs are manufactured in a bullet shape (Figure 7.4) from lightweight, polyurethane foam of various densities: light (1–4 lbs/ft3), medium (5–8 lbs/ft3) and heavy (9–10 lbs/ft3). They can be bare foam or can be further coated with polyurethane, brush, or silicon carbide. Bare foam pigs, commonly known as swabs or squeegees, are primarily used for determining any obstructions, for drying, for sweeping of loose debris, for removing condensates in wet gas pipelines, for assessing the internal pipe conditions before running expensive ILI pigs, and for pigging pipelines of multiple diameters. Foam pigs with wire brushes are used for cleaning lines containing buildup or debris. Foam pigs with silicon carbide are used for scraping and for mild abrasion of the pipeline.

7.2.3 Cast pigs Cast pigs are molded in cup or disc form (Figure 7.5). They are usually manufactured from urethane, neoprene, nitrile, VitonÔ , and other rubber elastomers. Cast urethane pigs are normally manufactured for use in pipelines with internal diameter between 14 and 16 inches (w355 and 406 mm); although 36 inches (914 mm) diameter cast pigs are also available. Cast pigs are effective in removing liquids from

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FIGURE 7.5 Photos of Typical Cast Pigs.5

product pipelines, in removing condensate and water from gas pipelines, and in controlling paraffin buildup in crude in pipelines. Cast pigs have hollow spaces between the discs or cups that can be filled with chemical inhibitors. Hollow cast urethane pigs are always used in well-lubricated pipelines (liquid or multiphase). Otherwise the pig sticks on the inner pipeline wall and blocks the flow. Cast pigs are manufactured as one unit; therefore when they are worn out the entire pig is replaced.

7.2.4 Mandrel pigs Mandrel pigs consist of a central tube or mandrel on to which various components (wire brushes, discs, or blades) are attached (Figure 7.6). Therefore, when the components wear out only the parts are replaced rather than the entire pig body. The central tube or mandrel is normally constructed using urethane and, depending on the application, the blades, discs, and brushes are constructed using materials (carbon steel, stainless steel, urethane, or other plastic materials) of a different hardness. Mandrel pigs are designed for longer runs and for heavy scrapping. They are used for cleaning, for applying batch inhibitors, or for displacing water. Bypass holes present in the nose of the pig control their speed or act as jet ports to keep debris suspended in front of the pig.

7.2.5 Brush pigs Brushes are mounted on spring loaded arms or installed as circular components. The arms of brush pigs are configured so that the brushes maintain contact on the pipe wall throughout the entire pig run (Figure 7.7). Brushes attached to mandrel pigs are more effective than those attached onto poly-pigs, because in the mandrel configuration the amount of bypass is reduced by using drive cups both in front and behind the brushes. Brush pigs may be specially configured to clean inside pits (Figure 7.8). Brushes are designed to conform to the inner diameter of the pipeline. The wires are configured to act as spring (forcing itself

7.2 Pigging

FIGURE 7.6 Photos of Typical Mandrel Pigs.5

FIGURE 7.7 Photos of Typical Brush Pigs.5

367

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FIGURE 7.8 Photos of Typical Brush Pigs for Cleaning Inside Pits.5

into the pits) and as scraper. These pigs enable corrosion inhibitors to subsequently reach and protect the surface by effectively removing the debris and loosely adhering substances from inside surface of the pits. In order to perform this task effectively, the brushes should reach the bottom of the pits and remove the materials; otherwise underdeposit corrosion may occur. However, the effectiveness of brush pigs in cleaning pits depends on the size and shape of the pits; the brushes may not effectively reach the entire surface of pits with narrow openings.

7.2.6 Plow blade pigs Plow blade pigs are designed to remove soft waxy internal deposits. They are not as aggressive as a hard disc, but could remove large quantities of wax and plug from the pipeline. The effectiveness of plow blade pigs depends on the strength and amount of extension of the cantilevered steel arm (Figure 7.9). Individual plows or blades can be replaced as they are worn out. When wax or paraffin solvents are used along with the cleaning pigs, the suitability of materials used in plows or blades should be evaluated.

7.2.7 Bidirectional pigs Bidirectional pigs are fabricated as discs so that they can be run in either direction (Figure 7.10). They are useful when the pipeline geometrical condition is not known. When they become stuck at dents, buckles or other restrictions, their direction can be reversed to retrieve them. Bidirectional pigs are used to clean the pipeline, to apply batch corrosion inhibitors, to separate the products, and to displace water after hydrotesting.

7.2.8 Pin wheel pigs Pin wheel pigs are designed for aggressive removal of scale or hard wax. The hard pins are fabricated from steel or tungsten carbide and are attached to polyurethane discs (Figure 7.11). The pins scrape or

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369

FIGURE 7.9 Photos of Typical Plow Blade Pigs.5

burst the deposits from the inner wall of the pipeline. The aggressiveness of the pig depends on the length of the pin, number of pins, and materials of construction. Pin wheel pigs should be used with caution, because improper sizing could damage the wall of the pipeline. Aggressive application of pin wheel pigs may result in the production of large amounts of debris, which may block the pipeline.

7.2.9 Multi-diameter pigs Multi-diameter pigs are used to pig a pipeline which has a varying diameter (Figure 7.12). There are several types of multi-diameter pigs: Butterfly discs: Butterfly discs use two out-of-phase discs with V-shaped cutouts to allow the gaps to be filled. The seal is not that satisfactory, but can be improved by adding a thin urethane membrane at the rear of each assembly. Petal flappers: Petal flappers comprise of a complete circle of individual blades which overlap each other to form a seal. They are more efficient than butterfly discs, but still do not form an adequate seal against the wall of the pipe. The seal can be improved by adding a thin membrane at the rear of each sealing assembly.

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FIGURE 7.10 Photos of Typical Bidirectional Pigs.5

Standard discs: Standard discs are only suitable for small diameter changes. In this configuration, two sizes are used: one size suitable for the larger diameter pipeline and another size suitable for the smaller diameter pipeline. When the pig is in the large diameter pipeline, the smaller seals do not contact the pipe wall. When the pig is in the smaller diameter pipeline, the large seals bend back and the smaller seals contact the metal surface. The large seals are generally worn badly while traveling through smaller diameters, and therefore this configuration is only useful when pigs travel from the larger to the smaller diameter pipeline.

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371

FIGURE 7.11 Photos of Typical Pin Wheel Pigs.5

FIGURE 7.12 Photos of Typical Multi-Diameter Pigs.5 (A) Butterfly Pig (B) Petal-Flapper Pig.

Foam pigs: These are inherently soft and light; hence can negotiate through different diameter pipelines. However they may turn in the pipeline, they may enter branch connections, they may tear badly, and may even disintegrate.

7.2.10 Bypass pigs The bypass pig is used in pipelines where there is expected to be a large quantity of loose debris present. The pig is fitted with a number of internal valves which are pre-set to open at a required pressure. The pig performs like a standard pig until such time that it accumulates large amounts of debris. This establishes a large pressure differential across the pig, which in turn opens the bypass valve. The resultant jet of product flushes away the debris (Figure 7.13). Removal of debris drops the differential pressure across the pig causing the valve to close. This process repeats as the pig travels along the pipeline.

7.2.11 Gel pigs Gel pigs are a series of gelled liquids (Figure 7.14). Most pipeline gels are water-based, but certain chemical-based gels are also available (Figure 7.15). The gels are pumped through the

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FIGURE 7.13 Photo of Typical Bypass Pig.5

line fill Drive Fluid

Separator Gel

Debris Gel

FIGURE 7.14 Photo of Typical Gel Pig Train.5

FIGURE 7.15 Photo of Typical Gel Material.5

Debris Gel

Debris Gel

Separator Gel

7.3 Drying

373

pipeline, either alone or in conjunction with conventional pigs. Depending on the application, there are three types of gel pigs: batching or separator gel, debris pickup, and dehydrating gel. Gel pigs do not wear out unlike conventional pigs, but are susceptible to dissolution in fluids. Therefore, when a pig train incorporates gel pigs, bypass of fluid across the pig train is minimized.

7.2.12 Special pigs Sometimes cleaning pigs get stuck in a pipeline. To locate where the pig is stuck, a special pig, known as transmitter pig is used. This pig is fitted with a transmitter in its body which emits a signal to indicate its location. A transmitter pig is normally mounted onto a mandrel, cast, or poly pig. Sometimes magnets are fitted onto the pig to pick ferrous debris from the pipeline. These pigs are known as magnetic cleaning pigs.

7.3 Drying If the hydrocarbons contain water (e.g., wet-gas and water-in-oil emulsion) water will drop out during operation. Removal of water decreases the tendency of the pipeline to corrode. Drying is especially important after hydrotesting and leak testing of gas transmission pipelines. Sometimes it is assumed that oil will displace the water; however as discussed in section 4.3, not all types of oil have the tendency to displace water. Therefore, drying is also important for oil transmission pipelines. A pigging operation may remove most of the water but not all. To completely remove the residual water from the system, additional drying may be necessary. Some of the drying processes used include injection of glycol or methanol, air drying, vacuum drying, and purging with nitrogen.

7.3.1 Injection of glycol or methanol Glycol and methanol dissolve water and can effectively remove the residual water.

7.3.2 Air drying Air drying is used to remove free water. This drying process is relatively short, but large equipment is required in this process. Introducing oxygen into an environment with even traces of free water would result in high rates of corrosion (see section 4.7). This process is not suitable for the offshore industry.

7.3.3 Vacuum drying When the pressure is reduced, water will boil and evaporate at a lower temperature; this principle is used in the vacuum drying process. Figure 7.16 presents a typical vacuum drying pressure curve.8 The vacuum drying process takes place in three stages:

CHAPTER 7 Mitigation – Internal Corrosion

Pressure (mmbara)

374

Evacuation Evaporation Drying

Drying time (days)

FIGURE 7.16 Typical Vacuum Drying Pressure Curve.8 Reproduced with permission from Elsevier.

Evacuation phase: Boiling phase:

Drying phase:

the pressure is reduced from atmospheric pressure. when the pressure approaches the saturated vapor pressure water starts to boil and evaporate. This phase continues until all water has evaporated. During this phase, the pressure remains relatively constant, as more and more water evaporates to compensate for the pressure loss due to boiling. Evaporation of water involves heat transfer between pipe and the surrounding. An appropriate vacuum pump is selected so that the rate of heat transfer from the surrounding to the pipe is equal to the rate of water evaporation; otherwise ice may form inside the pipeline. when all free water has evaporated the pressure will start to decrease, as the air in the system evacuates.

The vacuum drying process removes all free water from the system without using large equipment. But the process is slow, therefore is not suitable for long pipelines.

7.3.4 Purging with nitrogen After drying, the pipeline is purged with inert gas (usually nitrogen) to ensure that the system is dry, and to provide a barrier against explosion before introduction of hydrocarbons. Hydrocarbons may be introduced immediately after vacuum drying, but in some situations this may not happen; it may be several days or even months before the pipeline is put into service. Introduction of nitrogen provides an additional safety margin against explosion.

7.4 Corrosion inhibitors A corrosion inhibitor is a chemical substance which, when added in small concentrations (typically less than 100 ppm) to an environment, minimizes corrosion. An efficient inhibitor is compatible with

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Classification of corrosion inhibitors

Interface inhibitors

Environmental conditioners

Liquid phase

Vapour phase

Anodic (Passivators)

(Cathodic)

Mixed (adsorption)*

*(Most inhibitors used in the oil and gas industry are of this type)

FIGURE 7.17 Classification of Corrosion Inhibitors.10

the environment, is economical for application, and produces the desired effect when present in small concentrations. Control of internal corrosion by the application of corrosion inhibitors in production, transportation, and refinery sectors of the oil and gas industry is the most trusted, time-tested, and proven method; without corrosion inhibitors economical operation of these sectors using carbon steel is impossible.9 Figure 7.17 presents a general classification of corrosion inhibitors10 and Table 7.4 presents some of their characteristics. In order for chemicals to serve as good corrosion inhibitor, they have three basic structural requirements: an anchoring group, a backbone, and a substituent group (Table 7.5).11 The corrosion inhibitor attaches onto the metal surface through its anchoring groups. The anchoring groups invariably contain one or more heteroatoms, such as nitrogen (N), sulfur (S), phosphorous (P), or oxygen (O). If this group adheres strongly onto the metal surface, it increases the strength of corrosion inhibitors. Table 7.6 presents some common examples of anchoring groups.12 The anchoring groups attach to the backbone of the organic molecule. The bulkier the anchoring group, the greater is the area of coverage of inhibitor molecule. Table 7.7 illustrates how increasing the bulkiness of the corrosion inhibitors decreases the concentrations needed to produce the same efficiency.13 The backbone may contain additional substituent groups, to enhance the bonding strength of the anchoring group to the metal, and to enhance its surface coverage. Corrosion inhibitors used in the oil and gas industry are organic, polar, surface active molecules. Most are derivatives of amines or amine salts. They need to be able to interact with several interfaces, including oil-water, water-gas, oil-gas, metal-oil, metal-water, and metal-gas. In order for a corrosion inhibitor to be effective it should partition predominantly to the water-metal (to expel water phase from the metal surface) and they must exist in higher concentrations at interfaces than in the bulk. For this reason they are often classified in terms of their solubility as: oil soluble-water insoluble; oil

Table 7.4 Characteristics of Different Types of Corrosion Inhibitors

Mechanism

Interface

Liquid

Anodic

Precipitation at the anodic sites

Cathodic

Poison cathodic reaction

Precipitation at cathodic sites Mixed

Physical adsorption

Chemical adsorption

Characteristics • • • • • •

• • • • • • •

•

Film forming

• • •

Vapor

Mixed

Chemical adsorption

• •

Environmental conditioners

• •

Reinforces the passive layer on the metal. Effective only on metals (e.g., CRAs) have passive layer. They are normally effective in near neutral solutions. At insufficient concentrations accelerate corrosion. Controls cathodic reaction (normally hydrogen). They may increase susceptibility of metals to hydrogen effect (see section 5.18) by preventing recombination of hydrogen atoms to form hydrogen molecule. These inhibitors are mostly inorganic salts and are effective in alkaline solution. Precipitates at the cathodic sites to effect inhibition. Physically block the metal surface from contacting the environment. No other specific interaction with metal surface. Not specific and rapid. Effective only for a short duration. Chemical adsorption (often known as chemisorption) is the specific chemical interaction between corrosion inhibitor and the metal surface. The bond formed in chemisorption is stronger than that forms in physical adsorption. Therefore the chemisorbed inhibitors are effective. Chemisorbed inhibitor may undergo chemical reaction on the metal surface forming protective films. Corrosion protection increases as the films form, grow, and adhere on the surface. Most of the corrosion inhibitors use in oil and gas industry either chemisorb or form film on the metal surface. Vapor phase inhibitors are normally used to temporarily protect the metal surface in a closed environment. Chemicals that have low but significant vapor pressure and whose vapors adhere well on to the metal surface are successful vapor phase inhibitors. The decrease corrosivity of environment by scavenging corrosive species from the solution. Common species scavenged by inhibitors is oxygen.

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Class

Phase in Which Corrosion Inhibitors Present

376

Type of Interaction of Corrosion Inhibitors to Control Corrosion

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Table 7.5 Constitution of an Organic Corrosion Inhibitor11 Anchoring Groupa

Backbone

Substituent Groupa

• Binds onto the metal

• Bears anchoring and substituent groups • Provides surface coverage

• Supplements electronic strength and surface coverage

a Anchoring and substituent groups are interchangeable, i.e., the substituent group through which the inhibitor anchors onto the metal surface depends on the electron density, charge on the metal, and orientation of the molecule in a particular environment

Table 7.6 Some Anchoring Groups in Organic Corrosion Inhibitors12 Name of the Anchoring Group

Structure

Hydroxyl Epoxy Amine Carboxylic Amino Imino Nitro Triazole Amide Thiol Sulphide Sulphoxide Thio Phospho Phosphate ester Phosphonium Quaternary ammonium (quat)

-OH -C-O-C-C-N-C -COOH -NH2 -NH -NO2 -N¼N-N-CONH2 -SH -S -SO -C¼S-P-P-O3-R -PO-NR4

Table 7.7 Concentration of Substituted Thioureas Required to Produce 90% Inhibition13 Inhibitor

Chemical Structure

Concentration (mol/L)

Molecular Weight

Thiourea Allyl thiourea N,N-Diethyl thiourea N,N-Diisopropylthiourea Phenyl Thiocarbamide Symdiotolylthiourea

H2N-CS-NH2 H2N-CS-NH-CH2CH¼CH2 C2H5HN-CS-NHC2H5 C3H7HN-CS-NHC3H7 H2N-CS-NH-C6H5 C6H5HN-CS-NHC6H5 CH3C6H4HN-CSNHC6H4CH3

0.1 0.1 0.003 0.001 0.001 0.0006 0.0004

76.13 116.19 132.23 160.28 152.21 223.38 256.35

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soluble-water dispersible; oil dispersible-water dispersible; oil insoluble-water dispersible; oil insoluble-water soluble; water dispersible; water soluble; soluble in packer fluids (containing calcium chloride [CaCl2] and calcium bromide [CaBr2]); and soluble in aromatic solvents. Most corrosion inhibitors are dispersible either in oil or water or both. The film persistency of the corrosion inhibitors depends on their solubility or dispersibility in the fluid. In practice, corrosion inhibitors are seldom pure substances but are mixtures containing active ingredients for inhibition, biocides, hydrate inhibitors, wax inhibitors, and asphaltene inhibitors, surfactants, emulsifiers, antifoaming agents, carriers (solvents; aliphatic or aromatic), water, alcohol, and other chemicals. A commercial inhibitor package provides a percentage of active ingredients that constitute corrosion inhibitors.

7.4.1 Selection of corrosion inhibitors Users of corrosion inhibitors often face the task of selecting the best-performing chemical for a particular application in a rapid and cost-effective manner. The selection of corrosion inhibitors consists of three steps: 1) Evaluation of inhibitor efficiency, 2) Evaluation of secondary inhibitor properties, 3) Ranking of corrosion inhibitors based on inhibitor evaluation, secondary inhibitor properties, and other considerations including cost.

7.4.1a Inhibitor efficiency The selection of corrosion inhibitor starts with a laboratory evaluation, followed by testing in the field. Several laboratory methodologies are available to simulate field operating conditions. Based on experiments carried out using a loop in three field pipelines under 17 operational conditions, with six inhibitors (three continuous and three batch) and based on laboratory experiments carried out under field conditions using the same inhibitors at the same concentrations, a study has ranked the laboratory methodologies in terms of their ability to simulate field operating conditions (Table 7.8).14 Section 8.2.2a presents characteristics of laboratory methodologies. An ideal test should reproduce all the relevant parameters of the intended application, including pressure, temperature, compositions (steel, solids, liquid, and gases), and flow. These parameters are broadly divided into two categories: direct and indirect. Direct variables are composition of material, composition of gas and liquid (oil and water), temperature, and pressure; simulation of these variables in the laboratory is direct. Flow, on the other hand, is an indirect variable; simulation of flow in the laboratory is not direct. To simulate the effect of flow, the hydrodynamic parameters are first determined, and the laboratory corrosion tests are then conducted under the calculated hydrodynamic parameters. The fundamental assumption in this approach is that when the hydrodynamic parameters in field and laboratory methodologies are the same, the corrosion rates (and hence, the inhibitor performance) are similar. The hydrodynamic parameter most commonly used to simulate the flow is wall shear stress. Section 4.2 describes the methods to determine the wall shear stress of a pipe and section 8.2.2a describes the methods to determine wall shear stress in laboratory methodologies. Table 7.9 presents appropriate laboratory methodologies to simulate different wall shear stresses.15

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Table 7.8 Ranking of Laboratory Methodologies in Terms of their Ability to Simulate Field Operating Conditions14 Laboratory Methodology

Relative Ranking

Rotating cage

10 (highest ranking; simulates field operating conditions well) 9 8 7 6 5 4 3 2 (Lowest ranking; inadequately simulates field operating conditions)

Rotating Cylinder Electrode Jet Impingement Rotating Disc Electrode Rotating probes Bubble (Kettle) Wheel test Static Others

To simulate the direct variables, laboratory experiments are carried out under the same field operating conditions, i.e., at the temperature of the field, using coupons or electrodes fabricated from materials used in the field; at the pressure of the field using a gas mixture of same composition as that in the field for atmospheric experiment and of same partial pressures as that in the field for high pressure experiment; and using fluids from the field, or using synthetic fluids of composition same as that of field fluids.

7.4.1b Secondary inhibitor properties The secondary properties of inhibitors which are evaluated include water/oil partition, solubility, emulsification tendency, foam tendency, thermal stability, toxicity, and compatibility with other additives and materials.

i Oil-water partition To control corrosion the inhibitors must reach the aqueous phase. In the presence of aqueous and hydrocarbon phases, the inhibitors may partition and disperse between them. As a consequence, the effective concentration of inhibitors in the aqueous phase is reduced. To test the ability of corrosion Table 7.9 Effective Range of Laboratory Methodologies in Simulating Pipe Flow Conditions15 Laboratory Methodology

Wall Shear Stress, Pa

Jet Impingement Rotating Cage Rotating Cylinder Electrode Rotating Disc Electrode Kettle (Static) test

> 200 20 to 200 5 to 20 1 to 5 0

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inhibitor to partition or disperse between water phase and hydrocarbon phase, it is allowed to distribute between a hydrocarbon phase and an aqueous phase over certain period. After that the aqueous phase is separated from the hydrocarbon phase and the corrosivity of the aqueous phase is measured using one of the laboratory methodologies described in section 8.2.2a. The corrosivity of the aqueous phase is also determined by directly injecting the inhibitors into it. By comparing the results, the partition coefficient of the inhibitor (Pi) is calculated. Standards providing guidelines for determining the partition coefficients of corrosion inhibitors include: •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’

ii Solubility The inhibitors are dissolved in appropriate fluids (aqueous or liquid hydrocarbons) and the resultant solution is stored. Depending on the application and environment, the inhibitor solution may be stored for between 1 to 30 days at temperatures between 20 C and 30 C. During storage no change to the inhibitor solution should occur, i.e., no precipitation or phase separation. Solid particles formed during storage of corrosion inhibitor solution are commonly known as gunks. To determine the stability of the inhibitor solution, an appropriate concentration of the corrosion inhibitor is dissolved in the fluid and the solution is observed for at least two weeks. Formation of cloudiness or any change in appearance of the fluid is considered as an inhibitor solubility change. Since the solubility of inhibitors can vary quite drastically depending on the chemical composition of the water and hydrocarbon phases, the test is performed using actual field fluids, if possible. Standards providing guidelines for determining the solubility of corrosion inhibitors include: •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’

iii Emulsification tendency Inhibitors are surface active chemicals and hence may facilitate the formation of an oil-water emulsion. Some emulsions can be quite difficult to separate. To determine the emulsion-forming tendency of a corrosion inhibitor, aqueous and hydrocarbon phases containing corrosion inhibitors are stirred together, and the appearance of the phases and interfaces are observed. The ratio of water and oil depends on the field water and oil ratio. Alternatively various ratios of oil and water may be tested. Ideally, both water and hydrocarbon are obtained from the field for which the inhibitor is being evaluated. Table 7.10 presents some typical results.16 Standards providing guidelines for determining the emulsification tendency of corrosion inhibitors include: • •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’ ISO 6614, ‘Petroleum Products: Determination of Water Separability of Petroleum Oils and Synthetic Fluids’

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Table 7.10 Example of Presentation of Emulsion Test Results in the Presence of Corrosion Inhibitors16 Aqueous Phase

Hydrocarbon Phase

Interface

Time, min

Appearance

Volume, mL

Appearance

Volume, mL

Height, cm

5 15 30 60 1 day

Hazy Hazy Hazy Hazy Clear

10 20 30 40 50

Hazy Hazy Clear Clear Clear

10 20 30 40 50

5 1 Firm Firm Firm

iv Foaming tendency Corrosion inhibitors may foam certain solutions. This tendency is determined by spurging a gas through a glass frit into a solution containing the corrosion inhibitor. The foam height and stability are determined, and compared with that of a solution without the corrosion inhibitor. Standards providing guidelines for determining the foaming tendency of corrosion inhibitors include: • •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’ ISO 696, ‘Surface Active Agents – Measurements of Foaming Power: Modified Ross-Miles Method’

v Thermal stability The temperature has an effect on the efficiency of the inhibitor and on the stability of blends. Several tests used to evaluate thermal stability are described in the following sections. Sticky Deposits Test: Sticky deposits might form either due to thermal decomposition of inhibitor blends or due to evaporation of solvents. To evaluate the susceptibility of inhibitor blends to form sticky deposits, they are mixed with sandstone and bentonite from the field and heated (to the anticipated operating temperature of the field) in an oven for at least three days, cooled, and the observed for consistency, deposits, and viscosity change. Downhole Stability Test: In this test, the inhibitor blends are heated and maintained at the field operating temperature for at least four days in an autoclave and then subjected to inhibitor efficiency tests (see section 8.2.2a). The efficiency of the inhibitor is compared with that of inhibitor subjected to the test without preheat. Alternatively, after four days of heating, the chemical composition of inhibitor is analyzed using gas or liquid chromatography, infrared spectroscopy, mass spectroscopy, or other suitable analytical techniques. This test is normally used only for inhibitors that will be used to control the corrosion of downhole tubulars (see section 2.4). Glycol Test: This test is used to evaluate the compatibility of the corrosion inhibitor with glycol at higher temperatures. In this test, corrosion inhibitor (1,000 mg/L or 20 times the recommended concentration in the field) is dissolved in a 50/50 volume/volume solution of glycol and aqueous phase. The resultant solution is purged with a gas mixture containing methane, CO2, and/or H2S – composition depending on field – and heated in a refluxing condenser at around 135 C for five days. The performance of the corrosion inhibitor is then evaluated in a foam test (see section 7.4.1b.iv).

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vi Toxicity/environmental friendliness Different evaluating practices have been developed in various parts of the world to evaluate the environmental suitability of corrosion inhibitors; some of them are discussed in this section. Paris commission (PARCOM). The Paris Commission (PARCOM) developed guidelines to protect the North Sea marine environment from the activities of the offshore oil industry. These guidelines provide procedures for evaluating and testing corrosion inhibitors and chemicals based on environmental testing, and a model to analyze the data. Environmental testing: Environmental testing includes evaluation of toxicity, biodegradation, and bioaccumulation. The toxicity of the corrosion inhibitor blends to marine species is evaluated. The toxicity can be measured either in terms of LC50 or EC50. The EC50 is the effective concentration of chemical required to adversely affect 50% of the species, and LC50 is the concentration of chemical required to kill 50% of the species. EC50 is lower than LC50, hence EC50 is often a more sensitive criterion than LC50. The marine species used in the test include algae (primary producers), fish, crustacea (consumers) and seabed worms (decomposers or sedimentary reworkers). A 28 day environmental test is conducted to evaluate the biodegradation of the inhibitor in the environment. Bioaccumulation is evaluated based on the partition of the inhibitor between octanol and water. The results are expressed as the logarithm of the octanol/water partition coefficient (logPo/w). Standards providing guidelines to evaluate bioaccumulation includes: Organization for E Economic Co-Operation and Development (OECD) - Test No. 117, “Partition Coefficient (n-Octanol-water), HPLC Method”. The acceptance criteria for inhibitors for North Sea application are as follows: Toxicity: Biodegradability: Bioaccumulation:

EC50 and LC50 > 10mg/L to North Sea species. Greater than 60% in 28 days. log(Po/w) is less than 3.

Chemical Hazard Assessment and Risk Management (CHARM) Model: PARCOM further developed a model to compare different products based on environmental impact. This is known as the Chemical Hazard Assessment and Risk Management (CHARM) Model. It consists of four modules: Pre-screening, Hazard Assessment, Risk Analysis and Risk Management.

Pre-screening:

Hazard Assessment:

Risk Analysis: Risk Management:

In the pre-screening process inhibitors are classified based on toxicity, biodegradation, and bioaccumulation into four categories: permitted; given temporary permission of limited use; subject to continuing evaluation; and replacement required. The hazard of an inhibitor is estimated from the ratio of ’Predicted Environmental Concentration’ (PEC) to ’No Effect Concentration’ (NEC). If this ratio is less than or equal to one, the ecosystem is safe in the presence of the inhibitor. The NEC values are obtained from PARCOM toxicity data. The PEC is based on the release and subsequent dilution of the chemical from a realistic, worst case oil and gas platform model. The probability of occurrence of harmful effects is estimated. Measures to reduce the risk of harmful effects are identified. Such measures include target setting, which may involve principles of Best Available Technology (BAT) and Best Environmental Practice (BEP). Risk Management also allows the comparison of alternative chemicals, treatment rate, and cost effectiveness.

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383

Norway scheme. The Oslo Paris Commission (OSPARCOM) developed measures to evaluate the environmental effects of corrosion inhibitors for Norway. Many countries consider that there is no bioaccumulation of products with molecular weight (MW) greater than 600. The Norway Scheme does not accept this consideration, and classifies corrosion inhibitors as per the following specifications: • • • •

Biodegradation Biodegradation Biodegradation Biodegradation

less than 20%, log(Po/w) greater than 3 and MW less than 600 is between 20 and 50% and log(Po/w) greater than 3 between 50 and 70% and log(Po/w) greater than 3 less than 20%

United Kingdom scheme. The UK Government introduced its own voluntary guidelines on how to implement the PARCOM data. This is known as the UK notification. In the first step of this scheme, an inhibitor that does not meet the following conditions is rejected: • •

Product contains knowingly added substances on OSPARCOM Annex A, or known carcinogens, mutagens, or endocrine disrupters. Biodegradation less than 20%, log(Po/w) greater than 3 and MW less than 600.

The scheme then assigns environmental impact rating from A to E based on the toxicity; E is for the lowest environmental impact and A is for the highest. The rating based on toxicity is adjusted based on biodegradability and the partition coefficient: • • •

If the biodegradability is greater than or equal to 60%, the rating is moved to a lower category. If the biodegradability is greater than or equal to 20% or the log(Po/w) is greater than 3 (and molecular weight is less than 600), it is moved to a higher category. If it is possible to move in both directions, the worst case is taken.

The inhibitors are color coded based on CHARM model (Table 7.11).17 United States scheme. The USA scheme categorizes corrosion inhibitors on the basis of region and ‘Critical Dilution Factor’ (CDF). The CDF is based on discharge pipe size and depth, volume of water, and sea depth. A seven day test is then conducted at an inhibitor concentration determined based on the CDF dilution factor. At that concentration, the inhibitor must have no effect on mysid shrimp and one type of fish. For existing platforms, the referenced fish is sheep head minnows and for new platforms the referenced fish is silverside minnows. Table 7.11 UK Color Scheme for Categorizing Environmental Friendliness of Corrosion Inhibitors17 Hazard Assessment Based on CHARM Model Category

Minimum

Maximum

Gold Silver White Blue Orange Purple

0 1 30 100 300 Greater than 1000

1 30 100 300 1000

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Harmonized mandatory scheme. In 2002, a Harmonized Mandatory Control System (HMCS) was implemented for discharge of chemicals into the North East Atlantic region. According to the HMCS, the corrosion inhibitor must be more than 20% biodegradable. In addition the inhibitor must meet at least two of the following criteria: • • •

Biodegradation greater than 70% in 28 days Toxicity greater than 10mg/l (LC50 or EC50) Bioaccumulation log (Po/w) less than 3

vii Compatibility with other materials 316 stainless steel. Corrosion inhibitors may come into contact with several others materials, including stainless steel, flexible pipe materials, and weldment. The efficiency of the inhibitors in reducing the corrosion rate of these materials is also evaluated. Elastomers.18 Solvents used in the inhibitor formulations (e.g., amines) may swell or may embrittle elastomers. These materials are therefore tested in corrosion inhibitor solution in an autoclave. Visual change, changes in mass, and tensile strength are analyzed to determine the compatibility between corrosion inhibitors and the elastomers. Umbilical. Flexible umbilicals with non-metallic liners are sometimes used in downhole pipelines or subsea pipelines through which inhibitors may be transported. The compatibility between these non-metallic materials and the corrosion inhibitors should be evaluated. The umbilicals normally operate at approximately 40 F (w4 C), but the compatibility test is performed at elevated temperature to accelerate the interaction. The non-metallic materials are exposed to inhibitor solution for one to three weeks, and the property changes, if any, of the materials are analyzed.

viii Other tests In addition several other chemical and physical characteristics of corrosion inhibitors are evaluated for quality assurance and quality control purposes. Table 7.12 summarizes standard tests used to ensure the quality of the corrosion inhibitors and to evaluate secondary inhibitor properties.

7.4.1c Ranking of corrosion inhibitors Based on laboratory experiments, the efficiency of the corrosion inhibitor is calculated using Eqn. 7.1, and the inhibitor with highest efficiency is selected for field application.   ½C:RŠNo:inhibitor ½C:R:ŠInhibitor  100 (Eqn. 7.1) I:E ¼ ½C:R:ŠNo:inhibitor where I.E. is inhibitor efficiency, (C.R)No Inhibitor is the corrosion rate in the absence of corrosion inhibitor, and (C.R)Inhibitor is the corrosion rate in the presence of corrosion inhibitor. For various reasons, the direct and indirect variables in the laboratory may not be the same as those in the field. The effects of these differences should be considered when determining field performance of corrosion inhibitors based on laboratory experiments. Table 7.13 presents an approach to correct laboratory corrosion rates based on differences in variables in the laboratory methodologies and field operating conditions.

7.4 Corrosion inhibitors

385

Table 7.12 Quality Control and Quality Assurance Tests for Corrosion Inhibitors Properties

Standards

Remarks

Density

ASTM D1217 ASTM D1298

Viscosity

ASTM D88 ASTM D445 ASTM D2170 ASTM D2161

Pour point

ASTM D97 ASTM D5950

Flash point

pH

ASTM D92 ASTM E502 ASTM D3828 ASTM E70

Vapor pressure

ASTM D323

Total acid number (TAN)

ASTM D3339

• Density is reported in the data sheets that are normally supplied with corrosion inhibitors. • In addition to testing the viscosity, the gunking of inhibitors is tested. Chemical gunking may happen when the inhibitor is pumped through umbilical for deep water application. Due to higher temperature the inhibitor may form solid/paste and stick to the surface of the umbilical, stopping the flow. • This test result is used to ensure that the inhibitor is in the liquid form under the field operating conditions (especially at low temperatures). • Flash point is a required parameter in the Materials Safety Data Sheet (MSDS) of corrosion inhibitors. • pH is used to determine packaging and transportation procedures. • This test is used to determine volatile constituents of corrosion inhibitors. • This test is used to determine the acidic constituents of corrosion inhibitors.

Oil-Water partition Solubility Emulsion tendency

ASTM G170 ASTM G170 ASTM G170 ASTM D1401 ASTM G170 ASTM D892 ASTM G170 ASTM G170

Foaming tendency Thermal stability Toxicity/Environmental friendliness Compatibility with other chemicals

Particle size

ASTM G170

National Aerospace Standard (NAS) 1638

• Compatibility of corrosion inhibitors with other inhibitors (scale inhibitors, biocides, paraffin inhibitors, oxygen scavengers, and hydrate inhibitors) and chemicals is required so that the addition of corrosion inhibitors does not cause any side-effects in the field. • Particles may block the flow (especially through tiny tubes used in umbilicals for deep water application); therefore less the particles the inhibitor has better it is.

386

Weighted Score

Effect of

Condition

Flow

(Wall shear stress)field < (Wall shear stress)lab (Wall shear stress)field ¼ (Wall shear stress)lab (Wall shear stress)field > (Wall shear stress)lab (Temperature)field < (Temperature)lab (Temperature)field ¼ (Temperature)lab (Temperature)field > (Temperature)lab

3

(Pressure)field < (Pressure)lab (Pressure)field ¼ (Pressure)lab (Pressure)field > (Pressure)lab

3 2 1

Temperature

Pressure

Remarks Wall shear stress is used to simulate flow effects.

2 1 3 2 1

Increased temperature generally increases the corrosion rate because electrochemical and chemical reactions accelerate. However, the rate of precipitation also increases with temperature; hence, elevated temperatures may reduce the corrosion rate when protective films are formed. For inhibitors that physically adsorb on the metal surface, increasing the temperature increases the corrosion rate because elevated temperatures facilitate desorption. On the other hand, for those inhibitors that chemisorb on the metal surface, the chemical bond strength increases with temperature, and hence, corrosion rate decreases with temperature up to a certain temperature where the inhibitor is degraded. Pressure (or partial pressure of corrosive species) may increase the corrosion rate by increasing the dissolution of corrosive species or protective film, or may decrease corrosion rate by facilitating the formation of protective film on the metal surface.

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.13 Weighted Factors to Account for Differences in the Operating Conditions between Laboratory and Field

H2S partial pressure

(H2S)field < (H2S)lab (H2S)field ¼ (H2S)lab (H2S)field > (H2S)lab

3 2 1

CO2 partial pressure

(CO2)field < (CO2)lab (CO2)field ¼ (CO2)lab

3 2

Oil

(CO2)field > (CO2)lab 1 Although the oil phase is non-corrosive, the presence of the oil phase:

Steel composition Brine composition

H2S decreases the pH when it dissolves in the aqueous phase. The corrosion rate usually increases with increase in H2S pressure (when all other conditions remain constant and there is no film formation). CO2 decreases the pH when it dissolves in the aqueous phase. The corrosion rate usually increases with increase in CO2 pressure (when all other conditions remain constant and there is no film formation).

• Partitions inhibitor into it, thereby reducing the inhibitor concentration in the aqueous phase; • Changes the contact time of the aqueous phase on the pipe; • Changes the wetting behavior of the pipe surface; and/or • Introduces protective compounds that are naturally occurring in the oil. The effect of minor variations in the alloy content may have some limited effect on corrosion rate (see section 3.3.1). Metallic ions affect the corrosion rate, and hence, inhibitor efficiencies for various reasons. Sometimes the solution made in the laboratory (based on the field composition) becomes turbid. Turbidity may have the indirect effect of precipitating salts of the following ions: Naþ, Kþ, Ca2þ, Mg2þ, Ba2þ, Sr2þ and Fe2þ (see section 4.4).

7.4 Corrosion inhibitors 387

388

CHAPTER 7 Mitigation – Internal Corrosion

Equation 7.1 does not include the influence of direct and indirect variables. In addition, it does not include the effect of corrosion inhibitor concentration and the repeatability of the test (see section 12.2.1e). Equation 7.2 provides a more accurate method to rank corrosion inhibitors. ISC ¼

½C:RŠmean þ ½C:R:Šstd: þ ½CostŠ þ ½Concn:Š ½LabŠ þ ½WSSŠ þ ½TempŠ þ ½PressureŠ þ ½H2 SŠ þ ½CO2 Š

(Eqn. 7.2)

Sometimes inhibitors may also be ranked without cost using Eqn. 7.3: IS ¼

½C:RŠmean þ ½C:R:Šstd: þ ½Concn:Š ½LabŠ þ ½WSSŠ þ ½TempŠ þ ½PressureŠ þ ½H2 SŠ þ ½CO2 Š

(Eqn. 7.3)

where ISC is the individual inhibitor ranking with cost, IS is the individual inhibitor without cost, [C.R]Mean is the average or mean corrosion rate in the presence of corrosion inhibitor, [C.R]std. is the standard deviation of corrosion rate (which is a measure of the repeatability of the test data), [Cost] is the cost of corrosion inhibitor per ppm, [Concn.] is the concentration of corrosion inhibitor in ppm, [Lab] is the effect of laboratory methodology (Table 7.8), [WSS] is the effect of wall shear stress, [Temp] is the effect of temperature, [Pressure] is the effect of total pressure, [H2S] is the effect of H2S partial pressure, and [CO2] is the effect of CO2 partial pressure (see Table 7.13 for the values). Inhibitor selection is based on the individual rankings. Often the [C.R]Mean is predetermined to be about 5 mpy. Inhibitors are also ranked including secondary inhibitor properties using Eqns. 7.4 (with cost) and 7.5 (without cost). The secondary inhibitor properties included in the ranking are: solubility, emulsion tendency, foaming tendency, toxicity, biodegradability and bioaccumulation, and compatibility (with stainless steel, elastomers, umbilicals, and flow lines). ISSC ¼

ISS ¼

½C:RŠmean þ ½C:R:Šstd: þ ½CostŠ þ ½Concn:Š ½LabŠ þ ½WSSŠ þ ½TempŠ þ ½PressureŠ þ ½H2 SŠ þ ½CO2 Š þ ½Part:Š þ ½Solu:Š þ ½Emul:Š þ ½FoamŠ þ ½Ther:Š þ ½Toxi:Š þ ½Biode:Š þ ½Bioac:Š þ ½Comp:Š

(Eqn. 7.4)

½C:RŠmean þ ½C:R:Šstd: þ ½Concn:Š ½LabŠ þ ½WSSŠ þ ½TempŠ þ ½PressureŠ þ ½H2 SŠ þ ½CO2 Š þ ½Part:Š þ ½Solu:Š þ ½Emul:Š þ ½FoamŠ þ ½Ther:Š þ ½Toxi:Š þ ½Biode:Š þ ½Bioac:Š þ ½Comp:Š (Eqn. 7.5)

where ISSC is the individual inhibitor ranking with cost and with secondary inhibitor properties, ISS is the individual inhibitor ranking without cost but with secondary inhibitor properties, [Part] is the effect of partition, [Solu.] is the effect of solubility, [Emul.] is the effect of emulsion, [Foam] is the effect of foaming, [Ther.] is the effect of thermal stability, [Toxi.] is the effect of toxicity, [Biode.] is the effect of biodegradation, [Bioac.] is the effect of bioaccumulation, [Comp.] is the effect of compatibility. Table 7.14 presents the weighted scores for these properties. The top-ranked inhibitor is the one that has the lowest individual ranking, i.e., lowest value for ISC, IS, ISSC, and ISS.

7.4.2 Application of corrosion inhibitors Corrosion inhibitors are applied by three methods: batch, squeeze, and continuous: •

In the batch application method, the inhibitor in a carrier fluid is made to contact the surface.

Table 7.14 Weighted Factors to Account for Secondary Inhibitor Properties Weighted Score

Condition

Partition

(Corrosion rate)mean  (Corrosion rate) partition (Corrosion rate)mean > (Corrosion rate) partition

3

Solubility

No change Cloudiness Solid formation Gunk formation Phase separation

3 1 1 1 1

Emulsion

Aqueous phase: Clear Aqueous phase: Hazy Hydrocarbon phase: Clear Hydrocarbon phase: Hazy Interface: Firm Interface: Greater than 1 cm (Foaming)no.inhibitor  (Foaming)inhibitor (Foaming)no.inhibitor < (Foaming)inhibitor

1 0 1

Foaming

1

0

Remarks In oil and gas production, corrosion related problems are invariably attributed to the presence of an aqueous phase. Therefore, in order to prevent corrosion, the inhibitor must be present in the aqueous phase. This is achieved by partition or dispersion of the inhibitor from the hydrocarbon and is enabled by the inhibitor being water dispersible or, more commonly, water soluble. Irrespective of the water solubility of the inhibitor, any factors influence the ability to partition efficiently. The main concerns with regards to the solubility are the loss of solubility of the active ingredients, with the formation of solids of gunks, and phase separation due to changes in solubility. The solubility of corrosion inhibitors in carrier fluids should be assessed at the prospective storage temperature, often ambient to 20 C. No change should occur in the physical state of the inhibitor after storage. Formation of cloudiness, solids, gunk or phase separation indicates that the inhibitor is not stable. The emulsions formed between the water and hydrocarbon phases can be quite difficult to remove and can lead to separation difficulties in production facilities. Shake flask tests are used to evaluate whether the inhibitor will cause the water/hydrocarbon mixture to form an emulsion. The effect of emulsion is determined by observing the nature of the water phase, hydrocarbon phase and the interface between them.

1 0 1 3

Formation of foaming should be evaluated by sparging gas through a glass frit into solution of chemical in wither water or hydrocarbons. The foam height and the stability of the foam are used to assess the degree of foaming. The effect is compared to a blank. (Continued)

7.4 Corrosion inhibitors

Effect of

389

Condition

Thermal stability

(Corrosion rate)mean  (Corrosion rate)thermal.stability (Corrosion rate)mean > (Corrosion rate)thermal.stability

3

Toxicity

LC50 > 10 LC50  10 EC50 > 100 EC50  100

3 1 3 1

Biodegradation

BOD  3 BOD < 3 (LogPo/ w)bioaccumulation  3 (LogPo/ w)bioaccumulation < 3

3 1 3

Compatible with all four Compatible with three out of four Compatible with two out of four Compatible with one out of four Non-compatible with all four

3 3

Bioaccumulation

Compatibility stainless steel, elastomers, umbilicals, and flowlines

1

1

2 1 0

Remarks The effect of the pipeline or flow line inlet temperature on the efficiency of the inhibitor formulation should be evaluated. If the corrosion inhibitor formulation is to be blended with methanol or glycol, and possibly other chemical additives, and stored prior to injection, the stability of this mixture should be investigated, as well as the stability of the inhibitor formulation itself. Even if the corrosion inhibitor formulation is introduced into the methanol or glycol immediately before injection, it is important to test that the resultant mixture viscosity does not increase substantially, and thus, impede pumping. Awareness and concern for the environment will inevitably demand more stringent legislation to regulate discharges into coastal and offshore waters. Environmental concerns world wide are increasing and are likely to influence the choice of corrosion inhibitors in the future. Environmental requirements are still being developed, but some elements have been established. Toxicity is measured as LC50 or EC50. The biological oxygen demand (BOD), is a measure of how long the inhibitor will persist in the environment. The BOD should be less than 60%. Bioaccumulation is a measure of the distribution of the product between an octanol and water mixture. The result is usually expressed as the logarithm of the octanol/water partition coefficient (Log Po/w). A standardized High Performance Liquid Chromatography (HPLC) method is used and this test is done on all the components of the product. An octanol/water partition coefficient greater than 3 is good.

CHAPTER 7 Mitigation – Internal Corrosion

Weighted Score

Effect of

390

Table 7.14 Weighted Factors to Account for Secondary Inhibitor Properties Continued

7.4 Corrosion inhibitors

391

Table 7.15 Types of Corrosion Inhibitors for Various Applications Application Oil wells

Gas wells and gas condensate wells

Continuous inhibition (Capillary injection) Continuous (Through annular space) Squeeze Batch Continuous injection (Capillary injection) Batch Continuous

Gas pipeline Oil pipeline Multiphase Refinery

Batch Batch Continuous Continuous

Oil wells (Lifted by gas)

•

•

Mode of Inhibitor Application

Typical Type of Corrosion Inhibitors Oil soluble-Water Dispersible Water soluble e oil dispersible (if water content is high) Oil soluble Water soluble e oil dispersible (if water content is high) Oil dispersible e water dispersible Oil soluble e water dispersible Oil soluble e water dispersible Oil soluble e water dispersible Oil soluble e water dispersible; Water-soluble e oil dispersible Oil soluble Oil soluble Water-soluble e oil dispersible

In the squeeze application method, the inhibitor in a carrier fluid is squeezed into the formation. The well is shut down for twenty four hours for the chemical to flow into the formation. The squeezed chemical will slowly emerge out from the formation along with crude oil. The frequency of squeeze treatment may be between two weeks and six months depending on the nature of chemical, corrosivity of fluids, and type of formation. In the continuous application method, the inhibitor is continuously injected into the system.

Table 7.15 presents typical types of corrosion inhibitors and modes of applying them in various oil and gas sectors. Experience indicates that an integrated program with both batch and continuous treatments ensures successful application and maintenance of an inhibitor film. Thus for best protection the inhibitor application is carried out in three steps: 1. Batch treatment at a higher concentration of inhibitor (mostly oil soluble) over a short time span to establish initial inhibitor film on the surface. Both field and laboratory studies indicate that the initial phase of treatment impacts inhibitor film persistency and that adsorption of inhibitor onto metal surface may be long at low inhibitor concentrations which may limit formation of stable inhibitor film on the surface. 2. Continuous application at medium concentration to ensure integrity of the inhibitor film on the metal surface. 3. Continuous application at a lower concentration to maintain the inhibitor film on the metal surface. Some characteristics of different corrosion inhibitor application methods are discussed in the following paragraphs. Tables 7.16 through 7.18 present general guidelines for the frequency of batch inhibitor treatment.

392

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.16 Approximate Frequency of Batch Inhibitor Treatment for Oil Producing Wells21 Actual Velocity/Critical Velocity)

Batch Corrosion Inhibitor Treatment Frequency, Months

Less than 0.25 0.25 to 0.5 0.5 to 0.9 Greater than 0.9

3 to 6 2 to 3 1 to 2 Less than 1

)

Critical velocity is the minimum velocity at which erosion starts to occur. API RP-14E provides guidelines to determine the critical velocity (see section 6.6 for more information)

Table 7.17 Approximate Frequency of Batch Inhibitor Treatment for Gas and Gas Condensate Wells21 Actual Velocity)/Limiting Velocity))

Batch Corrosion Inhibitor Treatment Frequency, Weeks

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

16 13 9 8 7 6 5 4 3 2

) Liquid velocity in cubic feet per sec (CFS Liquid) ¼ (barrel of water produced per day þ barrel of oil produced per day)/15,400.)Gas velocity in cubic feet per sec (CFS Gas) ¼ MSCFD (thousands of standard cubic feet per day (R¼Fþ460)/flowing pressure.3060.)velocity in ft/sec ¼ CFS (liquid)þCFS (gas)/pipe area in sq. feet )) For the purpose of determining batch corrosion inhibitor treatment, the limiting velocity is determined as 100/r0.5 where r is the density of production fluids

Table 7.18 Frequency of Batch Treatment Based on Fluid Production Rate21 Barrels of Fluid per Day

Frequency of Batch Application)

Less than 50 50 to 150 150 to 350 35 to 800 More than 800

Monthly Bi-weekly Weekly Semi-weekly Continuous

)

The concentration of corrosion inhibitors in the batch is typically between 25 and 50 ppm depending on the well conditions

7.4 Corrosion inhibitors

393

7.4.2a Downhole tubular batch treatment For applying corrosion inhibitors by batch treatment in a downhole tubular, the production of the well is temporarily stopped. The corrosion inhibitor is pumped into the tubing and is allowed to fall freely to the bottom of the well. The time taken for the inhibitor to reach the bottom of the tubular (commonly known as inhibitor fall rate) depends on the length of the tubular and the viscosity of the corrosion inhibitor. As a general rule, a fall rate of 1,500 feet/hour (457 meters/hour) is maintained. The uniformity of the corrosion inhibitor film on the surface depends mainly on the contact time of inhibitor during batch application. This in turn depends on the inhibitor fall rate. Before being pumped into the tubing, the corrosion inhibitor is diluted with solvent (diesel or condensate) to adjust the viscosity, so that a uniform inhibitor film is formed on the internal surface of the tubular. The well is maintained in shutdown mode for at least one hour after the corrosion inhibitor has reached the bottom of the tubular. Batch inhibitors have been successful to control internal corrosion of downhole tubulars for several years, but this treatment has some disadvantages. To apply batch inhibitors, production must be stopped; the inhibitor film formed on the surface may not be uniform; it is difficult to ascertain that the corrosion inhibitor has reached the bottom of the well; and corrosion inhibitor film does not form on surface of the tubing already covered with a standing column of formation water or fluid (especially the bottom portions). This method is not highly used.

7.4.2b Surface pipeline batch treatment To apply corrosion inhibitors in surface pipelines (production and transmission), the inhibitor is placed between two pigs (see section 7.2) and the pigs are moved along the pipeline applying the corrosion inhibitor. These pigs may also have facility to ensure the inhibitors reach locations where water accumulates, e.g., special arrangements are used to spray inhibitors onto the top of the pipeline where TLC corrosion takes place (see section 5.24).

7.4.2c Downhole tubular squeeze treatment or tubing displacement To squeeze the inhibitor through the downhole tubular, the inhibitor is first dissolved in a suitable solvent (diesel or condensate). The volume of solvent needed is determined from the volume of the downhole tubular. The entire fluid volume, including an appropriate concentration of corrosion inhibitor, is then squeezed down through the downhole tubular into the well. The volume and viscosity of the fluid and concentration of corrosion inhibitor are adjusted such that the corrosion inhibitor has adequate time to contact the metal surface, and to form a film of predetermined thickness. After the fluids have squeezed down the tubular, production by the well starts. The remaining corrosion inhibitor in the squeezed-in fluid adsorbs onto the rocks downhole. During production, the inhibitor continuously desorbs from the rocks, gets carried away by the production fluids, and re-adsorbs onto the metal surface to repair the inhibitor film. The advantages of squeeze treatments are that the loss of production during the application of the corrosion inhibitor is minimized; the inhibitor film is uniformly established; and it ensures that the inhibitor film is formed at the bottom of the downhole tubular. Some disadvantages of squeeze treatment include need for a pump to displace large volumes of corrosion inhibitor, and the possibility of the well being shut down due to the hydrostatic pressure exerted by the squeezed-in fluids. This can happen in low pressure fields.

394

CHAPTER 7 Mitigation – Internal Corrosion

7.4.2d Downhole tubular continuous treatment Inhibitors may be continuously injected using an annular space or capillary injection. The annular space between the tubing and outer casing is filled with corrosion inhibitor by continuously pumping the inhibitor from the surface. An injection valve is placed between the annular space and downhole tubular. This injection valve is opened by increasing the pressure to release inhibitor into the downhole tubular. This method requires a large initial volume of corrosion inhibitor, so it is diluted in a solvent (diesel or condensate). The inhibitor must be very soluble in the solvent. The inhibitor may also be present in the annular space for a longer duration. Therefore the inhibitor must also be stable under high temperature and high pressure conditions. Continuous injection of inhibitor into the downhole tubular with capillary tubing is another effective method to control corrosion. This method of application is normally used in wells with high flow rates. The capillary tube (typically 0.25 to 0.5 inches (w6.4 to 13 mm) in diameter) is strapped onto the outside of the surface of the downhole tubular. An injection system is attached at the end of the capillary tube. The injection system includes a pump capable of injecting the inhibitor into the tube against the operating pressure, a filter to remove any solid materials, and a check valve to prevent backflow of tubing fluids into the capillary tube. When the oil is produced with gas-lifting, special atomizing nozzles may be used to ensure better distribution of corrosion inhibitors in the gas. The inhibitors are used neat, i.e., without dissolving them in solvents. The inhibitor should be stable, non-corrosive to the capillary material, and free of any solid particles which may plug the capillary tube. The advantages of continuously injecting corrosion inhibitors using a capillary tube include the lack of production time loss during the application of corrosion inhibitor, and the delivery of the inhibitor into the bottom portions of the tubular. The disadvantages of continuous injection using capillary tube include the high initial installation cost of installing the injection equipment; plugging of capillary tubes requiring retrieval of them for cleaning; and maintaining a delivery system on the surface to deliver inhibitor.

7.4.2e Surface pipeline and refinery continuous treatment The corrosion inhibitors are continuously injected to protect the internal surfaces of pipelines and refinery equipment. Figure 7.18 illustrates typical injection ports for injecting corrosion inhibitors for this purpose.19 In designing the injection port it is important to ensure that the inhibitor thoroughly mixes with the corrosive phases; otherwise corrosion may occur near the injection ports because some corrosion inhibitors may in fact be corrosive at higher concentrations.

FIGURE 7.18 Typical Injection Ports for Applying Continuous Corrosion Inhibitors in Pipelines and Refinery Equipment.19

7.4 Corrosion inhibitors

395

Corrosion Inhibitors How much is needed?

Impact of Film Thickness on Diffusion 0.8000

Mass Transfer Coefficient, cm/sec

As film thickness 0.7000

increases, diffusion (corrosion) rates

0.6000

decrease 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000 0

1

2

3

4

5

6

7

8

9

10

Liquid Film Thickness, mils

FIGURE 7.19 Relationship Between Diffusion Rate and Corrosion Inhibitor Film Thickness.20

7.4.3 Volume of corrosion inhibitor The amount of corrosion inhibitor required depends on the production rates of oil, water, and gases, and on the surface area of steel to be protected. The volume of corrosion inhibitor required may be calculated using Eqns. 7.6 through 7.9: A (Eqn. 7.6) Vinh ¼ Cinh 16:04  Ainh finh

(Eqn. 7.7)

A ¼ 0:2618  di  L

(Eqn. 7.8)

Cinh ¼

Vinh ¼ 0:01632:

di :L:finh Ainh

(Eqn. 7.9)

396

CHAPTER 7 Mitigation – Internal Corrosion

where Vinh is the volume of inhibitor required in gallons, A is the total internal surface area of the pipeline, Cinh is the concentration of inhibitor, Ainh is the activity of corrosion inhibitor in percentage, finh is the inhibitor film thickness in mil, di is the internal diameter of the pipeline in inches, and L is the length of the pipeline in miles. Various forms of Eqn. 7.9 are used in the industry to calculate the volume of corrosion inhibitor, and some of them are presented in the following paragraphs. Vinh ¼

di :L:finh 60:Ainh

(Eqn. 7.10)

The units are the same as in Eqn. 7.9, except for L which in Eqn. 7.10 is in feet. For batch inhibitor treatment: Vinh ¼ 3:di :L

(Eqn. 7.11)

where di is the diameter in inches and L is the length of the pipeline in miles. Vinh ¼ 31:di :L

(Eqn. 7.12)

where di is the diameter in feet and L is the length of the pipeline in miles. For initial continuous inhibitor treatment: Vinh ¼ 0:431:di :L

(Eqn. 7.13)

where di is the diameter in inches and L is the length of the pipeline in miles. For subsequent continuous inhibitor treatment (film maintenance): Vinh ¼ 0:0431:di :L

(Eqn. 7.14)

where di is the diameter in inches and L is the length of the pipeline in miles. As the inhibitor film thickness increases, the diffusion rate (as indicated by mass transfer coefficient) of species across the film decreases; consequently corrosion rate also decreases. Figure 7.19 presents a general relationship between diffusion rate across the film and inhibitor film thickness.20 From the figure it is clear that a minimum 3 mil (w0.08 mm) of inhibitor film is required to reduce the diffusion rate, and hence the corrosion rate, to a negligible value. A corrosion inhibitor film thickness of 3 mil has been used in the industry for a long time. Based on this criterion, several rules of thumb have been developed; some of which include: 1 pint to 1 quart per MMscf of gas: This rule was established in the 1940s, based on field testing in the USA (one pint is approximately equal to 0.473 liter and one quart is approximately equal to 0.946 liter) and field experience of using corrosion inhibitors in gas condensate wells. From the surface area, amount of inhibitor injected, and inhibitor activity, the calculated targeted inhibitor film thickness is approximately 3 mils. 25 to 50 ppm of corrosion inhibitor: Calculation of field data indicates that, for a targeted inhibitor film thickness of 3 mils, 25 ppm of corrosion inhibitor is numerically equal to 1 pint per MMscf of gas, and that 50 ppm of corrosion inhibitor is numerically equal to 1 quart per MMscf of gas. This method is normally used for wet gas (i.e., gases containing condensate as well as water particles). 1 drum/10,000 ft: One drum of inhibitor in a 10,000 ft (3,000 m) of downhole tubing of diameter 2 7/8’ (w70 mm) produces an inhibitor film of at least 3 mils (0.08 mm) of thickness.

7.4 Corrosion inhibitors

397

One important criterion in applying batch inhibition is the frequency at which the batch treatment should be performed. In general, this depends on the particular field conditions, but in the absence of previous experience it may be determined using the ratio between critical velocity and actual velocity. Tables 7.16 through 7.18 present general guidelines for the frequency of batch inhibitor treatment. The presence of sand or solids, corrosivity of the fluids, and other conditions of the pipeline, flowline, and downhole tubular may warrant higher frequency than those given in the tables.

7.4.4 Inhibitor availability In general, the target corrosion rate in the presence of corrosion inhibitors for temperatures up to 250 F (120 C) is 4 mpy (0.1 mm/y), and for temperatures between 250 and 300 F (120 and 150 C) the target is 8 mpy (0.2 mm/y). At temperatures above 150 C the effectiveness of inhibitors in reducing the corrosion rate is evaluated in laboratory methodologies, and a reasonable target is established from these results. Based on the inhibited corrosion rate and the target life of the equipment, a corrosion allowance is established. The corrosion allowance and the minimum thickness of the equipment required to contain the pressure determine the total thickness of the equipment. Laboratory testing is carried out in the design phase to ensure that the inhibitor decreases the corrosion rate to the target corrosion rate at a given inhibitor concentration (normally between 25 to 50 ppm). During field operation, it is important that the inhibitor is available 100% of time. If this is not the case, the corrosion rate fluctuates between the uninhibited (C.RNo Inhibitor) and inhibited corrosion rate (C.RInhibitor). Equation 7.15 determines the influence of non-availability of corrosion inhibitors on the corrosion allowance (CA): CA ¼ ðAinh time  CNo Inhibitor þ ð1

AÞ  C:RInhibitor Þ  Lfield

(Eqn. 7.15)

where Ainh.time is percentage of time the inhibitor system is available (Ainh.time ¼ 100 indicates that the inhibitor is available all time for the entire duration of the life of the equipment), and Lfield is the design life of the equipment. During design phase, typically the value of Ainh.time is assumed to 95%, which numerically equates to 18 days of inhibited condition during a year. Table 7.19 provides some guidelines in determining availability of corrosion inhibitors.22 For practical reasons, Ainh.time need not be 100, because Eqn. 7.15 does not consider the persistency of corrosion inhibitor. If the events that make inhibitors unavailable can be corrected within the duration of its film persistency, they can be considered as non-events because they do not lead to a higher corrosion rate. For example, if the inhibitor persistency is 10 hours, and if a failed inhibitor injection pump is repaired and back on service within 10 hours, such an event is considered as insignificant.

7.4.5 Other types of inhibitors Corrosion inhibitors are seldom used alone, but rather as a package containing other inhibitors, including biocides (see section 7.5), scale (see section 7.6), wax and asphaltene (see section 7.7), and hydrate (see section 7.8). The influence of these components should be evaluated. Table 7.19 provides some guidelines in determining availability of corrosion inhibitors.22

398

Item

Ainh.time [ 0.95

Ainh.time [ 0.99

Ainh.time > 0.99

Inhibitor demonstrated as suitable for the application Inhibitor injection pumps Back up pumps Check that pump is operating Pump planned maintenance Inhibitor tank levels Report on inhibitor used (or report on compliance with key performance indicators) to responsible corrosion engineer Quarterly manual check on pump injection rate No flow alarm (zero differential pressure across a critical component, or in line flow meters) Liquid samples for analysis of residual inhibitor levels and water chemistry Corrosion monitoring system response time

U

U

U

Standard x Daily manual check

High reliability U Automated alarm

High reliability U Automated alarm

Annual Daily manual check Monthly

Annual Automated alarm Weekly

May be required more often Automated alarm Daily

U

U

U

x

U

U

Monthly

Monthly

May be required more often

Response time such that total number of events x time to respond is < 18 days At least annual manual corrosion measurements

Response time such that total number of events x time to respond is < 4 days On line electrical resistance (ER) probes; response time

Response time is less than inhibitor persistency On line fast response monitoring systems;

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.19 Criteria for Determining the Availability of Corrosion Inhibitors22

1e4 days and daily inhibitor injection concentration

response time 1e24 hrs and 6 hourly inhibitor injection concentration

Desirable

Required

Required

x

x

U

18

4

0e4

Effectively never an issue

Possibly

U

Effectively never an issue

Possibly

U

U

U

U

Monthly review

Weekly review

Daily review

U

U

U

Typical choices for corrosion monitoring equipment and system response times Comprehensive review of uninhibited events Persistency taken into account Allowed days of uninhibited events per year (inhibitor system downtime, taking account of the persistency) Shut in if inhibition system goes down for greater than a defined period of time Check for worst case corrosion in shutdown conditions Identify Operations Technician with responsibility for the inhibition injection system Corrosion Engineering Involvement Key Performance Indicators set for Operations Technicians and Corrosion Engineers

7.5 Biocides 399

400

CHAPTER 7 Mitigation – Internal Corrosion

7.5 Biocides Two common methods to mitigate microbiologically influenced corrosion (MIC) are pigging and biocides. These two methodologies are not mutually exclusive; in fact an integrated program using both of them is the best approach to controlling MIC. Cleaning pigs remove scale, sludge, and other deposits. Otherwise, these solids facilitate MIC by providing surfaces for microbes to survive on, and by preventing biocides from reaching the biofilm. Cleaning also disturbs, destroys, and physically removes biofilms. The application of biocides poisons microbial activity and effectively controls MIC. The effect of biocides depends on various factors, including degree of de-aeration, degree of filtration, presence of solids, salinity, concentration of H2S, pH, temperature, residence time, source of water, and other chemicals.

7.5.1 Types The biocides used in the oil and gas industry can be broadly classified into three types: oxidizing, poisons, and bio-competitive. Table 7.20 provides some commonly used biocides in each class.22 Biodispersants are sometimes also used to augment the efficiency of biocides, and these are also known as bio-penetrants or bio-detergents. They help the biocides by breaking-up microbial aggregates suspended in the water, and by penetrating and dispersing biofilms. Bio-dispersants may be anionic, cationic, or non-ionic and may be used intermittently or continuously.

Table 7.20 Types of Biocides used in the Oil and Gas Industry26 Oxidizing • • • •

Chlorine Bromine Hypochlorite Chlorine dioxide (ClO2)

Poisons • Amines B Quarternary ammonium compounds • Aldehydes B Formaldehyde B Glutaraldehyde B Acrolein • Sulfur-containing B Methylene bis thiocyanate (MBT) B Isothiazolone B Thiocarbamates • Other B Tetrakishydroximethyl phosponium sulphate (THPS) B 2,2-dibromo3-nitrilopropioamide (DBNPA)

Bio-competitive Enhancers • Nitrate • Nitrite • Molybdate

7.5 Biocides

401

7.5.1a Oxidizing biocides As the name implies, oxidizing biocides control MIC by an oxidation process. Chlorine is frequently used, especially in seawater injection systems. When using chlorine, several points should be noted: •

• • • •

Chlorine reacts with oxygen scavengers, corrosion inhibitors, scale inhibitors, and corrosion products; consequently the efficiency of chlorine as biocide decreases in the presence of these substances. Chlorine may react with hydrocarbons to produce chlorinated hydrocarbons which cannot be discharged due to their environmental impact. Chlorine may foul refinery catalysts downstream. Chloride can also cause localized pitting corrosion, especially of CRAs, and crevice corrosion. Chlorine is not effective at higher pH.

In addition to chlorine, ozone, chlorine dioxide, bromine, hypochlorite, hypobromite, hypochlorous ion, and hypobromous ion are also used as oxidizing biocides. Figure 7.20 presents the effective pH range for various oxidizing biocides.23 Oxidizing biocides are effective on planktonic bacteria at lower concentrations, but are only effective at higher concentrations on sessile bacteria. There are two reasons for this phenomenon: an extracellular polymeric substance shields the sessile bacteria within the biofilm and the bacteria within a biofilm develop immunity towards biocides.

7.5.1b Poisons Enzyme poisons or protein denaturants act against specific groups of microbes. For example, bisthiocyanates affect all microbes containing iron in their cytochromes; isothiazolones affect thiols groups in proteins; aldehydes (e.g., formaldehyde) affect both proteins and lipopolysaccharides in the bacterial cell wall; quarternary ammonium compounds (quats) affect the surface structure of individual microbial cells, with the hydrophobic and hydrophilic portions of these biocides enabling them to penetrate the cell walls of the microbes; and anthraquinone interferes with the respiration of sulfate reducing bacteria (SRB), making them incapable of converting sulfate to sulfide.

100 Cl2

% Species

80

Br2

HOCI

HOBr

CIO–

BrO–

60 40 20 0 1

3

5

7

9

11

pH

FIGURE 7.20 Effective Range of Oxidizing Biocides.23 Reproduced with permission from NACE International.

402

CHAPTER 7 Mitigation – Internal Corrosion

7.5.1c Bio-competitive enhancers The third type of biocide acts by a bio-competitive exclusion mechanism. They do not directly affect the microbes of interest, but work indirectly by facilitating the growth of another microbe at the expense of microbes of interest. A common example is the addition of nitrate which encourages the growth of nitrate-reducing bacteria (NRB) at the expense of SRB. Field experience indicates that injection of 0.5 mmol of nitrate for 2.5 to 3.5 months eliminates 0.45 to 0.67 mmol of H2S. NRB compete with SRB for thiosulfate or sulfide as an energy source. NRB grow faster using the same source required by SRB. Therefore the activity of SRB is inhibited. Some SRB, which can reduce nitrate, can however overcome the inhibitory effect of nitrate addition. The advantages of using nitrates include their compatibility with most other chemicals used in the oilfield (corrosion inhibitors, oxygen scavengers, drag reducing agents, scale inhibitors, and biocides); they readily dissolve in water, are biodegradable, and do not bioaccumulate; and they are not regulated as a problem with respect to discharge into environment. However, nitrates may be corrosive. In instances where the addition of nitrates leads to corrosion, nitrites are used. Nitrites inhibit both SRB activity and corrosion. However, nitrites are effective only when SRB do not contain nitrite reductase. Nitrites are less powerful than nitrate, so high concentrations are required.24 A combination of nitrite and molybdates has also been found to be effective in controlling SRB.25

7.5.2 Selection The selection of biocides is similar to that of corrosion inhibitors. The appropriate biocide for mitigating MIC is evaluated and selected using laboratory methodologies, with the type selected depending not only on its efficiency but also on its environmental friendliness. Government regulations govern the residual concentrations of biocides in water discharged from oil and gas industry operations. To meet the regulatory requirements, the water is either chemically treated to remove the biocides or retained in a container until the biocide degrades. In selecting the biocides, compliance with government regulations on the discharge of waste water is considered. Some biocides degrade quickly, whereas others persist for a long time. In general, the environmental friendliness evaluation used for corrosion inhibitors is also applied to biocides (see section 7.4.1). Standards providing guidelines for selecting biocides include: •

NACE 31205, ‘Selection, Application, and Evaluation of Biocides in the Oil and Gas Industry’

7.5.3 Application The application of biocides is similar to that of corrosion inhibitors, and in most cases the corrosion inhibitor package includes a biocide. Corrosion inhibitors may inhibit, accelerate, or have no effect on biocides, so the compatibility between biocides and corrosion inhibitors, as well as the efficiency of the package in controlling MIC and non-MIC are evaluated. Biocides may be applied continuously or by batch treatment. Over the time, bacteria may develop resistance to a particular biocide, and as a consequence their efficiency decline with time. To overcome this issue, two or more biocides are applied alternately. In practice, several biocides are applied alternately or together as a blend so that they control a broad spectrum of microbial activity.

7.6 Scale inhibitors

403

7.6 Scale inhibitors26–28 Section 6.8 discusses the formation of scales. In general, scale formation is controlled by removing or reducing the concentrations of scale forming ions in the aqueous phase. This can be achieved by filtration, ion exchange, reverse osmosis, distillation, and aeration (to remove ferrous ions). If the concentrations of the scale forming ions cannot be reduced, then their scale forming tendency is reduced by the addition of chemicals. The chemicals added to control scale formation are known as scale inhibitors. There are three types of scale inhibitors: thermodynamic, kinetic, and adsorption. Chemicals that form complexes with scale-forming substances, and thereby increase their solubility are known as thermodynamic scale inhibitors. Common examples are phosphonates, phosphoric acid esters, and polyacrylic acid. Phosphonates are frequently used because they inhibit scale formation at very low concentrations; they are stable over a wide range of temperatures and pH values; they inhibit the formation of different types of scales; and their concentration in the formation water is easily detected. The effectiveness of scale inhibitors depends on the solubility of the complexes formed, and on the presence of other ionic species in the solution. For example, sulfonated polymers are effective scale inhibitors even at low concentrations in solutions containing only barium and strontium ions, but their effectiveness decreases in the presence of other ionic species. Normally the presence of ferrous ion poisons scale inhibitors and increases scale formation. Some chemicals that reduce scales by suppressing their growth are known as kinetic scale inhibitors. Some chemicals that control scale formation by preferably adsorbing onto metal surface are known as adsorption scale inhibitors. Adsorption scale inhibitors may also alter the nature of scales, e.g., soft scales that can be easily removed by water washing are formed rather than hard scales. Scale inhibitors may be applied by squeeze treatment or continuously. To control scale in the downhole tubular, scale inhibitors are applied by squeeze treatment; frequently both corrosion and scale inhibitors are applied together. To control scale in cooling water systems, scale inhibitors are continuously injected. In most cases, scale formation is prevented or controlled by scale inhibitors or by other treatment methods, but when the scales form they should be removed. Removing scales is tedious and time consuming, and several methods are used; some of them are described in the following paragraphs. Calcium carbonate, iron sulfide, and oxide scales are often removed by the addition of hydrochloric acid (5, 10, or 15). However hydrochloric acid is corrosive to steel and other metals, so corrosion inhibitors are added to the hydrochloric acid. Reaction between calcium carbonate and hydrochloric acid produces carbon dioxide. Similarly interaction between iron sulfide and hydrochloric acid produces hydrogen sulfide. Formation of these acidic gases increases the pressure in the system and also produces a corrosive environment (see sections 4.5 and 4.6). Ethylenediaminetetraacetic acid (EDTA) is also effective in dissolving scales. The reaction of EDTA with scales is slower than that of HCl, but redeposition of scales does not occur. Scales may sometimes be covered with paraffin or oil; such scales are immune to acid treatment, and addition of surfactant is necessary to remove them. The surfactants penetrate the paraffin or oil film, enabling the acids to dissolve the scales.

404

CHAPTER 7 Mitigation – Internal Corrosion

Scales are also mechanically removed by drilling, by using explosives, scrapping, or water-jetting. The selection of a mechanical method for removing scales depends on the properties, extent, and location of the scales.

7.7 Wax and asphaltene inhibitors Both wax and asphaltene effectively control corrosion because of their hydrocarbon contents. Figure 7.21 illustrates the effect of paraffinic wax and asphaltene in reducing the corrosion rate.29 However, the formation of paraffinic wax and paraffinic asphaltene creates operational difficulties. Paraffins are organic molecules that dissolve in crude oil at higher temperatures under reservoir conditions, but are deposited in pumps, rods, flow lines, and storage tanks where the operating temperatures are relatively low. The factors increasing the probability of paraffin deposition include decrease in the light hydrocarbon contents in the crude oil; slow movement of oil in the flowlines and pipelines; wetting of oil on the surface; and rough surfaces providing anchoring points for paraffin attachment. Chemicals are added to control paraffin deposition. These chemicals are of three types: paraffin solvents, paraffin inhibitors, and paraffin dispersants. Solvents dissolving paraffins are mixtures of organic solvents and surfactants. Some typical paraffin solvents are terpenes, benzene, toluene, and carbon disulfide. The solvents are injected continuously or batch treated to dissolve paraffin from downhole tubular, flow lines, and storage tanks. 1.00 Asphaltenic Paraffinic

0.95

Inhibiting Capacity

0.90 0.85 0.80 0.75 0.70 0.65 0.60 0

10

20

30

40

50

60

70

80

90

% Crude Oil

FIGURE 7.21 Effect of Paraffin and Asphaltene in Controlling Corrosion.29 Reproduced with permission from NACE International.

7.8 Hydrate inhibitors

405

Paraffin inhibitors are chemicals which inhibit the growth of paraffin crystals. They are more effective when applied before formation of the paraffin crystals. They inhibit either by preferably wetting the surface or by entering the paraffin crystals. They are either applied continuously or in batches. The binding element in the paraffin is asphaltene. Paraffin dispersants act on asphaltenes (binding materials) and reduce their ability to bind on the surface. The paraffin dispersants require water for maximum efficiency. They are applied as dispersion in water or injected directly into the water phase in downhole, flow lines, and storage tanks. It should be noted that measures to control wax or asphaltene formation counteract their beneficial corrosion protectiveness.

7.8 Hydrate inhibitors A solid hydrate is formed when gas molecules are trapped in a cage of water molecules under certain pressure and temperature conditions. Section 2.11 describes the formation of hydrates. The formation and dissociation of hydrates are phase transformation reactions (not chemical reactions) and depend strongly on the pressure and temperature. Generally, methane hydrate is formed in the presence of water when the temperature is below 40 F (4 C) and the pressure is above 170 psi (1,170 kPa). In addition to methane hydrate, ethane, propane, CO2 and H2S hydrates may also form. These solid or semi-solid hydrates slow or even completely block the gas flow. The formation of hydrate and its control by the addition of hydrate inhibitors are not related to corrosion, but an understanding of these processes is required, because measures to control hydrate formation (e.g., increase of temperature and addition of chemicals) may increase the probability of corrosion. The formation of hydrates is prevented or controlled in the pipeline by avoiding the presence of water in the pipeline, i.e., by drying the gas to make it free of water; by increasing the temperature above the temperatures where solid hydrate is stable; by decreasing the pressure below the pressure where solid hydrate is stable; and by adding chemicals to dissociate hydrates or to prevent hydrate formation. The chemicals added to control hydrates are known as hydrate inhibitors, which may be classified into thermodynamic inhibitors, kinetic inhibitors, and anti-agglomerates. Thermodynamic inhibitors create conditions which are thermodynamically unfavorable for hydrates formation. The most common thermodynamic inhibitors include monoethylene glycol (MEG), diethyene glycol (DEG), triethylene glycol (TEG), and methanol (MeOH). Diethylene glycol is commonly used because of its low cost and low solubility in hydrocarbons; MEG is preferred where the temperature is below 14 F ( 10 C); and TEG, which has a low vapor pressure, is suitable for injection into gas streams. The exact mechanism of thermodynamic inhibition is not known, but the most convincing theory is that they avoid the formation of hydrates by decreasing their freeze point, i.e., the temperature at which hydrates form is decreased. Although thermodynamic inhibitors are effective in controlling hydrate formation, dissolution of oxygen in them leads to corrosion. Kinetic inhibitors slow down hydrate nucleation. The concentration of kinetic inhibitor needed is less than that of a thermodynamic inhibitor. Kinetic inhibitors are normally polymers or copolymers.

406

CHAPTER 7 Mitigation – Internal Corrosion

Anti-agglomerate inhibitors control the agglomeration (sticking together) of hydrate crystals. Alkylated ammonium (alkyl or dialkyl ammonium halides), phosphonium, or sulfonium compounds are effective as anti-agglomerate inhibitors.

7.9 Internal coatings and linings The internal surfaces of infrastructure are protected from corrosive environments by covering them with three types of coatings: polymeric liners, metallic coatings (cladding), and refractive (ceramic) coatings.

7.9.1 Polymeric liners In the industry the words coating and liners may be used interchangeably, but mostly the word ‘liner’ is prominently used to represent material used to protect internal surfaces, and ‘coating’ is predominantly used to represent material used to protect external surfaces. Internal liners act as a protective barrier between the material and environment. Ideally they are inert in the environment and have low conductivity. Most internal liners are organic polymers.

7.9.1a Constituents A typical polymeric liner consist of binder (a natural or synthetic resin) that binds the constituents together; thinner (a volatile liquid) that spreads the liner during application; a pigment that provides color, promotes hardening, and provides corrosion resistance; and a plasticizer that provides flexibility, elasticity, flow, gloss, adhesion, and resistance to water and solvents. The binder and thinner may sometimes be collectively known as the vehicle. Most liners contain vehicle and pigments, but may or may not contain a plasticizer.

7.9.1b Types Some desirable material properties for liners include adhesion, abrasion resistance, ability to withstand rapid pressure change without blistering or flickering, elasticity to withstand stresses during construction, and ability to withstand welding temperatures. In addition, the liners should possess these properties under the operating conditions of the infrastructure. Typical environments include: sour, sweet, salt, natural gas, crude oil, lubricating oil, ethanolamine, ethylene glycol, solid desiccants, light oil, and moisture air (see Chapter 2 for more details). The constituents of the liners are proprietary; therefore performance tests are used to characterize them. However, they may be classified into some basic types and liners of same type will have similar properties. The properties of six basic types of liners used to protect the internal surfaces of oil and gas infrastructure are summarized in the following section; among them, epoxies and vinyls are widely used.

i Epoxies Epoxy resins are formed by the reaction between bisphenol-A and epichlorohydrin (see section 9.2.3 for more details). They are polymers containing hydroxyl and epoxy functional groups, whose properties depend on the reaction between the functional groups (hydroxyl and epoxy) with other chemicals, such as amino resins, phenolic resins, vegetable oil, and fatty acids. Table 7.21 provides typical properties of epoxy liners.30

Table 7.21 Typical Properties of Typical Internal Liners Property

Epoxy

Vinyl

Phenolics

Operating temperature

• Maximum operating temperature 250 F

• Maximum operating temperature 420 F

Adhesion

• Good adhesion on metallic surface

Abrasion resistance (Taber abraser with 1000 gram CS10 wheel)

• Excellent to rubbing and scuffing

• Decomposes at 375 F • Maximum operating temperature 150 F • Hardness and brittleness increases as temperature decreases • Minimum operating temperature -20 F • Poor wetting and penetration property • Surface must be adequately prepared • 0.7 to 1.5 mils per 1,000 revolutions

Hardness

Flexibility

• Pencil hardness: 4 to 9H • Sward hardness: 33 • Higher than 1014 ohm-cm • Good

• Tough and flexible

Impact resistance

• Good

• Good

Aging

• Good resistance

Resistance to water and moisture

• Absorbs water; w 0.66% by weight

• Good resistance to natural weathering • Absorbs water; w 0.1 to 0.15% by weight

Furans • Decomposes at 220 F

• Good

• Good

• Pencil hardness: 2H • Sward hardness: w40

• Rockwell: M80e130

• 1014 to 1015 ohm-cm)

• 1010 to 1012 ohm-cm • Brittle; may be improved by plasticizers

• 5 mil film on 30-mil steel fails 180 bend test over 1 in. mandrel • Less than 2 inchpounds

• Absorbs water; 10% (Continued)

407

• Absorbs water; 0.1 to 0.2% (ASTM D570)

• Excellent

7.9 Internal coatings and linings

Electrical resistivity

Neoprenes

408

Property

Epoxy

Vinyl

Phenolics

Neoprenes

Resistance to salt solutions

• Good resistance to most salt solutions

• Resistance to 3% NaCl

Resistance to solvents

• Resistant to alcohols, aromatics, and aliphatics

• Excellent resistant to NaCl and CaCl2 solutions • Excellent resistant to methyl alcohol

Resistance to hydrocarbons

• Unaffected by gasoline, diesel oil, lube oil, and other aliphatic hydrocarbons

• Good resistance to most salts of common acids and alkalis as well as to oxidizing salts (ferric, cupric, and mercuric) • Dissolves in aromatic hydrocarbons • Resistant to alcohols and aliphatic hydrocarbons • Resistant to common hydrocarbons (gasoline and some crude oils), animal oil, vegetable oil, and mineral oil at temperatures up to 90 F • Depends on formulation

Resistance to wet H2S gas )

• Resistant to ethyl alcohol

• Resistant to gasoline and lubricating oil

These values are for unpigmented vinyl; addition of pigments lowers electrical resistivity

• Good resistant to gasoline

• Excellent resistance

Furans

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.21 Typical Properties of Typical Internal Liners Continued

7.9 Internal coatings and linings

409

ii Vinyls Vinyl resins are polymers of the vinyl (CH2¼CH2) group; some common vinyl groups are vinyl chloride (CH2¼CHCl), vinyl acetate (CH2¼CHCOOCH3), vinylidene chloride (CH2¼CCl2), and vinyl alcohols (CH2¼CHOH). Polyvinyl chloride (PVC) and polyvinyl acetate are used extensively for corrosion control purposes. The basic properties of the liners are determined by the vinyl resins, but a few properties may be altered by the addition of other chemicals (e.g., primers, plasticizers, or heat stabilizers). Table 7.21 provides typical properties of vinyl linings.30 The liners are formulated as solutions or organogels, and applied by brush, spray, dip, flow, or roller coat. A primer is used to improve the adhesion of the liner onto the substrate.

iii Phenolics Phenolics were the first synthetic resins to be used in paints and varnishes, being first used in 1913. Phenolic resins form from the condensation polymerization of phenols and aldehydes. Figure 7.22 presents the general structure of phenolics.31 Their properties depend on the substituents on the phenol ring, type of aldehydes, aldehyde-phenol ratio, catalysts, reaction temperature, reaction time, and other materials such as resins and alcohols. They undergo a high degree of cross-linking, so are applied by thermosetting methods. Table 7.21 provides typical properties of phenolic resins.

iv Furans Furan resins form from the condensation polymerization of furan. Figure 7.23 presents the general structure of furans.32 The polymerization reaction takes place in the presence of a catalyst and OH

OH CH2

CH2 n

FIGURE 7.22 Typical Chemical Structure of Phenolics.

31

Reproduced with permission from the American Gas Association.

(A)

HC

CH

HC

CH O

(B) HC

CH

HC

C O

CH

HC CH2

C

C O

CH

HC CH2

C

C n

CH2

OH

O

FIGURE 7.23 Chemical Structure of Furan (A) and Typical Structure of Furan Liners (B).32 Reproduced with permission from the American Gas Association.

410

CHAPTER 7 Mitigation – Internal Corrosion

[− CH 2 − CCl − CH − CH 2 −]n

(A) [− CH 2 − C 2 H 3 − CH − CH 2 −]n

(B) FIGURE 7.24 Typical Chemical Structures of Neoprene.33 (A) Unvulcanized natural rubber (B).

produces water as byproduct. Furan films are hard and chemically resistant, but are brittle. Table 7.21 provides typical properties of furan linings. The properties of furan polymers are similar to those of phenolic resins and therefore are usually classified with them.

v Neoprenes Polychloroprenes are commonly known as neoprenes. Figure 7.24 presents typical the chemical structure of neoprenes.33 Structurally they are similar to natural rubber (Figure 7.24), and they may also be vulcanized, i.e., reacted with sulfur to produce an elastic structure. However, sulfurmodified neoprene linings have low resistance to gasoline and other hydrocarbons. The neoprenes are dissolved in suitable solvent (toluene or xylene) and applied by brushing or spraying. The liners form as the solvent evaporates. The evaporation of solvent may take from a few hours to few days.

vi Alkyds Alkyds form from condensation polymerization of polyhydric alcohols (e.g., glycerol) and polybasic acids (e.g., phthalic anhydride). They are durable, tough, adherent, and have good chemical resistance. Their properties vary widely depending on the chemicals added including silicon, amino resins, drying oils, and phenolic resins.

7.9.1c Selection of liners Several combinations of liners are commercially available. Table 7.22 presents some liner materials. It is not possible to select appropriate liners based on chemical constituents, hence performance tests are used. These performance tests can be broadly classified into those which measure physical properties and those which measure chemical properties.

i Physical properties Some commonly used physical properties to evaluate liners are discussed in the following paragraphs. Hardness: Hardness is not a significant property for internal liners, but changes in hardness are used as a convenient tool to determine changes in liner properties. Standards providing guidelines to test hardness include: • •

ASTM D3363, ‘Standard Test Method for Film Hardness by Pencil Test’ ASTM D1474, ‘Method of Test for Indentation Hardness of Organic Coatings’

Table 7.22 Some Commercially Available Liner Materials Principle Pigments

Epoxy

Diethylene triamine

Epoxy

Isopropylamino propylamine Diethylene triamine

• • • • • • • • •

Magnesium silicate Rutile TiO2 Magnesium silicate Rutile TiO2 Red lead Silicates Red lead Silicates Chrome oxide

• • • • • • • • • • • • • • • • • • • • • •

Magnesium silicate Rutile TiO2 Red lead Silicates Mineral filler Ash Chromium oxide Iron oxides Chromates Magnesium silicate Iron oxide Iron oxide Siliceous extenders Iron oxide Zinc chromate Lamp black Zinc chromate Mica Magnesium silicate Rutile TiO2 Red lead Silicates

Epoxy Epoxy

Isopropylamino propylamine 350 F

Epoxy-phenolformaldehyde Epoxy

Polyamide

Epoxy

Polyamide

Epoxy-coal tar

Organic amine

Epoxy Epoxy

Diethylene triamine Diethylene triamine

Epoxy

Diethylene triamine

Epoxy

Polyamide

Epoxy-fatty acid ester

Air dry

Epoxy Epoxy-alkyd

Polyamide Polyamide

Epoxy

Diethylene triamine

Epoxy

Diethylene triamine

Percentage Weight of Pigments (%)

Percentage Weight of Total Solids (%)

39

65

39

65

65

81

65

81

9

40

39

65

65

81

22

72

31 35

70 55

15

58

41

69

20

39

8 41

52 55

39

65

65

81

411

Curing Agent

7.9 Internal coatings and linings

Principle Resin

(Continued)

412

Table 7.22 Some Commercially Available Liner Materials Continued Percentage Weight of Total Solids (%)

None None 19 23

w100 w100 56 36

None None

w100 80

10

39

31 11 40

72 20 65

15 25 8 8

31 40 15 35

• Aluminum

52

w100

Blue lead Mica TiO2 Red lead Mica TiO2

25

49

23

40

Curing Agent

Principle Pigments

Furfuryl alcohol Epoxy-furfuryl alcohol Neoprene Phenolic nitrile

Sulfuric acid 330e500 F Lead oxidce Air dry

Phenol-formaldehyde Phenol-formaldehydepolyamide Phenol-formaldehydepolyvinyl acetate

350 F 400 F

• • • • • • •

Polyester-isocyanate Polyvinyl butyral Alkyd-urea formaldehyde

Air dry Air dry Phosphoric acid

Vinyl chloride-vinyl acetate Poly vinyl chloride Vinyl butyral Poly vinyl chloride-epoxyurea formaldehyde Phenol-formaldehyde-poly vinyl acetate Vinyl chloride- vinyl acetate

Air dry Air dry Air dry 300 F

• Iron oxide • Zinc tetroxy chromate • TiO2 • Zinc chromate • Iron oxide • Red lead • TiO2 • Red lead • Zinc chromate • TiO2

Air dry Air dry

• • • • • •

Air dry

Vinyl chloride- vinyl acetate Air dry

None None Carbon block Iron oxide Read lead None None

CHAPTER 7 Mitigation – Internal Corrosion

Percentage Weight of Pigments (%)

Principle Resin

7.9 Internal coatings and linings

413

Adhesion: Adhesion is a measure of the force per unit area required to remove the liner from the surface. The test provides a qualitative measure of how well the lining persists on the surface. See section 10.2.2a for further discussion and testing of adhesion. However, it is difficult to measure just the forces of adhesion, without the forces of cohesion, toughness, and elasticity. Standards providing guidelines to test adhesion include: •

ASTM D7027, ‘Standard Test Method for Evaluation of Scratch Resistance of Polymeric Coatings and Plastics using Instrumented Scratch’

Flexibility: Liners undergo significant elongation at the bends as well as due to expansion of the pipes when pressurized. A flexibility test is used to evaluate the ability of liners to elongate without rupturing or disbonding. Standards providing guidelines for testing the flexibility of liners include: •

ASTM D522, ‘Standard Test Methods for Mandrel Bend Test of Attached Organic Coatings’

Impact resistance: Resistance to impact is important, especially for liners applied at the mill before installation. Mill-applied liners should withstand tools that may be accidently dropped during construction, welding tools that may be clamped and other equipment that may be wheeled inside the pipeline. The tests presented in section 10.2.2a are typically used to evaluate the impact resistance of liners. Blistering resistance: Formation of blisters significantly weakens the liners due to penetration of liquids and gases between the liner and the substrate. Standards providing guidelines for evaluating the blistering resistance of liners include: •

ASTM D714, ‘Standard Test Method for Evaluating Degree of Blistering of Paints’

Abrasion resistance: Gas and oil being transported may contain entrained solids including sand, debris, corrosion products, dirt, and other particles. These solids may abrade the liner, especially in locations where the direction of flow changes. Standards providing guidelines for evaluating the abrasion resistance of liners include: •

ASTM D968, ‘Standard Test Methods for Abrasion Resistance of Organic Coatings by Falling Abrasive’

Reaction to welding: Mill-applied liners and liners in pipeline undergoing field repair may suffer damage due to welding. The nature and extent of damage depends on the temperature distribution adjacent to welding, rate of welding, thickness of the pipe wall, ambient temperature, and extent of preheat. Most organic liners suffer from the heat of welding in one way or another. The influence of physical properties on the performance of liners depends on the nature of their application. For example, impact resistance is more important for a mill-applied liner than for a fieldapplied liner. Conversely, solid content is more important for a field-applied liner than for a millapplied liner, because the solid content determines the length of pipe lined in one application. In addition to corrosion protection, liners also enhance the flow by decreasing drag. Most liners are smooth; in general the roughness of liners is at least one order of magnitude less than that of metallic materials (e.g., steel). Sometimes relative rankings of the physical properties are used to select an appropriate liner for a particular environment. Table 7.23 provides one such ranking, based on physical properties.34

414

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.23 Relative Importance of Physical Properties of Internal Liners Relative Ranking (%)

Physical Properties Adhesion Impact resistance Abrasion resistance Flexibility Percentage solid content Welding resistance (Negative points) Blistering (Negative points)

Mill Applied Liner e Pipeline Carrying Clean Gas

Field-Applied LinerPipeline Carrying Clean Gas

Field-Applied Liner e Flowline Carrying Well Fluids

50 25 15 10 0 5

60 5 10 5 20 0

50 5 30 5 10 0

15

15

15

ii Chemical properties In addition to physical properties, the liners should be resistant to chemicals that will come into contact with them. Therefore the change in physical properties before and after exposure to such chemicals is determined. Table 7.24 presents some common chemical environments in which the liners are normally tested. It should be noted that the concentrations of chemicals used in the laboratory testing are higher than those experienced in the operating conditions of the oil and gas industry. Therefore some liners which do not perform well in laboratory tests may perform well in the mild operating conditions in the field.

7.9.1d Application The performance of a liner not only depends on its nature, but also on the preparation of the surface before it is applied. Surface preparation removes mill scale, dirt, rust, oil, grease, salts, moisture, weld scale, flux, and slag. The surface may be prepared either by physical or by chemical methods, or both.

Table 7.24 Typical Chemical Environments in which Internal Liners are Tested Chemical Environment in the Laboratory Tests Saturated salt solution Lubricating oil Natural gasoline Tap water saturated with H2S and CO2 at 30 psi partial pressure DEG-MEA-H2S solution

Equivalent Field Conditions Saline water produced with gas Compressor lubricating oil Light hydrocarbons produced with gas Sour and sweet production environments

Chemical agents used to remove acid gases

7.9 Internal coatings and linings

415

Some typical physical methods include wire brushing, impacting, grinding, flame scarfing, and blast cleaning. Chemical methods include acid pickling, solvent cleaning, electrolytic cleaning, emulsion cleaning, and surface conversion. Most commercial cleaning involves a combination of both physical and chemical methods. Preparing the internal surface of the pipe presents unique challenges in which the surface preparation equipment is loaded on some form of a vehicle which is sent through the pipe to prepare the surface. Once the surface is prepared, it is coated with an appropriate lining. Typically there are four methods by which the liners are applied to the metal surface: Chemical reaction: After application, the polymeric material undergoes a chemical reaction within itself or other constituents to form the lining on the surface. The chemical reaction may be facilitated by the presence of catalysts and heat. Liners commonly applied by this process include epoxy resins, formaldehyde condensation resins, urea, urethane, phenolics, triazine resins, and allyl resins. Some typical processing parameters adjusted to produce appropriate liners include drying time (commonly known as curing time), heating, and pot-life (the maximum duration before which the liner should be applied after mixing of ingredients). Solvent evaporation: The polymeric material dissolved in a suitable solvent is applied on the surface, and the liner is formed as the solvent evaporates from the surface. Multiple layers of liners are applied to obtain the desired thickness. Some typical liners applied by this process include thermoplastics, nitrocellulose, vinyl resins, polyacrylates, polymethacrylates, styrene resins, chlorinated rubbers, polyester, polyamides, polytetrafluoroethylene, and polyethylenes. The major disadvantage of this method is the toxicity and flammability of the solvents used. Non-solvent evaporation: This method is used to apply liners of high-molecular weight polymeric materials which are insoluble in common solvents. The polymeric material dispersed in a suitable solvent is applied on the surface and the liner is formed as the solvent evaporates from the surface. If the dispersed medium is aqueous, the process is called latex or emulsion, and if it is an organic medium the process is called orangosol. Some typical liners formed by this process include vinyls, polytetrafluoroethylene, and synthetic rubbers. This method may require application of heat to bake, fuse, and form uniform liners. The major disadvantage of this method is the toxicity and flammability of solvents used. Coagulation or freezing: The polymeric material is melted and sprayed as a hot liquid on the substrate. Alternatively, the substrate may be dipped in the molten resin at a high temperature. The liners are formed when the resins cool and solidify. Many thermoplastics are applied by this process. The liners applied by this method usually have higher chemical resistance but lesser adhesion. The primary disadvantage of this method is the need for special equipment to handle resins in the molten state. Applying liners inside a pipe may pose some unique issues. Most liners are applied in the mill immediately after the manufacture of the pipes. Some typical procedures are discussed in the following paragraphs. The liner may be sprayed on to the internal surface using a spray-head attached to a long hollow stem. The hollow stem is run into the pipe section as the spray-head applies the liner. The liner may also be applied using a centrifugal casting procedure. In this procedure, after preparing the surface, a thick slurry of lining material is sent into the pipe, which is rotated at high speed to spread the liner. For larger diameter pipes (30 to 34 inch (w760 – 860 mm)) boom-mounted spray-heads are used. The pipe is rotated on a roller to apply the liner uniformly. After application of the liner, the pipe may be heated

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to 275–375 F (135–190 C) and kept at those temperatures for 10–15 minutes to fuse and blend the liner on the pipe wall. The liners may also be applied on the internal surface of the pipe after the pipeline has been constructed, by solvent evaporation or other processes. For this purpose, specially designed pigs propelled by air-pressure are used, to transport cleaning solution as well as liner materials. The speed of the pigs is controlled by maintaining proper differential pressure across them. Figure 7.25 presents typical equipment used for this purpose. A typical sequence for applying the liners is described in the following paragraphs. The internal surface of the line is cleaned sequentially with water, solvent, and detergent solution to remove oil and gas from the surface. The water, solvent, and alkaline detergent phases are separated from one another using pigs. Conventional pigs are run to clean the surface. Alkaline solutions are run between pigs to degrease the surface. The line is again washed with water sent between pigs. Inhibited acid solution (hydrochloric acid or phosphoric acid) is run between pigs to clean and etch the surface. The line is again washed with water, containing inhibitors, sent between pigs. The line is then dried either by drying agent (methyl ethyl ketone) or by blowing air. A primer is then applied by sending slugs of material between two counter-facing rubber pigs, against a constant back pressure. The excess primer is removed downstream and the primer is dried by blowing air. The liner material is then sent in a similar process to that used to apply primer. Two or more slugs of liner are sent until the desired thickness is obtained. The length of pipeline lined in a single operation depends on the nature of the liner; for example 4 to 5 miles (6.5 to 8 km) of vinyl liner, or 20 miles (32 km) of epoxy liner, are applied in a single operation. The liners may also just be fitted (either tight or loose) into pipelines; i.e., they are not bonded onto the surface. Figure 7.26 shows a tight liner being installed in a field pipeline. Liners are successfully used in water injection pipelines and sour gas pipelines containing corrosion defects.

7.9.1e Industry experience The first known application of internal liners was in 1943, and this used phenolic resins to protect a downhole tubular carrying sour crude oil. Between 1945 and 1948, more than two million feet of downhole tubular transporting condensate and sour crude oil had phenolic liners. The liners performed well for up to eight to nine years, but some failed within six months. Inadequate surface preparation was the primary cause of liner failure. Since the 1950s, however, the success of organic corrosion inhibitors slowed down the use of liners. In the late 1940s, vinyl acetate liners successfully protected many sour crude oil flow lines in West Texas. These liners protected the flowlines for between two and six years after application. In the early 1950s, epoxy liners replaced vinyl and phenolic liners for service up to 250 F (121 C) due to their ease of application and excellent adhesion to the steel surface. In 1954, 42 miles (68 km) of natural gas pipeline were internally lined with amine-cured epoxies with a nominal thickness of 1 to 2 mils (0.06 mm). These liners controlled internal corrosion during storage and hydrostatic testing, decreased the amounts of metal dusts, and reduced the duration of post-construction pigging to remove debris and corrosion products. In one 16 inch 12 mile (41 cm, 19 km) section of a gas pipeline, the dust content was reduced by about 50% after the pipeline had been lined with epoxy. Inspection after 18 months in service indicated that the liner was in perfect condition except around the welds; a length of 0.5 to in 1 inch (12.7 to 25.4 mm) of liner on either side of the weld had totally charred.

7.9 Internal coatings and linings

417

FIGURE 7.25 Typical Equipment to Apply Liner on the Internal Surface of an Operating Pipeline.35 Reproduced with permission from the American Gas Association.

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CHAPTER 7 Mitigation – Internal Corrosion

FIGURE 7.26 Insertion of Internal Liner in a Pipeline.36

Modern gas transmission pipelines increasingly apply linings on the internal surfaces of pipelines to reduce both corrosion and friction. Predominantly, epoxy coatings are used. These linings increase the flow rate by reducing the friction, so the pressure drop along the pipeline and the number of compressor stations (which boost the operating pressure of the pipeline – see section 2.22 for details) decrease. Studies have indicated that internal linings reduce fuel consumption by approximately 20%.37 Standards providing guidelines for applying and using internal liners include: • • • • • • •

API 652, ‘Guide on applied linings for internal surfaces of store tank bottoms’ API Recommended Practice 5L2 (RP 5L2), 1987, ‘Recommended Practice for Internal Coating of Line Pipe for Non-Corrosive Gas Transmission Service’ NACE RP0191, ‘The Application of Internal Plastic Coatings for Oilfield Tubular Goods and Accessories’ NACE RP0181, ‘Liquid-Applied Internal Protective Coatings for Oilfield production Equipment’ NACE TM0174, ‘Laboratory Methods for the Evaluation of Protective Coatings and Lining Materials in Immersion Service’ NACE TM0183, ‘Evaluation of Internal Plastic Coatings for Corrosion Control of Tubular Goods in an Aqueous Flowing Environment’ NACE RP 0592, ‘Application of a Coating System to Interior Surfaces of New and Used Rail Tank Cars in Concentrated (90 to 98%) Sulfuric Acid Service’

7.9.2 Clad materials Clad materials are used in the oil and gas industry when the corrosion resistance of carbon steel is inadequate even with the addition of corrosion inhibitors, or when economic considerations or mechanical strength do not warrant replacing carbon steel with a CRA. Under these conditions, the most practical, economical solution is to coat (clad) CRA material onto carbon steel.

7.9 Internal coatings and linings

419

FIGURE 7.27 Methods of Producing Clad Materials.38

The cladding process produces a composite material which combines the mechanical strength of carbon steel (base metal) and the corrosion resistance of CRA (cladding material). Therefore it is important that the cladding process does not alter the properties of either the base material or the cladding material. Clad materials are produced by three methods: hot-rolling, explosion, and a combination of both hot-rolling and explosion. Figure 7.27 illustrates all three methods.38 Hotrolling is most commonly used, and in this process, a metallurgical bond is established between the base material and the cladding material. The mechanical strength of the bond ensures that the clad material withstands both cold and hot forming processes. Some cladding materials (e.g., austenitic stainless steel) require annealing to dissolve the precipitates or phases formed during hotrolling. Water quenching follows the annealing process, to prevent the formation of an intermetallic phase. To retain the properties of the base carbon steel, the clad material is often post-weld heat treated. Some typical properties of a successful cladding material include: high pitting resistance, high crevice resistance; low corrosion rate in salt water, sea water, sour environment, sweet environment, and specific environments (e.g., gas desulfurization process (absorbers and ducts)). In addition, the cladding material should form strong bond with the base material. Table 7.25 presents chemical compositions of some commonly used cladding materials.38 Common instances in which clad materials are used in the oil and gas industry include:39,40 • • •

Offshore applications where both corrosion resistance and weight reduction are required; UR B6N cladding material is commonly used. Flue gas desulfurization plants, in which the material should withstand the corrosive sour environment; UR B66 cladding material is commonly used. Flowlines transmitting sour and sweet environments at higher temperatures; alloy 825 and UR B28 cladding materials are commonly used.

7.9.3 Refractive liners41,42 Refractories are materials used to protect the internal surface of materials exposed to high temperatures. They have been used in the refineries for a long time. The performance of refractory liners depends on the materials, installation, fabrication, and process. The thickness of refractive liners used

420

Material

Grade

UNS

C

Cr

Ni

Mo

N

Austenitic

316 317 LNM URANUS B6(N) URANUS B25 URANUS B26

0.03 0.02 < 0.020 < 0.030 < 0.020

17 18 20 20 20

12 14 25 18 25

2.2 4.5 4.3 6 6.2

0.15 0.13 0.20 0.20

URANUS B66

S31603 S31726 N08904 S31254 N08925 N08926 S31266

< 0.025

24

22

6

0.45

URANUS B28 URANUS 825

N087028 N08825

< 0.020 < 0.020

27 22

31 41

3.5 3

URANUS 625 C22

N06625 N06622

< 0.030 < 0.015

21 22

60 Balance

9 13

C276

N10276

< 0.010

15.5

Balance

16

Super austenitic

Others

PREN

Cu ¼ 0.5 Cu ¼1

25 35 37 42 44

Cu ¼ 1.5 W¼2 Cu ¼ 1 Cu ¼ 2 Ti < 1 Nb ¼ 3.5 Fe ¼ 4 W¼3 Fe ¼ 4 W¼3

56 38 32 51

CHAPTER 7 Mitigation – Internal Corrosion

Table 7.25 Chemical Compositions of Commonly used Cladding Materials in Oil and Gas Industry

7.11 Process optimization

421

in refineries ranges between 25 and 100 mm (1 and 4 inch). Typical materials used as refractories include silica, alumina, chromium oxide, calcium oxide, silicon nitride, and silicon carbide. Refractive liners are applied by hydraulic-setting, pneumatic gun, casting, or hand-packing; of which the hydraulic-setting process is the most commonly used. Standards providing guidelines for selecting refractive materials include: • • • • • • •

ASTM C 279, ‘Standard Specification for Chemical Resistant Masonry Units’ ASTM C 288, ‘Standard Test Method for Disintegration of Refractories in an Atmosphere CO’ ASTM C 454, ‘Standard Practice for Disintegration for Carbon Refractories by Alkali’ ASTM C 621, ‘Standard Test Method for Isothermal Corrosion Resistance of Refractories to Molten Glass’ ASTM C 704, ‘Standard Test Method for Abrasion Resistance of Refractory Materials at Room Temperature’ ASTM C 863, ‘Standard Test Method for Evaluating Oxidation Resistance of SiC Refractories at Elevated Temperatures’ ASTM C 987, ‘Standard Practice for Vapor Attack on Refractories for Furnace Superstructures’

7.10 Cathodic protection Section 9.3 discusses the principle of cathodic protection (CP), and the criteria for establishing it. Cathodic protection is extensively used to control external corrosion of equipment, but is also used to some extent to control internal corrosion of equipment in the oil and gas industry. Common instances where CP is used to control internal corrosion include oil-treating vessels and sea water treating facilities. Standards providing guidelines for applying CP inside an infrastructure include: •

NACE RP0575, ‘Internal Cathodic Protection Systems in Oil-Treating Vessels’

7.11 Process optimization Process optimization controls corrosion by altering the environment to decrease its corrosivity. However, process optimization as a method for controlling corrosion is expensive and, in many cases, impractical. Nevertheless, instances where this approach can be used are summarized in the following paragraphs.

7.11.1 pH control pH plays an important role in determining the corrosion rate, so by controlling pH the corrosion can be mitigated. Controlling pH in a closed system is relatively easy, but this is difficult in an open system. Studies have indicated that at and above pH 6.5 the corrosion rate decreases to less than 0.1 mm/y in sweet environments. For open systems, controlling the corrosion rate by pH stabilization depends on the volume of water phase. For example, corrosion control by pH stabilization may be effective in gas

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condensate pipelines, as long as the pH stabilizer can be transported and deployed in locations where water condenses. Some chemicals successfully used for pH stabilization include NaOH and NaHCO3.43,44

7.11.2 Oxygen control Corrosion can be controlled by removing the corrosive species in the medium. Chemicals which decrease the corrosivity of the medium by scavenging the aggressive substances are called environmental conditioners or scavengers. In near neutral and alkaline solutions, oxygen reduction is a common cathodic reaction. In such situations, corrosion can be controlled by decreasing the oxygen content using scavengers. One commonly used oxygen scavenger is ammonium bisulfite.45

7.11.3 Bacterial control The bacterial contents of incoming water used in the process can be reduced by irradiating the water with ultraviolet (UV) light. This process is frequently used to treat sea water. In order for UV radiation to be effective, the water should be free from solid particles (slime and silt), hydrocarbons, and turbidity. Typically, a UV intensity of approximately 11 MW/cm2 with 254 nm light is used for 1 s. Such irradiation may reduce the concentration of SRB by three orders of magnitude. However, it should be noted that UV radiation treats only planktonic bacteria, not sessile bacteria. Also, planktonic bacteria may become active downstream of the UV radiation point. For this reason, UV radiation treatment is further supplemented by the application of biocides.46

References 1. B. Guo, S. Song, J. Chacko, A. Ghalambor, ‘Offshore Pipelines’, Chapter 16: Pigging Operations, p. 215, Gulf Professional Publishing, 30 Corporate Drive, Suite 400, Burlington, MA, ISBN: 978–0–7506–7847–6 (2005). 2. Falk C, Maribu J, Eide LO. Commissioning the Zeepipe System Sets New Standards. Pipeline and Gas Journal August 1994;221(8):24–33. 3. G. Schreure, P. Burman, S. Hamid, C. Falck, J. Maribu, C. Ashwell, ‘Development of Gel System for Pipeline Dewatering and Drying Operations’, Presented at the 26th Annual Offshore Technology Conference, Houston, Texas, USA (1994). 4. Bob Lotwin, in Medicine Hat Seminar, ‘Shallow Gas Gathering Pipeline System Integrity, November 22, 2005, Slide 12, NACE, Calgary Section NACE International, 1440, South Creek Drive, Houston, TX, USA 77084-4906. 5. Cameron G. Maintenance Pigging Selection Guidelines. Pigging Course Materials (Personal communication) 2009. 6. Roy D. ‘Offshore Pipelines’, Second Canada-India workshop on Pipeline Integrity: Developing an Integrity Management Plan. Calgary: Alberta, Canada; Oct. 25–26, 2008. Natural Resources Canada, 580 Booth Street, Ottawa, Ontario, Canada K1A 0G1. 7. B. Lotwin, in Medicine Hat Seminar, ‘Shallow Gas Gathering Pipeline System Integrity, November 22, 2005, Slide 17, NACE, Calgary Section NACE International, 1440, South Creek Drive, Houston, TX, USA 77084-4906. 8. B. Guo, S. Song, J. Chacko, A. Ghalambor, ’Offshore Pipelines’, Chapter 16: Pigging Operations, Figure 14.4, p. 167, Gulf Professional Publishing, 30 Corporate Drive, Suite 400, Burlington, MA, ISBN: 978–0-7506–7847–6 (2005).

References

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9. Sastri VS. Corrosion Inhibitors: Principles and Applications. John Wiley and Sons; 1998. ISBN: 0–471–97608–3. 10. S. Papavinasam, Chapter 71, ‘Corrosion Inhibitors’, Figure 71.1, p. 1021, in Uhlig’s Handbook, Ed. R.W. Revie, ISBN: 978–0470–87285–7, J. Wiley and Sons (2011). 11. S. Papavinasam, Chapter 71, ‘Corrosion Inhibitors’, Table 71.4, p. 1026, in Uhlig’s Handbook, Ed. R.W. Revie, ISBN: 978–0470–87285–7, J. Wiley and Sons (2011). 12. S. Papavinasam, Chapter 71, ‘Corrosion Inhibitors’, Table 71.3, p.1026, in Uhlig’s Handbook, Ed. R.W. Revie, ISBN: 978–0470–87285–7, J. Wiley and Sons (2011). 13. Singh I. Inhibition of Steel Corrosion by Thiourea Derivatives. Corrosion 1993;49:473. 14. Papavinasam S, Attard M, Revie RW, Demoz A, Michaelian K. Comparison of Laboratory Methodologies to Evaluate Corrosion Inhibitors for Oil and Gas Pipelines. NACE Corrosion 2003;59(10):897. 15. Papavinasam S, Revie RW, Panneerselvam T, Bartos M. Laboratory Evaluation of Oilfield Corrosion Inhibitors. Materials Performance 2007;46(5):46–8. 16. ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’ ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428-2959 USA. 17. Papavinasam S, Doiron A, Revie RW. Evaluation of Green Inhibitors. IPC2002, October 6–10. Calgary, AB, Canada: ASME; 2002. 18. NACE TM0196, ‘Chemical Resistance of Polymeric Materials by Periodic Evaluation’ 19. A. Perkins, Personal Communication. 20. Nalco J. ‘Developing a Defendable Platform for Corrosion Inhibitor Treatments: Corrosion Inhibitors Application and Dosage – Theory and Practical’, NACE Corrosion Technology Week, 2007, 282x. September 18, 2007 Houston, TX: Sour Gas Technical Exchange Group; 2007. 21. NACE Gulf Coast Corrosion Control Seminar, Corrosion Inhibitors and Applications, Feb. 7, 1994 NACE International, 1440, South Creek Drive, Houston, TX, USA 77084-4906. 22. Hedges B, Paisley D, Woollam RC. ‘The Corrosion Inhibitor Availability Model’, CORROSION 2000, Paper # 34. NACE International, Houston, TX: NACE; 2000. 23. Davies M, Scott PJB. ‘Oilfield Water Technology’, Figure 13.1, page 266, ISBN: 1–57590–204–4. Houston, Texas: NACE; 2006. 24. Hubert C, Voordouw G, Nemati M, Jenneman GE. ‘Is souring and corrosion by SRB in oil fields reduced more efficiently by nitrate or by nitrite?’ CORROSION 2004, Paper # 04762. NACE International Houston, TX: NACE; 2004. 25. Kilbane JJ, Bogan B, Lamb B. ‘Quantifying the contribution of various bacterial groups to microbiologically influenced corrosion’, CORROSION 2005, Paper #: 491. NACE International, Houston, TX: NACE; 2005. 26. Davies M, Scott PJB. ‘Oilfield Water Technology’, Table 13.1, p. 265, ISBN: 1–57590–204–4. Houston, Texas: NACE; 2006. 27. Fink JK. ‘Oil Field Chemicals’, ISBN: 0–7506–7703–1. Gulf Professional Publishing; 2003. 28. Becker JR. ‘Corrosion and Scale Handbook’, PennWell Publishing Company, 1421 South Sheridan. Tulsa: Oklahoma; 1998. 29. Hernandez SE, Duplat S, Vera JR, Baron E. ‘A statistical approach for analyzing the inhibiting effect of different types of crude oil in CO2 corrosion of carbon steel’, CORROSION 2002, Paper #2293. NACE International, Houston, TX: NACE; 2002. 30. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960, Page 40. 31. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960., Page 73.

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32. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960., Page 72 33. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960., Page 74. 34. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960, page 53 35. Interior Surface Coating of Pipe for Natural Gas Service, G.G. Wilson, American Gas Association, 420, Lexington Avenue, New York, 17, N.Y. Project NB-14, Institute of Gas Technology Technical Report No.3. 1960., Page 19. 36. Stephenson M. ‘Corrosion Mitigation’, Tutorial #3, Internal Corrosion Control of Pipelines’. Banff, Canada: Banff Pipeline Workshop 2007; April 2, 2007. 37. Cato K. ‘A Process for Lining Oilfield Pipelines’, CORROSION 2000, Paper #178. NACE International, Houston, TX: NACE; 2000. 38. L.Coudreuse, J.P. Audouard, and J. Charles, ‘Production and Application of Superaustenitic Stainless Steels Clad Plates’, USINOR INDUSTEEL (France), 56, Rue Clemenceau, BP56, 71202 Le Creusot Cedex, France (Handout report provided at Eurocorr 2000, September 15, 2000, London, UK). 39. Kelley DH. ‘Cost Effective Materials for Flue Gas Desulfurization (FGD)’, CORROSION 1996, Paper #: 398. NACE International, Houston, TX: NACE; 1996. 40. Eide OH. ‘Guideline for Material Selection and Qualification of Wear and Corrosion Protective Hard Face Coatings for Piston Rods’, CORROSION 2007, Paper #: 7694. Houston, TX: NACE; 2007. 41. Silvernman DC. ‘Introduction of Environmental Performance of Nonmetallic materials’, in ASM Volume 13B, Corrosion; Materials. ASM International 2003. ISBN: 0–87170–707–1, P. 546. 42. Kane RD. ‘Corrosion in Petroleum Refining and Petrochemical Operations –Corrosion Control: Refractory Linings’, in ASM Volume 13B, Corrosion; Materials. ASM International 2006. ISBN: 0–87170–709–3, P. 1003. 43. Olsen S, Lunde O, Dugstad A. ‘pH-Stabilization in the Troll Gas-Condensate Pipelines’, CORROSION 1999, Paper #19. Houston, TX: NACE; 1999. 44. Dugstad A, Dronen PE. ‘Efficient Corrosion Control of Gas Condensate Pipelines by pH-Stabilisation’, CORROSION 1999, Paper #20. Houston, TX: NACE; 1999. 45. Papavinasam S, Pushpanaden F, Ahmed MF. Hydrazine and Substituted Hydrazines as Corrosion Inhibitors for Lead in Acetic Acid Solutions. British Corrosion Journal 1989;24:39–42. 46. Davies M, Scott PJB. ‘Oilfield Water Technology’, Chapter 13, Biological Control, page 261, ISBN: 1–57590–204–4. Houston, Texas: NACE; 2006.

CHAPTER

Monitoring – Internal Corrosion

8

8.1 Introduction Chapters 2 through 6 provide information on the nature of corrosion and on methods to estimate the corrosion rate. If the corrosion rate of a material in a given environment is high, it is reduced by implementing suitable corrosion mitigation strategies. Chapter 7 discusses various mitigation strategies for controlling internal corrosion. Successful material selection and implementation of mitigation strategies ensure that the infrastructure is safe for continued operation. It is important to ensure that the corrosion, under the field operating conditions, proceeds according to the anticipated low rate so that the infrastructure lasts for its designed service period. Various techniques are used to monitor the corrosion rate at different stages. In general, the objectives of corrosion monitoring are two-fold: to select appropriate material and corrosion mitigation strategies, and to ensure that the material and mitigation strategies selected continue to be effective in the operating environment. Corrosion monitoring may take place in three situations: •

• •

In the laboratory at the design stage to evaluate the suitability of a given material in the anticipated environment. Based on these laboratory measurements, appropriate materials are selected, and the minimum thickness of material required to withstand corrosion is established. In the field during operation the infrastructure is monitored to determine the actual corrosion rate under operating conditions, to optimize the corrosion control strategies. In the field during operating, the infrastructure is also inspected, to ensure that the material continues to be safe under field operating environment.

This chapter discusses techniques to monitor internal corrosion in the laboratory and in the field, as well as to inspect the infrastructure in the field.

8.2 Laboratory measurement The selection of materials for oil and gas industry starts with an evaluation and selection of materials in the laboratory. Some types of corrosion cannot be monitored in the field, Therefore evaluation of material susceptibility for such types of corrosion is performed only in the laboratory. The main advantage of conducting laboratory tests is the ability to control many variables that cannot be controlled in the field, meaning that the influence of an individual variable on the overall corrosion can be investigated. For this reason, the first task is to determine the parameters influencing corrosion in the Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00008-X Copyright Ó 2014 Elsevier Inc. All rights reserved.

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field, and the second task is to select an appropriate laboratory methodology for simulating these parameters. The fundamental assumption in this approach is that when all parameters influencing corrosion in the field are simulated in the laboratory the corrosion mechanism in both situations is the same. In order for a laboratory methodology to be useful it must simulate the combined effects of all the parameters that would influence corrosion in the field. Laboratory methodologies provide controlled conditions for evaluating the corrosion behavior of a material in a given environment. Depending on the type of laboratory methodology, several variables can be simulated. The measured corrosion rate will depend on several parameters. including duration of the experiment; volume of the solution; solution volume to surface area ratio; extent of de-aeration;extent of purging acid gases; stress level; size, shape, area, and orientation of samples; stress level; flow rate (e.g., rotation speed); temperature; pressure; type and frequency of corrosion measurements; as well as the skill, knowledge, and experience of the operator. As many parameters as possible should be controlled (see also Chapter 12). It is important to develop a standard operating procedure before the experiments are started, and to ensure that the results are valid and relevant to field operating conditions. It is equally important to understand the extent and cause of deviation between the experiments. In general, some of the variation in the results is intrinsic (nature of corrosion and apparatus) and some is extrinsic (operator error and improper assembly of apparatus). All intrinsic causes should be minimized to the greatest extent possible, and extrinsic causes should be eliminated. It is good laboratory practice to conduct at least two identical tests and determine the variation between them. If the corrosion rates differ by more than 10%, conduct two more additional tests and use the mean and standard deviation of all four corrosion rates. In establishing the mean and standard deviation of four corrosion rates, the importance of repeatability and reproducibility should be understood. Repeatability is defined as the mean and standard deviation of results produced by one operator using the same or identical experimental setup and following the same experimental procedure. Reproducibility is defined as the mean and standard deviation of results produced by multiple operators using an identical experimental setup and following the same experimental procedure. Several standardization organizations develop and publish the repeatability and reproducibility of individual laboratory methodologies; they should be verified in determining the validity of test results. The following paragraphs discuss laboratory measurements to evaluate susceptibility of materials to various types of internal corrosion.

8.2.1 Hydrogen effects Section 5.18 discusses the effects of hydrogen and types of hydrogen-related corrosion and cracking. Laboratory evaluation of the susceptibility of materials to hydrogen-related corrosion and cracking is important, because techniques to monitor them in the field are not well established. The relevant tests may be broadly divided into hardness tests, hydrogen absorption tests, and tests that determine susceptibility to applied stress.

8.2.1a Hardness test One of the primary properties influencing the effect of hydrogen is the mechanical strength of the material. One of the common properties used to indicate this is hardness (see section 3.2.1c).

8.2 Laboratory measurement

427

Therefore, to understand the effect of hydrogen the hardness of the material is determined. The hardness requirements of different materials for use in various sectors of oil and gas industry have been established. Standards specifying the hardness requirements include: •

•

•

• • •

ANSI-NACE MR0175/ISO 15156–1: Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production – Part 1: General Principles for Selection of Cracking-Resistant Materials ANSI-NACE MR0175/ISO 15156–2: Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production – Part 2: Cracking-Resistant Carbon and Low-Alloy Steels, and the Use of Cast Irons ANSI-NACE MR0175/ISO 15156–3: Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production – Part 3: Cracking-Resistant CRAs (Corrosion Resistant Alloys) and Other Alloys NACE Standard Practice MR0176: Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments NACE Standard Practice MR0103: Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments NACE Standard Practice SP0472: Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments

Different scales are used to indicate the hardness of materials. Some commonly used scales include Rockwell hardness Scale C (HRC); Rockwell hardness Scale B measured using a steel ball (HRBS); Rockwell hardness Scale B measured using a tungsten carbide ball (HRBW); Brinell hardness measured using a tungsten carbide ball (HBW); Vickers 49 N hardness measured using 5 or 5 kgf (HV 5); and Vickers 98 N Vickers hardness measured using 10 or 10 kgf (HV 10). Standards showing the relationship between various hardness scales, and tables to convert hardness from one scale to another include: •

ASTM E140, ‘Standard Hardness Conversion Tables for Metals Relationship Among Brinell Hardness, Vickers Hardness, Rockwell Hardness, Rockwell Superficial Hardness, Knoop Hardness, and Scleroscope Hardness’

i. Rockwell hardness test In the Rockwell hardness test, a load ranging between 147 N (15 kgf) to 1,470 N (150 kgf) is applied. The indentation caused by the load is measured and reported. A steel or tungsten carbide ball or a diamond cone is used to apply the load. This test is ideal for identifying localized hard spots because the load and the resulting indentation area are small. This method is quick, produces a direct reading, and is routinely used during the manufacturing of materials. However, because this test only measures hardness in a small area, it cannot be used in certain locations due to geometrical restrictions, and it is not portable. Standards providing guidelines for performing the Rockwell hardness test include: • •

ASTM E18, ‘Standard Test Method for Rockwell Hardness’ ISO 6508–1, ‘Metallic Materials: Rockwell Hardness Test: Part 1: Test Method (A, B, C, D, E, F, G, H, K, N, T)’

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ii. Brinell hardness test In the Brinell hardness test, a load of 29.42 kN is applied using a 10 mm tungsten carbide ball. The indentation created is measured optically, and the hardness is calculated from this measurement. This test is frequently used to determine hardness of castings and forgings. The hardness value reported in this test is considered as the average hardness of the material because a relatively large load applied. It cannot be used in certain locations due to geometrical restrictions, and it is not portable. Standards providing guidelines for performing the Brinell hardness test include: • •

ASTM E10, ‘Standard Test Method for Brinell Hardness of Metallic Materials’ ISO 6506–1, ‘Metallic Materials – Brinell Hardness Test – Part 1: Test Method’

iii. Comparison hardness test In a comparison hardness test, a hammer simultaneously indents the test material and a reference material of known hardness. The indentations created on the test and reference materials are compared to determine the hardness of the test material. The results obtained from this test can be directly correlated with those obtained from the Brinell hardness test. This test is commonly used to evaluate field welds. Standards providing guidelines for performing a comparison hardness test include: •

ASTM A833, ‘Standard Practice for Indentation Hardness of Metallic Materials by Comparison Hardness Testers’

iv. Vickers hardness test In the Vickers hardness test, a load of 0.25 N to 1,180 N is applied using a diamond pyramid indenter. The test procedure is similar to that used in the Brinell hardness test. The results are designated as ‘HV’ with a suffix to indicate the load applied (e.g., 248 HV 10 indicates a Vickers hardness of 248 determined using a 10 kgf load). The hardness values obtained in this test are independent of load when the test is performed with loads in the range between 49 N (5 kgf) and 98 N (10 kgf). This test is frequently used to assess the hardness of heat-affected zones (HAZ) around the weld and to qualify a welding procedure. Standards providing guidelines for performing a Vickers hardness test include: • • •

ASTM E384, ‘Standard Test Method for Knoop and Vickers Hardness of Materials’ ASTM E92, ‘Standard Test Method for Vickers Hardness of Metallic Materials’ ISO 6507–1, ‘Metallic Materials – Vickers Hardness Test – Part 1: Test Method’

v. Microhardness test The microhardness test is valuable for testing components that are too small to be tested by conventional methods. In this test only a small load of 9.8 N (1 kgf) or less is applied. This test is sensitive because of the relatively small size of the indentation. The presence of localized microscopic constituents may cause individual hardness values that are much higher or lower than the bulk hardness. For this reason it is difficult to establish a general acceptance criterion for this test.

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8.2.1b Hydrogen absorption tests Hydrogen affects the properties of a material only when its absorbed concentration of equals or exceeds a threshold hydrogen concentration (Cth). By measuring the permeation of hydrogen atoms through the wall, the amount of hydrogen absorbed inside the surface can be calculated. The test methods used to estimate the hydrogen concentration inside materials are discussed in this section.

i. Electrochemical (Devanathan-Stachurski) test1,2 Figure 8.1 presents a typical experimental setup to estimate the hydrogen concentration in a material.3 This technique involves charging the material on one side and measuring the hydrogen flux on the other side by electrochemical methods. The charging side is exposed to a corrosive environment in which the cathodic reaction is hydrogen reduction, producing hydrogen atoms. This process normally occurs in low pH environments (typically below pH 5.5) containing H2S. Some of the hydrogen atoms produced diffuse through the material and exit at the other side, which is commonly known as the oxidizing side. The potential of the material on the oxidizing side is controlled so that the oxidation of hydrogen occurs on its surface. The kinetics of hydrogen oxidation are limited by the flux of hydrogen atoms through the surface, i.e., the kinetics are diffusion controlled. The current on the oxidizing side is Reference Electrode (RE)

Auxiliary Electrode (AE)

Reference Electrode (RE)

Gas out

Gas in

Auxiliary Electrode (AE)

Gas out

Gas in

Oxidation Cell Charging Cell

Specimen (WE)

FIGURE 8.1 Hydrogen Permeation Cell.3 Reproduced with permission from ASTM.

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continuously monitored. Prior to the diffusion of hydrogen atoms through the material, this oxidation current should be relatively constant and small, and it increases proportional to the hydrogen flux (Figure 8.2).4 The level of permeation of hydrogen atoms is determined from the increase in the oxidation current. The maximum concentration of hydrogen in the material is given by (Eqn. 8.1): CH o ¼

Imax :tw DF

(Eqn. 8.1)

where CHo is the concentration inside the material, Imax is the peak current density (mA/cm2), tw is the thickness of material, D is the diffusion coefficient (cm2/s), and F is the Faraday constant (96,487 C/mol). The diffusion coefficient is calculated from the half-rise time, t1/2 (Eqn. 8.2) or from the breakthrough time, tH,b (Eqn. 8.3). Figure 8.2 illustrates both the half-rise time and the breakthrough time. D¼

tw2 7:2:t1=2

(Eqn. 8.2)

D¼

tw2 15:3:tH;b

(Eqn. 8.3)

Standards providing guidelines for hydrogen measurement include: •

Permeation Flux (µA/cm2)

•

ASTM Standard practice G148 ‘Evaluation of Hydrogen Uptake, Permeation, and Transport in Metals by an Electrochemical Technique’ ASTM Standard F 1113, ‘Standard Test Method for Electrochemical Measurement of Diffusible Hydrogen in Steels (Barnacle Electrode)’

t1/2

J∞ tb

0.5 J∞

Time (S)

FIGURE 8.2 Schematic Current Response of the Oxidizing Side in the Hydrogen Permeation Test.4 Reproduced with permission from Wiley.

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ii. Glycerol displacement test In this test, a coupon is first immersed in an H2S-saturated solution or other suitable medium for a predetermined duration (typically 100 hours) to absorb hydrogen. After this period the coupon is removed, washed, dried, and immediately placed in a collector tube. This tube is placed in a glass container filled with glycerol. To facilitate desorption of hydrogen from the coupon the glass container is heated to 40 C. The volume of hydrogen collected in the container is measured as a function of time until a steady state is reached, which normally happens within 72 hours. The volume of absorbed hydrogen is estimated from the volume collected after 72 hours. The results are typically presented as volume of hydrogen per 100 g of coupon.

8.2.1c Stress tests To evaluate the influence of hydrogen, the susceptibility of the material to applied stress is evaluated. This is done because the driving force for the hydrogen effects is stress. During the test, the stress is applied in the form of a load. Equation 8.4 provides the relationship between stress, s and load, A: s¼

Ps A

(Eqn. 8.4)

where s is the stress on a smooth uniaxial tensile specimen, Ps is the load on the specimen, and A is the cross-sectional area of the specimen.

i. Constant load method When the required load is small, usually a hanging weight is suspended from the specimen. To focus the influence of corrosion and stress, a single notch may sometimes be made in the specimen. Once the crack initiates, the cross-sectional area decreases and consequently the stress increases. For this reason, the specimen fails shortly after the crack initiates, so this test is not useful for studying crack propagation. Standards providing guidelines for performing constant load stress tests include: • • •

ASTM G49, ‘Standard Practice for Preparation and Use of Direct Tension Stress Corrosion Test Specimens’ ISO 7539-Part 4, ‘Corrosion of Metals and Alloys – Stress Corrosion Testing – Part 4: Preparation and Use of Uniaxially Loaded Tension Specimens’ NACE TM0177, ‘Standard Test Method: Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking in H2S Environments’

ii. Deflected sample method Another method to stress the sample is by deflecting it. In deflected samples, the stress decreases as the crack propagates. The tests are commonly identified by the geometry of the specimens as: bent-beam (Figure 8.3),5 C-ring (Figure 8.4),6 and U-bend specimen (Figure 8.5)7 tests. In the bent-beam test, the specimen may be loaded by two-, three- or four-point loading. The relationship between the load and deflection depends on the geometry. Therefore in this test it is important to understand the relationship between load and deflection.

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L

H t θ

(A) TWO-POINT LOADED SPECIMEN

H t y

(B) THREE-POINT LOADED SPECIMEN

H y1

A

H t

y

(C) FOUR-POINT LOADED SPECIMEN H h WELD S

t

(D) DOUBLE-BEAM SPECIMEN

FIGURE 8.3 Schematic Diagram of Bent Beam Specimen and Holder Configuration.5 Reproduced with permission from ASTM.

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433

FIGURE 8.4 C-Ring Specimens.6 Note: Notch illustrated in sample (D) can also be created on tension side in samples (B) and (C). Reproduced with permission from ASTM.

Standards providing guidelines for conducting deflected sample tests include: • • •

ISO 7539, ‘Corrosion of Metals and Alloys – Stress Corrosion Cracking’ ASTM G39, ‘Standard Practice for Preparation and use of Bent-Beam Stress Corrosion Test Specimens’ NACE TM0177, ‘Standard Test Method: Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking in H2S Environments’

FIGURE 8.5 Typical Methods to U-Bend Specimens.7 Reproduced with permission from ASTM.

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ISO 7539-Part 5, ‘Corrosion of Metals and Alloys – Stress Corrosion Testing – Part 5: Preparation and Use of C-Ring Specimens’ ASTM G38, ‘Standard Practice for Making and Using C-Ring Stress Corrosion Test Specimens’ NACE TM0177, ‘Standard Test Method: Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking in H2S Environments, Method C’ ISO 7539-Part 3, ‘Corrosion of Metals and Alloys – Stress Corrosion Testing – Part 3: Preparation and Use of U-Bend’ ASTM G30, ‘Standard Practice for Making and Using U-Bend Stress Corrosion Test Specimens’ ASTM G58, ‘Standard Practice for Preparation of Stress Corrosion Test Specimens for Weldments’ ASTM G168, ‘Standard Practice for Making and Using Precracked Double Beam Stress Corrosion Specimens’

In some instances, the deflected samples may be pulled to failure after being exposed to the corrosive environment and the load at which failure occurs is recorded. This destructive test is usually performed on specimens that have not failed during exposure. Standards providing procedures for performing pull tests include: •

ASTM standard G139, ‘Standard Test Method for Determining Stress Corrosion Cracking Resistance of Heat-Treatable Aluminum Alloy Products Using Breaking Load Method’

In deflection tests, the applied stress is high relative to the yield strength. Also the geometry, dimensions, and modulus of elasticity of the material prevent the application of stress uniformly across the sample.

iii. Dynamic load method In some tests the stress may be applied dynamically. One common test in this category is the slow strain rate test (SSRT), also known as the constant extension rate test (CERT). Figure 8.6 the load (or stress) until failure occurs. This test produces results in a short time period, usually one to two days, because the increasing load decreases the incubation time for the initiation of cracks. The susceptibility of a material is evaluated by conducting the experiment in inert (usually air) and in corrosive environments. The test is conducted by varying the extension rate, strain rate, and applied electrode potential. The stress applied in an SSRT is far greater than the material faces in actual service. For this reason, some material may exhibit higher susceptibility to cracking in this test compared to the constant load test. Standards providing guidelines for performing dynamic load tests include: • • •

ASTM G129, ‘Standard Practice for Slow Strain Rate Testing to Evaluate the Susceptibility of Metallic Materials to Environmentally Assisted Cracking’ NACE TM0198, ‘Slow Strain Rate Test Method for Screening Corrosion Resistant Alloys for Stress Corrosion Cracking in Sour Oilfield Service’ ISO 7539–7, Corrosion of Metals and Alloys – Stress Corrosion Cracking – Part 7: Method for Slow Strain Rate Testing’

A variation of the SSRT is the cyclic slow strain rate (CSSR) test. In this test the specimen is loaded and the stress is varied above and below this value. The amount of load, frequency of cyclic loading, and stress range are varied during the test. The cumulative plastic strain applied on the specimen in this test

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435

Signal Conditioner

Strip Recorder Speed and Temperature Controller

Load Cell

Autoclave Heater Bands

Thermocouple

SSR Machine Drive Mechanism

FIGURE 8.6 Schematic Diagram of Slow Strain Rate Test (SSRT).8 Reproduced with permission from ASTM.

is lower than that in an SSRT. The dynamic strain mechanically disrupts the protective surface layer, thereby reducing the duration of the test. The types of tests, type of environments in which to perform them, type of stress to be applied, and criteria for qualifying different materials for different applications are well established.

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Standards providing guidelines for performing a CSSR test include: •

•

NACE MR0175-ISO15156–2, ‘Petroleum and natural gas industries – Materials for use in H2S containing environments in oil and gas production: Part 2: Cracking-resistant carbon and lowalloy steels, and the use of cast irons’ NACE MR0175-ISO15156–3, ‘Petroleum and natural gas industries – Materials for use in H2S containing environments in oil and gas production: Part 3: Cracking-resistant CRAs (corrosion resistant alloys) and other alloys’

It should be noted that for testing the susceptibility of materials to hydrogen-induced cracking (HIC) (see section 5.18), no external stress is applied whereas to test SSC stress is applied. Standards providing guidelines for performing HIC and SSC tests include: • •

NACE TM0284, ‘Standard Test Method: Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking’ NACE TM0177, ‘Standard Test Method: Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking in H2S Environments’

The susceptibility of a material to hydrogen embrittlement (HE) (see section 5.18) can be evaluated from the difference in the mechanical properties (e.g., yield strength, ultimate tensile strength, notched tensile strength, reduction in area or elongation) in a hydrogen containing (embrittlement) environment and in a non-embrittlement environment. In order to simulate field operating conditions, the test is typically carried out at the operating temperature and pressure of the field in an autoclave. Standards providing guidelines for evaluating HE include: •

ASTM G142, ‘Standard Test Method for Determination of Susceptibility of Metals to Embrittlement in Hydrogen Containing Environments at High Pressure, High Temperature, or Both’

Hydrogen-induced disbondment (HID) (see section 5.18) of stainless, alloy clad, carbon steel can be evaluated by charging the specimen in with gaseous hydrogen at high temperature and high pressure. The specimen is then cooled to room temperature for sufficient time to allow HID to develop. The susceptibility of the material to HID is then evaluated using ultrasonic inspection. Standards providing guidelines for evaluatig HID include: •

ASTM G 146, ‘Standard Practice for Evaluation of Disbonding of Bimetallic Stainless Steel/Steel Plate for Use in High Pressure, High Temperature Refinery Hydrogen Service’

8.2.2 General and localized corrosion Commonly used laboratory methodologies and measuring techniques to evaluate internal corrosion (general, localized, pitting, flow-induced localized corrosion (FILC) (see section 4.5), and erosioncorrosion) are described in this section. Laboratory measurements consist of two main components: laboratory methodology and monitoring technique. Laboratory methodology is the apparatus to simulate the variables, and the monitoring technique determines the corrosion rate that is simulated. Not all monitoring techniques are suitable for all laboratory methodologies. Table 8.1 presents some typical combinations of laboratory methodologies and monitoring techniques. To evaluate the

8.2 Laboratory measurement

437

Table 8.1 Laboratory Methodologies and Monitoring Techniques Laboratory Methodology

Corrosion Measuring Techniques

Static test

• • • • •

Bubble test Wheel test

Remarks

Mass loss Electrochemical Mass loss Electrochemical Mass loss

Rotating disk electrode

• Electrochemical

Rotating cylinder electrode

• Electrochemical

Rotating cage

• Mass loss

Jet impingement

• Mass loss

Jet impingement

• Electrochemical

Flow loop

• Mass loss • Electrochemical

• Specimen is too small for accurate measurement of loss of mass • Specimen is too small for accurate measurement of loss of mass • Connections to make electrochemical measurements difficult • When the specimen is a large disk

• When the specimen is a ring or when it is a small disk • When coupons are inserted into the flow loop

Types of Corrosion Evaluated • • • • • • • • • • • • • • • • • • • • • • • • • • • •

General corrosion Pitting corrosion General corrosion Pitting corrosion General corrosion Pitting corrosion General corrosion Pitting corrosion Flow-induced localized corrosion (FILC) General corrosion Pitting corrosion Flow-induced localized corrosion (FILC) Erosion-corrosion General corrosion Pitting corrosion Flow-induced localized corrosion (FILC) Erosion-corrosion General corrosion Pitting corrosion Flow-induced localized corrosion (FILC) Erosion-corrosion General corrosion Flow-induced localized corrosion (FILC) Erosion-corrosion General corrosion Pitting corrosion Flow-induced localized corrosion (FILC) Erosion-corrosion

susceptibility of materials to general and localized corrosion, field conditions should be simulated in the laboratory. The variables that influence corrosion inside oil and gas infrastructure are numerous, but they can be broadly classified into composition of material, compositions of solid, liquid (oil and water), and gas (especially acid gases), temperature, and pressure. Simulation of these variables in the laboratory is direct. With respect to these direct variables, laboratory experiments can easily be carried out under field conditions. For example, the laboratory experiments are carried out at field temperatures using specimens made out of the correct material (for example, carbon steel) and in an environment of the same composition (solid, oil, aqueous, and gas) as that experienced in the field.

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Table 8.2 Typical Laboratory Methodologies to Simulate Different Wall Shear Stress9 Laboratory Methodology

Wall Shear Stress, Pa

Rotating disk electrode Rotating cylinder electrode Rotating cage Jet impingement

Below 5 5 to 20 20 to 200 Above 200

The effect of pressure is simulated by using a gas mixture with a composition similar to the field for atmospheric experiments and by using partial pressures similar to those in the field for high pressure experiments. Standard providing general guidelines for performing experiments at high temperatures and pressures include: • •

ASTM G111, ‘Standard Guide for Corrosion Tests in a High Temperature or High Pressure Environment, or Both’ ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’

For various reasons, the direct variables in the laboratory may not be the same as those in the field. Section 7.4.1 describes the effects of differences in the direct variables between the laboratory and the field. Flow, on the other hand, is an indirect variable, and simulation of flow in the laboratory is not direct. To simulate the effect of flow, the hydrodynamic parameters are determined, and then the laboratory corrosion tests are conducted under the calculated hydrodynamic parameters (see also section 4.2). The fundamental assumption in this approach is that when the hydrodynamic parameters in two different geometries are the same, then the corrosion rates are similar. The hydrodynamic parameter normally used is wall shear stress. Sections 4.2 and 7.4.1 describe wall shear stress and methods to determine wall shear stress. Table 8.2 presents appropriate laboratory methodologies to simulate various values of wall shear stress.

8.2.2a Laboratory methodologies Figure 8.7 presents the variables simulated in various laboratory methodologies.9–14

i. Static test The static test is a basic test used to evaluate material performance in the absence of flow. It simulates two variables, composition and temperature, to reflect the condition in which the system is not in operation. A static test may be conducted at elevated pressure in an autoclave, in which case the effect of pressure can also be simulated. The corrosion rate can be measured by mass loss or by electrochemical techniques, with the latter being used predominantly. Several configurations of static test are available. Figure 8.8 presents a schematic picture of a typical static test apparatus,15 which contains ports to insert the test sample, counter electrodes (typically two), a reference electrode, gas inlet, gas outlet, and thermometer. Figure 8.9 presents a leakproof assembly in which to mount the sample. A proper compression fit between the sample and gasket

8.2 Laboratory measurement

Composition

Temperature

Flow

439

Pressure

Controllable Variables

Field Static

Static, Bubble, Wheel RDE RCE, JI, RC

Atmospheric Pressure Experiments

HTHP R DE HTHP R CE HTHP J I HTHP R C

Elevated Pressure Experiments

Controllable Variables in Laboratory Methodologies FIGURE 8.7 Variables Simulated in Different Laboratory Methodologies.10–14

GAS OUTLE THERMOMETER

SALT BRIDGE CONNECTION

GAS INLET

AUXILIARY ELECTRODE HOLDER

PROBE WORKING ELECTRODE

FIGURE 8.8 Schematic Diagram of Static Test.15 Reproduced with permission from ASTM.

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MOUNTING NUT SPACER

ELECTRODE HOLDER

MOUNTING ROD

TFE-FLUOROCARBON COMPRESSION GASKET TEST SPECIMEN

FIGURE 8.9 Mounting Specimen in Static Test for Electrochemical Measurements.15 Reproduced with permission from ASTM.

is essential; too much pressure may either shield certain surfaces of the sample or break the holder, and too little pressure may cause leaks and crevice corrosion. Standards providing guidelines for performing static tests include: • • •

ASTM G5, ‘Standard Reference Test Method for Making Potentiostatic and Potentiodynamic Anodic Polarization Measurements’ ASTM G31, ‘Standard Practice for Laboratory Immersion Corrosion Testing of Metals’ ASTM G157, ‘Standard Guide for Evaluating the Corrosion Properties of Wrought Iron- and Nickel-based Corrosion Resistant Alloys for the Chemical Process Industries’

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441

Gas outlet Gas inlet Thermometer

Probe

FIGURE 8.10 Schematic Diagram of Bubble Test.

ii. Bubble test The bubble test is a slight variation of the static test, in which the size and rate of the bubble are more precisely controlled. It is also known as the stirred corrosion test or the kettle test, and it can be carried out in the same apparatus used for the static test, but is normally performed in a simple container closed with a cover (Figure 8.10). Glass tubes inserted through the cover provide the gas inlet and outlet. For each test, two or more mass loss samples are suspended in the flask using a plastic wire, knotted so that the samples do not touch either the adjacent sample or the sides of the flask. Alternatively, a three-electrode probe may be inserted as shown in Fig. 8.10. In this test, the composition and temperature can be simulated, and the bubble flow rate can be varied. The only fluid movement is generated by the bubbles; consequently no hydrodynamic equation exists to characterize the flow conditions in the test. A round robin test revealed that the reproducibility of bubble test was 75% (six out of eight laboratories produced similar trends of corrosion rate).16 Standards providing guidelines for performing a bubble test include: •

NACE Task Group T-1D-34 Technical Committee Report, ‘Laboratory Test Methods for Evaluating Oil field Corrosion Inhibitors’, NACE Publication 1D196

iii. Wheel test The wheel test is used to select corrosion inhibitors, and is performed by adding the fluids, oil, water, and inhibitor to a 7-ounce (207 cm3) bottle with a steel coupon, purging with a corrosive gas, and capping the bottle. The bottle is then agitated for a period of time by securing it to the circumference of a ‘wheel’ and rotating it (Figure 8.11). In the higher pressure version of the test, a pressurized autoclave is used instead of a glass bottle. There is no theoretical or hydrodynamic method to characterize the flow conditions in wheel tests. A round robin test revealed that the reproducibility of the wheel test was only 55%.16 Standards providing guidelines for performing the wheel test include: •

NACE Publication 1D182, ‘Wheel Test Method Used for Evaluation of Film Persistent Inhibitors for Oilfield Application’

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FIGURE 8.11 Wheel Test. (Courtesy Cormetrics)

iv. Rotating disc electrode (RDE) test The rotating disk is very popular in electrochemical studies, because flow conditions can be simulated easily. It has been extensively used to differentiate charge controlled processes from diffusion controlled processes (see section 5.2). A typical RDE apparatus consists of a rotating unit driven by a motor that is attached to a sample holder. At the side of the sample holder, electrochemical connections to the electrodes are made by brush contact. The RDE can be used both as a mass loss coupon and as an electrode. The surface area is small (typically 120 to 200 mil (w3 to 5 mm) in diameter) therefore corrosion is monitored using conventional electrochemical techniques. The hydrodynamic relationship between the RDE under laminar conditions and the pipe is given as (Eqn. 8.5):17–20  0:15
1=2 (Eqn. 8.5) Rep ¼ 79ðdpipe =rRDE Þ εpipe =dpipe Sc 1=6 ReD

where Rep is the Reynolds number for the pipe (Eqn.8.6), dpipe is the diameter of pipe, rRDE is the radius of the rotating disk, εpipe is the roughness of pipe wall, Sc is the Schmidt number (Eqn.8.7), and ReD is the Reynolds number for the rotating disk (Eqn. 8.8). Equation 8.5 is applicable for an RDE operating under laminar flow condition. Other equations to correlate RDE flow to other flow conditions are also available.18   Udpipe (Eqn. 8.6) Rep ¼ n n Sc ¼ (Eqn. 8.7) D   u:rRDE 2 (Eqn. 8.8) ReD ¼ n where U is the flow rate of fluid, n is the kinematic viscosity, D is the diffusion coefficient, and u is the angular velocity (rad/s). The RDE predominantly operates under laminar flow conditions. It does not adequately simulate turbulent flow effects, and the maximum wall shear stress created is 5 Pa. For these reasons, the RDE is not used in the oil and gas industry.

8.2 Laboratory measurement

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v. Rotating cylinder electrode (RCE) test The design of the RCE has several features in common with that of the RDE. An RCE test can be carried out using the same rotating electrode system, except that in this case the sample is a cylinder. The RCE uses a well-defined rotating specimen setup and mass loss and/or electrochemical measurements to determine corrosion rates in a laboratory apparatus. A typical RCE system is shown in Figure 8.12.10 The RCE test system is compact, relatively inexpensive, and easily controlled. The electrode rotates at various speeds, providing stable and reproducible flow in relatively small volumes of fluid. Measurements are made at a number of rotation rates under increasingly severe hydrodynamic conditions. The flow of RCE is hydrodynamically characterized. The wall shear stress of the RCE, sRCE, is given as (Eqn. 8.9):21 2 sRCE ¼ 0:079Rec 0:3 rsolution rRCE u2

(Eqn. 8.9)

where Rec is the Reynolds number of the rotating cylinder (Eqn.10); rsolution is the solution density; and rRCE is the radius of the cylinder.   u:rRCE 2 (Eqn. 8.10) Rec ¼ n

Equation 8.9 can be used as a first approximation to establish the appropriate RCE velocity for modeling the desired system when studying corrosion accelerated by single phase flow. There is

FIGURE 8.12 Schematic Diagram of Rotating Cylinder Electrode.10 1. Electrical Contact Unit; 2. Tachometer (Rotation Speed Display); 3. Rotation Controller; 4. Electrochemical Measurement Unit; 5. Rotating Electrode Unit (Working Electrode); 6. Reference Electrode; 7. Water Cooler Coil; 8. Inlet (Gas and Solution); 9. Thermocouple; 10. Outlet (Gas and Solution); 11. Counter Electrode; 12. Autoclave Body; 13. Solution; and 14. Liner. Reproduced with permission from ASTM.

Polarization Resistance, ohm/cm 2

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12 out of 19 within 5% Error 17 out of 19 within 10% Error

93

0 1

2

3

4

5

6

7

8

9 10 11 # of Runs

12

13

14

15

16

17

18

19

FIGURE 8.13 Results on Reproducibility of RCE.24 Reproduced with permission from NACE International.

general agreement that the Eqn. 8.9 adequately describes the hydrodynamic conditions of RCE, but several other relationships are available to correlate the RCE flow and pipe flow and hence the corrosion conditions.22,23 Standards providing guidelines for performing RCE test include: •

ASTM G185, ‘Standard Practice for Evaluating and Qualifying Oil Field and Refinery Corrosion Inhibitors Using the Rotating Cylinder Electrode’

Figure 8.13 presents round robin test results carried out based on the procedure described in ASTM G185. As can be seen from the figure, good reproducibility (within 10%) was obtained in 17 out of 19 tests in three of the four laboratories. The fourth laboratory consistently produced results with larger experimental errors than those of the others. The results of the round robin experiments confirmed that the reproducibility of RCE is good, and that the scatter observed in the fourth laboratory is due to operator error (extrinsic) rather than any defect in the methodology (intrinsic)24 (see also Chapter 12).

vi. Rotating cage (RC) In 1990, the rotating cage was introduced as a promising laboratory method for simulating pipe flow in the laboratory by rotating the specimens at speeds up to 1500 rpm.25,26 The rotating cage is also known as the high-speed autoclave test (HSAT) or rotating probe.27–29 The methodology is compact, inexpensive, hydrodynamically characterized, and scalable (i.e., the tests can be carried out under various flow conditions). Several variables can be simulated, including composition (of the steel, brine, oil, and gas); temperature; pressure; and flow. Figure 8.14 shows a schematic diagram of the rotating cage system. The vessel can be manufactured from acrylic or polytetrafluoroethylene (PTFE). A PTFE base fits snugly at the bottom of the container. A hole is drilled at the center of the PTFE base, into which the lower end of the stirring rod is placed. This arrangement stabilizes the stirrer and the coupons. Eight coupons (surface area 14 inch2

8.2 Laboratory measurement

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FIGURE 8.14 Schematic Diagram of Rotating Cage. Reproduced with permission from ASTM.

(35.8 cm2)) are supported between two PTFE disks mounted 3 inch (76 mm) apart on the stirring rod of the autoclave. Holes are drilled in the top and bottom PTFE plates of the cage to increase the turbulence on the inside surface of the coupon. This experimental setup can be used at temperatures up to 150 F (70 C) and rotation speeds up to 1000 rpm. For elevated pressure experiments, an autoclave is used instead of acrylic or PTFE vessels. The flow characteristics of a rotating cage vary with cage dimensions, liquid levels, rotation speeds, and liquid types. The flow pattern in the absence of rotating cage is similar to that of the RCE because the experimental set-ups are similar. One characteristic aspect of a rotating cage is the formation of a vortex (Figure 8.15). Under most conditions, the ratio of vortex length to rotating speed is about 3 mm/ 100 rpm. As a first approximation, rotating cage wall shear stress can be calculated using Eqn. 8.11, which includes both wall shear stress due to cylinder (sRCE) and due to vortex (svortex): sRC ¼ 0:079ReRC

0:3

rsolution rRC 2 u2:3

(Eqn. 8.11)

where sRC is the wall shear stress of rotating cage, ReRC is the Reynolds number of the rotating cage (Eqn. 8.12), and rRC is its radius.   u:rRC 2 ReRC ¼ (Eqn. 8.12) n Computational fluid dynamics (CFD) analysis indicates that the wall shear stress varies somewhat with time. The shear stress is generally higher on the leading edge compared to the trailing edge, and higher on the outer face compared to the inner face. On the leading edge, the shear stress is higher toward the inner face. On the trailing edge, the shear stress is higher toward the inner face. On the outer face, the

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FIGURE 8.15 Flow Patterns of Rotating Cage.12 (A) Rotating cage homogeneous zone. (B) Rotating cage in top-cover affected zone (Compared with Figure A, the Vortex is less). (C) Rotating cage in turbulent zone. (D) Rotating cage in side-wall affected zone. Reproduced with permission from ASTM.

shear stress is higher toward the trailing edge. And on the inner face, the shear stress is higher toward the leading edge (Figure 8.16).30 These fluid dynamics lead to the shear stress distribution on the coupons. The highest speeds occur near the coupons, since they drive the flow. The relative variation in velocity leads to variations in shear stress. The flow speed past the coupon is low due to the fact that the coupons and the water are moving in the same direction. In one study the rotating cage was identified as the preferred methodology for evaluating corrosion inhibitors.28 This assessment was based on a quantitative comparison of field and laboratory data on general corrosion rates, pitting corrosion rates, and percentage inhibition (calculated from general and pitting corrosion rates) under three different field conditions using three continuous and three batch inhibitors. By comparing the results of the field and laboratory experiments at the same inhibitor concentrations, a study found that the RC test was the top ranked laboratory methodology based on the comparison of laboratory and field general and pitting corrosion rates. This methodology produced

8.2 Laboratory measurement

447

FIGURE 8.16 Rotating Cage Flow Pattern: Computational Fluid Dynamics (CFD) Analysis (Different Colors Presents Values of Wall Shear Stress in Pascals).30 Reproduced with permission from NACE International.

higher pitting corrosion rates, and is a more stringent, tougher test for the inhibitor to pass. Several inhibitors exhibited lower efficiencies when tested with this methodology. The reasons for the simulation of pitting corrosion in the rotating cage are due to the variation in the flow pattern on various sides of the coupons. Standards providing guidelines for performing rotating cage tests include: • • •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’ G184, ‘Standard Practice for Evaluating and Qualifying Oil Field and Refinery Corrosion Inhibitors using the Rotating Cage’ G202, ‘Standard Test Method for Using the Atmospheric Pressure Rotating Cage’

An inter-laboratory program of round robin tests established a bench-mark average corrosion rate of 23  2 mpy (0.06  0.01 mm/y) for carbon steel in synthetic ocean water.31

vii. Jet impingement Jet impingement has been used to simulate flow patterns in the laboratory by many industries, including aerospace and power generation since the 1950s, and the oil and gas industry started using it in the 1990s.32–35 Several studies comparing the corrosion rates of various methodologies found that jet impingement was most suitable for simulating flow conditions in pipelines, and for the evaluation of oil field corrosion inhibitors. Figure 8.17 presents the typical flow field established by a jet impinging on a flat plate with its central axis normal to the plate (i.e., specimen). Depending on the flow characteristics, the flat plate (specimen) can be divided into three regions.

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FIGURE 8.17 Flow Pattern of Jet Impingement.36 Reproduced with permission from ASTM.

In Figure 8.17, Region A is known as the stagnant region. This stagnation region occurs directly beneath the jet and extends radially up to r ¼ 2rjet. The flow in this region is uniformly accessible to mass transfer. In this region, the wall shear stress is given by: sstag ¼

1:312rðmrsolution Þ0:5 a1:5 jet

(Eqn. 8.13) 2

where sstag is the wall shear stress of the jet impingement stagnant region, N/m (or Pa); r is the radius of specimen, m is the dynamic viscosity, kg/m s; and ajet is a hydrodynamic constant (a value between 100 and 300 s 1 is assumed). In Figure 8.17, Region B is known as the wall jet region, in which the principle velocity component is parallel to the plate. The flow pattern is characterized by high turbulence, large velocity gradient at the wall, and high wall shear stress. This region starts at approximately r ¼ 2rjet and extends radially by up to approximately r ¼ 4rjet. In the wall jet region, the wall shear stress is given by:  2:0 r sw ¼ 0:179rsoluion Uo;jet 2 Rejet0:182 (Eqn. 8.14) rjet where s,w is the wall shear stress in jet region, N/m2 (or Pa); Uo, jet is the mean fluid velocity in the jet, m/s; Rejet is the Reynold’s number of the jet (Eqn.8.15); and rjet is the radius of jet, m. Where the Reynolds number of the jet is defined as: 2rjet Uo (Eqn. 8.15) n In Figure 8.17, Region D is known as the hydrodynamic boundary region, and it starts at approximately r ¼ 4rjet. In Region D, the jet flow rate and turbulence decrease rapidly. This region is not hydrodynamically solved because the fluid velocity is low. Rejet ¼

8.2 Laboratory measurement

449

FIGURE 8.18 Schematic Diagram (Side-View) of Impinging Jet on a Specimen in Stagnation Region, i.e., r/rjt is Less than 2. (The unit of x-axis is radial distance, r/rjet). Reproduced with permission from ASTM.

In addition, a low turbulence wall jet region (Region C, Figure 8.17) exists above the hydrodynamic boundary layer in which the turbulence is low. Because this region is at an axial distance far away from the plate, its fluid properties are similar to the surrounding bulk fluid. Jet impingement is a widely used technique to study flow-accelerated corrosion. Experimental results at very high wall shear stress, up to 1000 Pa, have been reported. A jet impingement apparatus can be used in all applications in which a rotating cage can be used, but it is typically used to create high-shear stress flow conditions, typically above 200 Pa. There are three jet impingement designs. Design 1: In this design the working electrode (specimen) is a disc and is exposed only to the stagnation region (Figure 8.18).36 The diameter of the specimen is equal to or less than the diameter of the jet nozzle. The typical distance between the jet nozzle tip and specimen is five times the diameter of the jet nozzle. The jet system is a submerged type and it impinges at 90 onto the specimen. Both the counter electrode and the reference electrode are placed adjacent to the nozzle, so that they are not in the path of the jet impinging on the working electrode. Design 2: In this design the working electrode (specimen) is a ring and is exposed only to the jet region (Figure 8.19).36 The diameter of the specimen is three times the diameter of the jet nozzle. Both the inner and outer diameters of the ring specimen are within the jet region. The counter electrode is placed at the end of the jet nozzle. The reference electrode is placed adjacent to the counter electrode. Design 3: In this design, the specimen is a disc and is exposed to all three regions of the jet (stagnant, jet, and hydrodynamic regions) (Figure 8.20).36 This design facilitates the occurrence of

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CHAPTER 8 Monitoring – Internal Corrosion

FIGURE 8.19 Schematic Diagram (Side-View) of Impinging Jet on a Specimen in Wall Jet Region.36 (The unit of x-axis is radial distance, r/rjet). Reproduced with permission from ASTM.

FIGURE 8.20 Schematic Diagram of Impinging Jet on a Specimen Covering Stagnation, Wall Jet, and Hydrodynamic Boundary Regions.36 The unit of x-axis is radial distance, r/rjet. Reproduced with permission from ASTM.

8.2 Laboratory measurement

451

FIGURE 8.21 Schematic Diagram of Jet Impingement Apparatus (Design 3) with Four Disc Specimens.37 Reproduced with permission from NACE International.

localized corrosion, as the specimen is under the influence of various regions (stagnation, wall jet, and hydrodynamic regions). The diameter of the specimen is five times the diameter of the jet nozzle. The larger size of the specimen enables it to be used as a mass loss coupon. The counter electrode is placed on the return path of the jet to avoid interference with the jet flow. The reference electrode is placed in the side of the jet arm. This design uses multiple specimens (typically four) (Figure 8.21). The jet is created in a central cell with four arms containing four nozzles. The impeller is housed in the cell body and is driven by a motor magnetically coupled to the impeller shaft. Fluid from the cell is forced by the impeller through the nozzles and is re-circulated to the cell. All moving parts of the pump are located inside the central cell.37 Standards providing guidelines for performing jet impingement apparatus include: • •

ASTM G170, ‘Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory’ ASTM G208, ‘Standard Practice for Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors Using Jet Impingement Apparatus’

8.2.2b Monitoring techniques Monitoring techniques determine corrosion simulated by laboratory methodologies. There are a number of different types: Online, non-destructive: These techniques determine the corrosion rate repeatedly while the experiment is in progress because they do not change the state of metal. They include linear polarization resistance (LPR), electrochemical impedance spectroscopy (EIS), electrochemical noise (EN),

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and electrochemical quartz crystal microbalance (EQCM). This type may further be sub-divided into continuous and frequent. EN is a good example of a continuous measurement, in which the sample can be monitored continuously from the start to the finish of the experiment. On the other hand, LPR and EIS are examples of frequent measurements, because an external signal is sent to the specimen and the response is recorded. The time needed for sending the signal and recording the response may vary between 20–40 sec (for LPR) and 5–20 min (for EIS). The frequency of measurement depends on the number of times the signal is sent and on the duration of each measurement. Online, destructive: These techniques determine the corrosion rate while the experiment is in progress. They measure this only once, because they change the state of the specimen during the measurement. A good example of this type of technique is potentiodynamic polarization (PP), in which application of higher potential in the positive direction may cause pitting corrosion on the surface of the specimen. Offline: These techniques determine the corrosion rate after the specimen has been retrieved from the laboratory methodology. A good example under this type is the mass loss method. The following paragraphs discuss some characteristics of these monitoring techniques.

i. Mass loss To determine the corrosion rate, the specimens (commonly referred to as coupons) are exposed for a pre-determined period in a laboratory methodology. The coupons are cleaned and weighed before and after the experiment to remove the surface and/or corrosion products. The corrosion rate is calculated from the mass lost during the test: C:R: ¼

K:W A:t:Dspecimen

(Eqn. 8.16)

where Kmass is a constant, W is the mass lost in gms, A is the surface area of the specimen in cm2, t is the duration of exposure of specimen in hours, and Dspecimen is the density of specimen in g/cm3. Table 8.3 present Kmass value to convert mass loss into various corrosion rate units.38 Corrosion rates in rotating cage and wheel tests are determined only by mass loss. This method can, in principle, be used in all laboratory methodologies, but in practice it is used when the specimen is

Table 8.3 Constants (Kmass) to Convert Mass Loss into Corrosion Rate38 Corrosion Rate Unit

Kmass (See Eqn. 8.16)

Mils per year (mpy) Inches per year (ipy) Inches per month (ipm) Millimeters per year (mm/y) Micrometers per year (um/y) Picometers per second (pm/s) Milligrams per square decimeter per day (mdd) Micograms per square meter per second (mg/m2-s) Grams per square meter per hour (g/m2-h)

3.45 3.45 2.87 8.76 8.76 2.78 2.40 2.78 1.00

        

106 103 102 104 107 106 106 x Dspecimen 106 x Dspecimen 104 x Dspecimen

8.2 Laboratory measurement

453

reasonably large, so that the mass lost can be measured accurately (see also Table 8.1). Corrosion rates calculated from mass loss are only useful if the corrosion is general (or uniform). When localized corrosion takes place (e.g., pitting or crevice corrosion), the pits on the specimen should be measured using depth gage or micrometer or laser profilometer. In general, three results are obtained from mass loss specimens: a corrosion rate from the mass lost, pit depths, and pitting factor (ratio of the deepest metal penetration to the average metal penetration (determined by mass loss)). Standards providing guidelines for determining the corrosion rate using the mass loss method include: • • •

ASTM G1, ‘Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens’ ASTM G31, ‘Standard Practice for Laboratory Immersion Corrosion Testing of Metals’ ASTM G46, ‘Standard Guide for Examination and Evaluation of Pitting Corrosion’

ii. Electrochemical techniques The electrochemical techniques usually involve applying an electrochemical signal to the specimen, commonly known as the working electrode (WE), and measuring the response of the electrode to that signal. When the electrode is electrochemically excited it moves away from the corrosion potential, and therefore it is said to be polarized (see section 5.2 for discussions on the electrochemical mechanism of corrosion). For this reason, most electrochemical techniques are called polarization techniques. Electrochemical techniques require some additional components, including a counter electrode (CE), a reference electrode (RE), a conducting electrolyte (i.e., environment), a potentiostat, a potential-measuring instrument, a current-measuring instrument, and a Luggin capillary with a salt bridge connection to the RE. The WE is the primary electrode, whose corrosion rate is being measured. Care should be taken properly to prepare and mount (without any crevice) this electrode. Figures 8.9 and 8.22 illustrate a simple method to mount the WE.39 A leak-proof assembly is obtained by the proper compression fit between the electrode and an insulator gasket. The potential of a single electrode cannot be measured; only the difference between two electrodes can be measured. For this reason, standard reference electrodes with stable and reproducible potentials are used. Table 8.4 presents some commonly used reference electrodes, their reversible potential, and factors to convert the potential from one reference electrode to another. Sometimes the reference electrode is placed in a separate vessel and is connected to the working electrode through a Luggin capillary with salt bridge (Figure 8.23).39 This arrangement minimizes the contamination of the RE with the products of corrosion reactions. Further the standard RE is electronically connected to the WE through a high-impedance voltmeter. This arrangement prevents any current from passing through the RE; i.e., during corrosion measurement the current is not passed through the RE. To apply current or potential to the WE, a third electrode known as the auxiliary (AE) or counter electrode (CE) is used. During electrochemical measurements, the CE is polarized in the opposite direction to the WE, i.e., if the WE is polarized in the noble (positive) direction, the CE is polarized in the active (negative) direction. The counter electrode is usually made from inert material, e.g., platinum or graphite, or from same material as the WE. In some cases, two CEs are used. The CE is mounted in the same way as the WE.

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FIGURE 8.22 Mounting Specimen (1. Excessive Compression; 2. Proper Compression; and 3. Insufficient compression).39 Reproduced with permission from ASTM.

Thus in an electrochemical measurement three electrodes are used: the WE (the material whose corrosion rate is measured), then CE (acts as opposite electrode), and the RE (to monitor the potential of the WE). The current flows through the WE and the CE, but not through the RE. In some measurements, a single material is used as both the CE and RE. However, in this configuration it should be

Table 8.4 Potentials of Standard Reference Electrodes and Conversion Factors to Convert Potentials against one Standard Reference Electrode to Another40 To Convert toz Reference Electrode

Common Abbreviation

Potential (V) at 25 C (Vs. SHE)y

Thermal Coefficient (mV)

SHE Scale

SCE Scale

Hydrogen Silver-Silver chloride Saturated calomel electrode Copper-copper sulfate

SHE Ag/AgCl) SCE))

0.000 þ0.235 þ0.241

þ0.87 þ0.25 þ0.22

N/A þ0.235 þ0.241

0.241 0.006 N/A

CCS

þ0.300

þ0.90

þ0.300

þ0.060

)

with 1 M KCl as internal electrolyte; in addition sea water with 0.6 M chloride ion or solution with 0.1 M chloride ion is also used as internal electrolyte )) the internal electrolyte contains excessive amounts of potassium chloride (KCl) crystals; therefore the electrolyte is saturated; in addition 0.1 M KCl or 1 M KCl solution is used as internal electrolyte y the potential of reference electrodes depend on the concentrations of internal electrolyte z An electrode potential of þ1.000 V versus SCE would be (1.000 þ 0.241) equal to þ1.241 V versus SHE. On the other hand, an electrode potential of 1.000 V versus SCE would be ( 1.000 þ 0.241) equal to 0.759 V versus SHE

8.2 Laboratory measurement

455

POTENTIOSTAT WORKING AUXILIARY

REFERENCE

SALT-BRIDGE PROBE A U X

W E

POLARIZATION CELL

S C E REFERENCE CELL

FIGURE 8.23 Schematic Diagram of a Setup to Connect a Reference Electrode to an Electrochemical Cell through a Salt Bridge.39 Reproduced with permission from ASTM.

understood that the potential of the WE is measured against the single electrode which may not have a well-defined value. The basic requirement of any electrochemical measurement is the presence of a conducting (lowresistivity) electrolyte. Figure 8.24 presents some guidelines on the operating range of solution conductivities in which electrochemical polarization measurements can be made reliably.41 Standards providing guidelines for establishing the applicable range of electrochemical techniques include: • •

ASTM G96, ‘Standard Guide for Online Monitoring of Corrosion in Plant Equipment (Electrical and Electrochemical Methods)’ ASTM D1125, ‘Standard Test Methods for Electrical Conductivity and Resistivity of Water’

Most corrosion reactions occur in the potential range 2 to þ2 V and in the current range between 1 and 106 mA. The potential is applied by an instrument called a potentiostat. Modern computer

high purity distilled water

good quality distilled water

rain water

normal range of cooling waters

seawater

mile per year

good quality drinking water

CHAPTER 8 Monitoring – Internal Corrosion

mm per year

456

10,000 Typical Corrosion Rate of Carbon Steel

100 1,000 Non–operating Region

10 100 1 A

10 0.1

B

C

D

Operating Region

2

1

1

3

0.01 0.1 100K

10K

1K

100

10

1

0.1

Conductivity (µ mhos/cm) 1

2 electrode probe with high frequency compensation for solution resistance

2

Close spaced 3 electrode probe

3

2 electrode probe or 3 electrode probe with reference electrode equispaced from the test and auxiliary electrodes

FIGURE 8.24 Guidelines on Regions in which Reliable Corrosion Rate Measurements can be Made.41 Reproduced with permission from ASTM.

controlled potentiostats with user-friendly software, have multiple functions, including applying potential, monitoring current, storing and analyzing data, and producing graphical trends. Ideally, the first measurement in any electrochemical experiment is the measurement of the corrosion potential (Ecorr) of the WE with respect to an RE. This should be measured for sufficiently long for it to reach a steady state. The corrosion potential indicates the tendency of a metal to undergo corrosion, but not the corrosion rate. To measure the corrosion rate, the electrode may be polarized by direct current (DC) or alternating current (AC). In the DC technique, the electrode may be polarized in four ways: • •

Potentiostatic: The potential of the WE is controlled at a constant value and the response of current is monitored. Potentiodynamic: The potential of the WE is varied at a constant rate and the response of the current is continuously monitored.

8.2 Laboratory measurement

• •

457

Galvanostatic: The current of the WE is controlled at a constant value and the response of potential is monitored. Galvanodynamic: The current of the WE is varied at a constant rate and the response of the potential is continuously recorded.

Corrosion rates are normally monitored by controlling potential (potentiostatic or potentiodynamic) rather than by controlling current (galvanostatic or galvanodynamic). Linear polarization resistance (LPR) and potentiodynamic polarization are commonly used DC techniques. During LPR measurements, the polarization of WE is small (less than  30 mV), hence the corrosion rate can be monitored repeatedly. On the other hand, in the potentiodynamic polarization technique the polarization of WE is large (more than  500 mV) and in some measurements the scan is reversed (cyclic potentiodynamic polarization). This means that only one measurement can be obtained during the experiment. EIS is an AC method. The corrosion rate may also be measured without polarizing the WE. Electrochemical noise is a commonly used method of measuring corrosion without applying polarization. Table 8.5 presents some general characteristics of various electrochemical measurements.

iii. Polarization resistance method About 60 years ago, Stern and Geary found that the slope of a current-potential plot around the corrosion potential is essentially linear (Figure 8.25), and named that slope the polarization resistance (Rp).42,43 It is related to corrosion current (Icorr) as follows: Icorr ¼

B Rp

(Eqn. 8.17)

The constant B is defined as (Eqn. 8.18): B¼

ba : bc 2:303 ðba þ bc Þ

where ba and bc are anodic and cathodic Tafel constants. By combining Eqns. 8.17 and 8.18:   1 ba : bc Icorr ¼ RP 2:303 ðba þ bc Þ

(Eqn. 8.18)

(Eqn. 8.19)

If ba and bc are known, the corrosion rate can be calculated from Rp. Their values may either be determined by the Tafel extrapolation method or may be assumed. Table 8.6 presents typical values of B, ba, and bc.40 In the majority of cases, the values of b fall between 60 and 120 mV, so in many instances a value of 120 mV is assumed for both ba and bc. Consequently Eqn. 8.19 may reduce to Eqn. 8.20: Icorr ¼

26 Rp

(Eqn. 8.20)

Figure 8.26 presents the error in determining the corrosion current using Eqn. 8.20. In the figure, negative error values indicate that the actual corrosion rate is higher than the one determined, and positive values indicate that the actual corrosion rate is lower than that measured.

Table 8.5 Characteristics of Different Electrochemical Methods of Monitoring Corrosion Rate Information Obtained

Type of Corrosion Studied

Relevant Standards

Polarization resistance

Application of  30 mV (typically  10 mV) around corrosion potential

• Corrosion current from polarization resistance

• General corrosion

Tafel extrapolation

Application of an overpotential of þ500 mV both in anodic and cathodic directions, from corrosion potential Application of overpotential from corrosion potential towards noble direction to a potential at which current is 5 mA, where the potential is reversed and scanned until hyteresis loop is completed or until corrosion potential is reached Application of current steps (typically in 20 mA/cm2 increments between 0 to 120 mA) both in anodic and cathodic directions Application of one potential step (typically to 700 mV vs. SCE)

• Corrosion current (Icorr), and Tafel slopes (anodic and cathodic)

• General corrosion

• ASTM G3 • ASTM G5 • ASTM G59 • ASTM G102 • ASTM G5 • ASTM G102

• Critical pitting potential, passive current, transpassive region

• Pitting corrosion

• ASTM G5 • ASTM G61 • ASTM G102

• Protection potential (Eprot) and breakpoint potential (Eb).

• Pitting corrosion

• ASTM G100

• Change of current with a variable e.g., temperature (determination of critical pitting temperature) • Protection potential and breakpoint potential.

• Pitting corrosion

• ASTM G150

• Pitting corrosion

• ASTM F746

• Galvanic current

• Galvanic corrosion

• Corrosion current from polarization resistance

• General corrosion

• ASTM G71 • ASTM G82 • ASTM G106

• Corrosion current from noise resistance • Pitting factor

• General corrosion • Pitting corrosion

Cyclic potentiodynamic polarization

Cyclic galvanostatic polarization

Potentiostatic polarization

Galvanic corrosion rate

Electrochemical impedance spectroscopy Electrochemical noise

Application of potential step to a more positive potential (above Eb), and stepping it down to a less positive potential (below Eb) Immersion of two dissimilar metals in an electrolyte and electrically connecting them using zero resistance ammeter Application of AC potential  10 mV around corrosion potential, over a wide range of frequency, typically 0.1 Hz to 106 Hz Measuring potential and current fluctuation continuously

• ASTM G199

CHAPTER 8 Monitoring – Internal Corrosion

Typical Measurement

458

Polarization Method

Polarization (E - E corr) (+)

8.2 Laboratory measurement

Slope =Rp

Current density (+) Polarization (E - Ecorr) (-)

Current density (-)

459

FIGURE 8.25 Hypothetical Linear Polarization Resistance Plot.42,43

During LPR measurement, the corrosion potential of the WE is measured against a RE. In most situations, the corrosion potential stabilizes within one hour. After that the potential is applied and the current response of the WE is measured. The potential may be applied in increments of  5 mV (potential step method), or it can be scanned at a constant rate (typically 600 mV/h) (potentiodynamic method). In both methods, the test is started at potential negative to corrosion potential, and moved in the positive direction through the corrosion potential. Rp is determined from the slope of the potentialcurrent plot. Assuming that the current distribution across the WE is uniform: Icorr icorr ¼ (Eqn. 8.21) A where icorr is the current density (mA/cm2). Based on Faraday’s law, the corrosion rate (X) (Eqn. 8.22) or mass loss rate (MR) (Eqn.8.23) can be calculated as:   icorr EW (Eqn. 8.22) CR ¼ Kcorr rmetal MR ¼ KMR : icorr : EW

(Eqn. 8.23)

where CR is given in mm/y; Icorr in mA/cm2, Kcorr is a constant with a value of 3.27 x 10 3 unit mm g/ mA cm y; EW is the equivalent weight; MR is g/m2; and KMR is a constant with a value of 8.954 x 10 3 g cm2/mA m2 d. Table 8.7 presents other values of Kcorr and KMR.45 The equivalent weight, EW, is the mass in grams that will be oxidized by the passage of one Faraday (96,489 C (amp-sec)) of electric charge. For pure elements, EW is given as: Awt (Eqn. 8.24) EW ¼ n

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CHAPTER 8 Monitoring – Internal Corrosion

Table 8.6 Values of Constant ‘B’ for the Polarization Resistance Method40 Corroding System

ba, mV

bc, mV

B, mV

Theoretical (Values of B calculated from arbitrary ba and bc values using formulas given in Eqns. 9 and 10; ba and bc values can be interchanged).

30 30 30 30 30 60 60 60 60 60 90 90 90 90 120 90 120 120 180 180 e e e e e

30 60 120 180 N 60 90 120 180 N 90 120 180 N 120 N 120 N 180 N e e e e e

6.5 9 10 11 26 13 16 17 20 26 20 22 26 39 26 39 26 52 39 78 17 17 10e20 18e23 12

57 e

N e

25 19

N 85

50 160

22 24

N e 82

50 e 160

22 20 24

e

e

44

Aluminum, seawater

45

600

18

Zircaloy 2, lithiated water, 288 C Copper, 1 N NaC1, H2, pH 6.2, 30 C

N

186

81

e

e

26

Iron, 4% NaC1, pH 1.5 Iron, 0.5 N H2SO4, 30 C Iron, 1 N H2SO4 Iron, 1 N HCI Iron, 0.02 M citric acid, pH 2.6 35 C Carbon steel, seawater Carbon steel, 1N Na2SO4, H2, pH 6.3, 30 C 304 L SS, 1 N H2SO4, O2 304 SS, lithiated water, 288 C 304 SS, 3% NaC1, 90 C 430 SS 1 N H2SO4, H2, 30 C 600 alloy, lithiated water, 288 C Al 1199, 1 N NaC1, pH 2, 30 C

8.2 Laboratory measurement

461

200 150

Percentage Error

100 50 0 -50 -100 -150 -200 0

20

40

60

80

100

Actual B Values

FIGURE 8.26 Percentage Error in Calculating Icorr Assuming a B Value of 26.44 Reproduced with permission from Woodhead.

Table 8.7 Constants to Convert Corrosion Current into Penetration Rate and Mass Loss Rate45 (A) Corrosion Rate mpy mm/yr mm/yr

Kcorr)

Density

Icorr 2

mA/cm A/m2 mA/cm2

3

g/cm Kg/m3 g/cm3

0.1288 mpy g/mA cm 327.2 mm kg/A m y 0.00327 mm g/mA cm y (B)

Mass Loss Rate

Icorr

KMR)

g/m2d mg/d m2d (mdd) mg/d m2d (mdd)

A/m2 mA/cm2 A/cm2

0.8953 g/Ad 0.0895 mg cm2/mA dm2 d 0.00895 mg cm2/mA dm2 d

)

Equivalent weight is assumed to dimensionless

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CHAPTER 8 Monitoring – Internal Corrosion

where Awt is the atomic weight of the element and n is the number of electrons required to oxidize an atom of the element in the corrosion process, i.e., the valence of the element. The EW of an alloy is calculated as: 1 EW ¼ P n f

i i

(Eqn. 8.25)

wi

where ni is the valence of the ith element of the alloy; Awt.i is the atomic weight of the ith element of the alloy, and fi is the mass fraction of the ith element of the alloy. The advantages of the polarization resistance method are: the corrosion current is measured rapidly (typically within one minute), and hence this technique can be used as an online monitoring technique; only very small potentials are applied (less than  30 mV, typically less than  10 mV), hence the corrosion rate is not affected by the measurements; it can be used to measure low corrosion rates (less than 0.1 mils per year); and the measurements can be made repeatedly. Certain limitations of LPR should also be understood. During actual measurement, the total resistance, R, is measured. This consists of two components, Rs (solution resistance) and Rp. It is assumed that Rs is very low, so that the measured R is approximately equal to Rp. It is for this reason that electrochemical techniques, including the polarization resistance technique, generally require a conducting medium. In poorly conducting media, the electrochemical reading should be corrected for the solution resistance. The correction is commonly known as the iR drop correction. The i-E curve around the corrosion potential may not be linear, and the curvature in the anodic and cathodic regions may or may not be symmetrical. A symmetrical i-E curve is only obtained when both ba and bc are equal. The errors associated with assuming the values of ‘B’ should be understood (Figure 8.26). In calculating the EW of alloys, it is assumed that the process of oxidation (corrosion) is uniform and does not occur selectively to any component of the alloy. If this is not true then the calculation should be adjusted. Further, assigning the valency of elements that exhibit multiple valences can create uncertainty. Standards providing guidelines for measuring the corrosion rate using the LPR technique include: • • • •

ASTM G3, ‘Standard Practice for Conventions Applicable to Electrochemical Measurements in Corrosion Testing’ ASTM G5, ‘Standard Reference Test Method for Making Potentiostatic and Potentiodynamic Anodic Polarization Measurements’ ASTM G59, ‘Standard Test Method for Conducting Potentiodynamic Polarization Resistance Measurements’ ASTM G102, ‘Standard Practice for Calculation of Corrosion Rates and Related Information from Electrochemical Measurements’

iv. Tafel extrapolation method More than 100 years ago, Tafel found that a linear relationship exists between E and log I if the electrode is polarized to sufficiently large potentials, both in the anodic and cathodic directions.46,47 The regions in which such a relationship exists are known as Tafel regions. Equation 8.26 expresses this relationship mathematically:

8.2 Laboratory measurement

I ¼ Icorr



exp




2:303 Eappl ba

Ecorr



exp



2:303ðE Ecorr Þ bc



463

(Eqn. 8.26)

where Eappl is the applied potential; Ecorr is the corrosion potential; and ba and bc are the anodic and cathodic slopes of E-log I plots in the Tafel regions, respectively. Figure 8.27 presents the polarization curve of a metal exhibiting Tafel behavior. The difference between Eappl-Ecorr is called the overpotential, h. At sufficiently large values of h (typically between 100 and 500 mV), in the anodic direction, Eqn. 8.26 becomes Eqn. 8.27: ha ¼ ba log

I Icorr

(Eqn. 8.27)

Similarly at sufficiently large hc (in the cathodic direction), Eqn. 8.26 becomes Eqn. 8.28: hc ¼

bc log

I Icorr

(Eqn. 8.28)

FIGURE 8.27 Hypothetical Cathodic and Anodic Tafel Polarization Diagram.48 Reproduced with permission from ASTM.

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FIGURE 8.28 Hypothetical Cathodic and Anodic Polarization Plot for Determining Localized Corrosion Parameters.48 Reproduced with permission from ASTM.

where ha is the anodic Tafel slope and hc is the cathodic Tafel slope. In cases where Tafel regions are observed, Icorr can be determined by extrapolation of either the anodic or cathodic Tafel regions, or both, to Ecorr (Figure 8.27). Tafel extrapolation measurements can be performed either by a potentiodynamic or by a step-wise potentiostatic polarization method. As in Rp measurements, the corrosion potential is first measured until it stabilizes. After that, the electrode is polarized in steps (typically at an increment of 25 mV for every 5 mins) and the resultant current is monitored (in the potential step method), or continuously scanned at a constant rate (typically 0.6 V/h) (potentiodynamic method). In both methods, the experiment is started at the corrosion potential and the cathodic polarization is first conducted by applying an overpotential of approximately 500 mV or until gas (e.g., hydrogen) evolution occurs at the electrode. After that, the corrosion potential is measured again until it stabilizes, and then anodic polarization is conducted by applying an overpotential so that the potential at the end of the anodic polarization is þ1.6V vs. SCE. Tafel plots are generated by plotting both anodic and cathodic data in a semi-log plot as E-log I. From the plot, three values are determined: the anodic Tafel slope, the cathodic Tafel slope, and Icorr (from backextrapolation of both anodic and cathode curves to Ecorr) (Figure 8.28).48 The main advantage of this technique is that it provides a simple, straightforward method for determining Tafel constants. Other parameters that can be determined from the potentiodynamic polarization

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curves (Figure 8.28) are the primary passivation potential (Epp, potential positive to which passive surface layers are formed), critical current density (Icc, minimum current required before surface layers are formed), the breakdown potential (Eb, potential positive to which passive surface layer is destroyed and transpassive region starts), the protection potential (Eprot, potential at which passive layers are stable and protective), and passive current (Ip, current of the electrode in Eprot). Many of these parameters are determined on the basis of empirical observations. The results obtained by this method can be a function of scan rate, pit size or depth, polarization curve shape, and specimen geometry. Therefore the results should be considered as qualitative rather than quantitative in nature. This method applies a large overpotential to the metal surface, therefore it is destructive. This is particularly true during anodic polarization, during which the metal surface may be permanently changed. For this reason the specimen is used once in the test, and cannot be reused without preparing the surface. Standards providing procedures to construct an anodic polarization plot include: •

ASTM G5, ‘Standard Reference Test Method for Making Potentiostatic and Potentiodynamic Anodic Polarization Measurements’

ASTM G5 standard is frequently used in the laboratory to ensure that the potentiostat is working properly.

v. Cyclic potentiodynamic polarization The cyclic potentiodynamic polarization method is used to qualitatively understand the pitting corrosion tendency of metals and alloys. In this method, the potential is scanned in the noble (positive) direction, monitoring the current continuously until it reaches 5 mA, at which point the scan direction is reversed (i.e., scanned in the active (negative) direction), until the hysteresis loop completes (i.e., the current in the reverse scan is lower than that of the forward scan) or until the corrosion potential is reached. The results are plotted as E-log I, as in the Tafel extrapolation method. Figure 8.29 presents a typical cyclic polarization curve.49 The potential at which the anodic current increases rapidly during the forward scan is taken as the indication of initiation of localized corrosion. The more noble (more positive) this potential is, the less susceptible the alloy is to the initiation of localized corrosion. Similarly, the potential at which the hysteresis loop completes is an indication of repassivation of localized corrosion; the more electropositive is this potential, the less likely it is that localized corrosion will occur. From Figure 8.29 it is obvious that alloy C276 is more resistant to the initiation of localized corrosion than stainless steel: increase in the potentials positive direction increases current rapidly for stainless steel than for C276 and the reverse scan of C276 exhibits hysteresis at a higher positive potential whereas stainless steel does not exhibit hysteresis at all. Standards providing procedures for conducting cyclic potentiodynamic polarization measurements include: •

ASTM G61, ‘Standard Test Method for Conducting Cyclic Potentiodynamic Polarization Measurements of Localized Corrosion Susceptibility of Iron-, Nickel-, or Cobalt-Based Alloys’

vi. Cyclic galvano-staircase polarization The cyclic galvno-staircase polarization (CGSP) method is used to determine the protection potential (Eprot) (note: Eprot may also be determined by the cyclic potentiodynamic polarization method). The protection potential may be used as an indication of the susceptibility of a metal to localized

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FIGURE 8.29 Representative Cyclic Potentiodynamic Polarization Curves.49 Reproduced with permission from ASTM.

corrosion. The more noble (more positive) is the Eprot, the less susceptible is the metal or alloy to the initiation of localized corrosion. When the applied potential is more negative than Eprot, no pits initiate, and when the applied potential is more positive than Eprot, pits may initiate even when the applied potential is less positive than the breakdown potential Eb. In this method, a current of 0 to 120 mA/cm2 is applied, in increments of 20 mA/cm2. The potential is measured at every current-step for 2 minutes. After reaching 120 mA/cm2, the current is reversed and stepped back to zero in the same increments (i.e., 20 mA/cm2). The current may be applied manually or by using a computer-controlled potentiostat. The step-up points are extrapolated to zero current to obtain Eb. Similarly, the step-down points are extrapolated to zero current to obtain Eprot (Figure 8.30).50 This method provides a quick method for determining the susceptibility to pit initiation, but it does not provide information about pit propagation. It can only be used as qualitative technique. Because a sensitive instrument is required to conduct the experiment, it cannot be routinely used for all alloys. Standards providing guidance for conducting CGSP experiments to determine susceptibility to localized corrosion include: •

ASTM G100, ‘Standard Test Method for Conducting Cyclic Galvanostaircase Polarization’

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FIGURE 8.30 Typical Application of Current in the Galvanostaircase Polarization (Upper Graph) and Typical Potential Response (Lower Graph).50 Reproduced with permission from ASTM.

vii. Potentiostatic polarization There are several ways in which potentiostatic polarization experiments are conducted. In one method, the potential is stepped only once and the variation in current is monitored. For instance, in a procedure to evaluate the resistance of stainless steel and related alloys to pitting corrosion, the potential is stepped and held constant at þ700 mV (or other suitable potential), and the variation in current is monitored as a function of other changes (e.g., temperature). Standards providing a procedure for determining the critical pitting temperature of stainless steel and related alloys include: •

ASTM G150, ‘Standard Test Method for Electrochemical Critical Pitting Temperature Testing of Stainless Steels’

In another procedure, the potential is first stepped to a higher value (to initiate pits this potential should be more electropositive than Eb) and the current is monitored. The potential is then stepped down (to sustain pit propagation this potential is more positive than Eprot) and the current is monitored again. This technique cannot be used independently without results from other Eb and Eprot measurements, as well as prior knowledge of the alloy and metal behavior.

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Standards providing a procedure for this type of measurement include: •

ASTM F746, ‘Standard Test Method for Pitting or Crevice Corrosion of Metallic Surgical Implant Materials’

viii. Galvanic corrosion rate A simple method for determining the galvanic corrosion rate (see section 5.4 for a discussion on galvanic corrosion) involves immersing two dissimilar metals in an electrolyte, connecting them together electrically, and measuring the resulting current between them as a function of time using a zero-ammeter. Standards providing guidelines for conducting galvanic corrosion measurements include: • •

ASTM G71, ‘Standard Guide for Conducting and Evaluating Galvanic Corrosion Tests in Electrolytes’ ASTM G82, ‘Standard Guide for Development and Use of a Galvanic Series for Predicting Galvanic Corrosion Performance’

ix. Electrochemical impedance spectroscopy (EIS) EIS is also known as AC impedance because it uses alternating current. The techniques apply an AC signal and measures response of the electrode. Equation 8.29 presents the relationship between current and potential when an AC signal is applied: E ¼ IZ

(Eqn. 8.29)

DE DI

(Eqn. 8.30)

where Z is the impedance and is defined as: I¼

where DE is the potential difference, which depends on AC frequency (fEIS) and time (t) as DEsin(fEISt). DI is the current difference, which depends on AC frequency, phase angle (F), and t as DIsin(fEISt þ F). During EIS measurement, a small potential, usually in the range of 5–10 mV peak-to-peak, is applied over a range of frequencies (10 2–106 Hz) and the AC current response of the WE is monitored. The potential and current data from an EIS measurement are normally presented in three forms: Nyquist plot and two types of Bode plots (Figure 8.31).51

=

FIGURE 8.31 Typical Electrochemical Impedance Spectroscopy (EIS) Plots (Bode Plot (A), Bode Plot (B), and Nyquist Plot (C).51 (A) Bode plot, Impedance magnitude versus frequency. (B) Bode plot, Phase angle versus frequency. (C) Nyquist plot (Imaginary vs. Real resistance). Note: ASTM G106 explains real and imaginary components in detail. Briefly, When sine or cosine potential wave is applied across a resistor the resultant current is also a sine or cosine wave with no phase change. on the other hand, When sine or cosine potential wave is applied across a capacitor or inductor the resultant current shifts in time. The real and imaginary components represent this difference. Reproduced with permission from ASTM.

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FIGURE 8.32 Equivalent Circuit of Corroding Surface.

In order to analyze the EIS data, a physical model (equivalent circuit) representing the electrochemical system is required. This equivalent circuit consists of resistors, capacitors, and inductors. The values of the components of the electrical circuit are varied to generate a theoretical EIS plot. This theoretical plot is then compared with the experimental plot. When both the theoretical and experimental plots match, the components used for the theoretical plot are assumed to represent the real system. Figure 8.32 presents a very simple equivalent circuit, consisting of the solution resistance (RS), polarization resistance (Rp), and double layer capacitance (Cdl). Other models of analysis EIS plots are available (see section 10.2.2b for an equivalent circuit commonly used to represent a corrosion surface with surface layers).52–55 Standards describing the EIS technique include: • •

ASTM G106, ‘Standard Practice for Verification of Algorithm and Equipment for Electrochemical Impedance Measurements’ ISO 16773, ‘Paints and Varnishes – Electrochemical Impedance Spectroscopy (EIS) on HighImpedance Coated Specimens’

x. Electrochemical noise Noise is the general term used to describe the fluctuating behavior of a physical variable with time. With respect to corrosion there are two types of noise: fluctuation in the corrosion potential (potential noise) and fluctuation in the current (current noise). There are several sources of noise, including fluctuations in the rates of the anodic and cathodic reactions. Under steady state conditions, anodic dissolution and cathodic reduction occur at equal and opposite directions and noise may be a manifestation of small difference in the rate of these reactions. Other sources are the breakdown and reformation of surface layers; variation in electrolyte concentrations near the metal surface; initiation and re-passivation of pitting or crevice corrosion; and fluctuation in mass-transport rates of reactants towards the surface or of products away from it. All these fluctuations are different from the white or random noise caused by thermal variations, which is produced by the measurement instrumentation and caused by the electrical and electronic circuits. White noises constitute a source of error in measurement. Such white noise can usually be overcome by increasing the duration of the measurement. Conversely, noise associated with corrosion is independent of measurement duration. Noise data is normally recorded using three identical electrodes, of which two are coupled through a zero resistance ammeter and the current noise between them is measured. The assumption in the EN

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471

measurement is that the current fluctuation between these two electrodes is related to variations in the corrosion process. The potential noise between this couple and the third electrode is also measured simultaneously. From the current and potential noises, the EN resistance, Rn, is calculated:56–60 Rn ¼

sE A sI

(Eqn. 8.31)

where sE is the standard deviation of the potential noise, A is the surface area of the specimen, and sI is the standard deviation of the current noise. Rn is assumed to be equivalent to RP (as determined by polarization resistance method, see Eqn. 8.17). Information about pitting corrosion may also be obtained from the noise data. Three commonly used variables are the pitting index (PI) (Eqn. 8.32), pitting factor (PF) (Eqn. 8.33), and pit indicator or coefficient of variation (CV) (Eqn. 8.34). sI (Eqn. 8.32) PI ¼ Irms where Irms is the root mean square current noise. The PI may vary between 0 and 1. Values of PI above 0.6 are assumed to indicate localized corrosion. sI (Eqn. 8.33) PF ¼ Icorr where Icorr is the general corrosion current. The PF is a measure of the stability of the general corrosion processes. sI (Eqn. 8.34) CV ¼ Imean where Imean is the absolute value of the mean coupling current (between the identical electrodes). It should be noted that Eqns. 8.31 through 8.34 are mostly based on empirical observations. The theory behind them is not yet fully established. This limitation should be considered when using these equations. Standards providing guidelines for using EN include: • •

ASTM G199, ‘Standard Guide for Electrochemical Noise Measurement’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

xi. Electrochemical quartz crystal microbalance (EQCM) EQCM is currently being developed into a reliable laboratory monitoring technique, and no standard procedure for performing EQCM is currently available. See section 10.2.2b for the principles and procedures of this technique.

xii. Scanning reference electrode technique (SRET) Conventional electrochemical techniques measure the response of the bulk material to DC or AC signals. The scanning reference electrode technique (SRET), on the other hand, measures the response of different locations by scanning the surface of a material using a fine-tipped reference electrode.61,62

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FIGURE 8.33 Typical SRET Results.63

As discussed in section 5.2, at the anodic sites the metal ions flow into the solution and the electrons generated flow to the cathodic sites through the metal. Simultaneously at the cathodic sites, the metal ions or some other species flow into the metal by receiving these electrons. Therefore the corrosion potentials of different locations of the metal surface are different. In one procedure of SRET the surface of the material is scanned using a fine-tipped reference electrode to record the potential difference. The current flow disturbs the electric field within the electrolyte. In another procedure, SRET measures these electric field variations. In yet another type of measurement, the SRET utilizes two fine platinum tips. The tips of the probe are set a little apart so that they will reside in different electric fields, but also close enough to monitor surface activity at high resolution. The dual SRET probe scans over the entire sample to make the measurement. The results are displayed as either a line map or a color coded map (Figure 8.33).63

xiii. Laser profilometer A laser profilometer can be used to map surface topography at a vertical resolution of 1mm. It can be used to determine pit distributions and depths over the entire surface of a sample. During measurement, a laser beam travels in both longitudinal and transverse directions over the sample surface, and measures the profile at pre-determined intervals (typically 10 mm). The collected profiles are then leveled using the software to correct for any overall deviation of the sample surface from the horizontal plane and then a peak count operation is performed to determine the pit depths and densities. During the analysis, the highest point on the specimen is assumed to correspond to the original metal surface (prior to immersion in a corrosive environment) and the pit depths are reported relative to this point. Figure 8.34 provides a typical surface profile recorded by a laser profilometer.64

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FIGURE 8.34 A Typical Graph from a Laser Profilometer.64

8.2.3 Mechanical forces As discussed in section 5.11 mechanical forces may be erosion, abrasion, and/or wear. When they combine with corrosion the effect may be synergistic. Laboratory methodologies have been devised to delineate the effect of individual forces. The total material loss, W, is given by: W ¼ Wmech þ Ccorr þ SMechCorr

(Eqn. 8.35)

where Wmech is the wear or erosion or abrasion rate in the absence of corrosion, Ccorr is the corrosion rate in the absence of mechanical forces, and SMech.Corr is the synergistic interaction between the two. The synergistic interaction, SMech.Corr is the sum of mechanical forces enhanced by corrosion, SMEC and corrosion enhanced by mechanical forces, SCEM. SMechCorr ¼ SMEC þ SCEM

(Eqn. 8.36)

Under corrosive wear conditions, the total material loss, W: W ¼ WMech þ Ccorr:M þ SCEM

(Eqn. 8.37)

where Ccorr.M is the corrosion in the presence of mechanical forces (Ccorr.M is usually higher than Ccorr due to enhancement of corrosion by mechanical forces). From Eqn. 8.36 and 8.37, the difference between corrosion rate in the presence of mechanical force (Ccorr.M) and in its absence (Ccorr) is equal to the difference between SMech.Corr and SMEC: SMEC ¼ SMech:Corr

SCEM ¼ CCorr:M

CCorr

(Eqn. 8.38)

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The four parameters, W, Ccorr.M, Wmech and Ccorr are determined as follows: •

•

•

•

Tests are carried out in a rotating cylinder electrode, jet impingement, or slurry wear apparatus in the presence of both corrosive fluids and wear materials. The material loss per unit area obtained from this test is W. In the same test, the corrosion rate is monitored electrochemically (normally using the LPR technique). The average corrosion rate over the period of the test is converted into material loss per unit area, and this value is CCorr.M. The test is then repeated, except that the specimen is cathodically polarized. Under this condition the mass loss due to corrosion is eliminated because the specimen is a cathode. Therefore the material loss per unit area obtained from this test is Wmech. Finally, the test is repeated under conditions in which T is determined, except that all wear causing materials are removed from the solution. The material loss per unit area from this test is Ccorr.

Standards providing guidelines for investigating the influence of mechanical forces and corrosion include: • • •

ASTM G40, ‘Standard Terminology Relating to Wear and Erosion’ ASTM G119, ‘Standard Guide for Determining Synergism between Wear and Corrosion’ ASTM G 163, ‘Standard Guide for Digital Data Acquisition in Wear and Friction Measurements’

8.2.3a Erosion Erosion may occur due to cavitation, liquid impingement, and solid impingement. All these are mechanical forces. In addition, these forces may combine synergistically with corrosion. The following sections describe procedures to evaluate the susceptibility of materials to erosion.

i. Cavitation erosion Section 5.10 discusses the mechanism of cavitation erosion. It may occur in pumps, turbines, valves, bearings, propellers, and in internal flow passages containing obstructions. Cavitation damage is simulated in the laboratory by vibrating the sample at high frequency while it is immersed in a liquid. The vibration forms and collapses cavities, causing cavitation erosion. Figure 8.35 shows a schematic diagram of a typical apparatus.65 The test apparatus is relatively small and simple. It produces axial oscillations in a test specimen inserted to a specified depth in the test liquid. The vibration causes the formation and collapse of bubbles. Using this test the cavitation erosion of different materials or a single material in various conditions (e.g., vibration amplitude) can be studied. Standards providing guidelines for performing tests to evaluate the susceptibility of materials to cavitation erosion include: • •

ASTM G 32, ‘Standard Test Method for Cavitation Erosion using Vibratory Apparatus’ ASTM G134, ‘Standard Test Method for Erosion of Solid Materials by a Cavitating Liquid Jet’

ii. Liquid impingement erosion When liquid drops or a jet impinge repeatedly on a surface, erosion occurs. The relative resistances of a material to liquid impingement erosion and cavitation erosion are similar. In both mechanisms, repeated, small-scale, high intensity pressure pulses acting on the solid surface cause the damage.

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FIGURE 8.35 Schematic Diagram of a Vibratory Cavitation Erosion Apparatus.65 Reproduced with permission from ASTM.

The liquid impingement erosion rate is not constant over time. Normally, the damage occurs at three rates: an initial incubation time in which the loss is low or absent; an accelerated erosion rate after the incubation period, and a decreasing erosion rate at the end, commonly known as ‘terminal steady state rate’. The period and length of these three stages depend on material and the environment. During the test, both incubation period and maximum erosion rate are determined. To evaluate the susceptibility of a material to liquid impingement, specimens are usually attached to a disk. As the disk rotates, the specimen passes repeatedly through impacting liquid sprays or jets. Figures 8.36 and 8.37 presents two commonly used experimental set-ups.66 The tests are conducted typically at impact velocities between 60 and 600 m/s. At lower velocities the influence of corrosion predominates, but at higher velocities the mechanism of material removal changes. In this test, the droplet size, jet size, and impact velocities can be adjusted to simulate specific liquid impingement environments. Standards providing guidelines for evaluating the susceptibility of materials to liquid impingement include: • • •

ASTM G73, ‘Standard Practice for Liquid Impingement Erosion Testing’ ASTM G 32, ‘Standard Test Method for Cavitation Erosion Using Vibratory Apparatus’ ASTM G134, ‘Standard Test Method for Erosion of Solid Materials by a Cavitating Liquid Jet’

iii. Solid impingement erosion (from gas phase) The impingement of solids particles entrained in a gas phase causes erosion. The extent of this depends on many factors, including particle sizes, velocities, attach angles, and environment. Jet nozzle type erosion equipment is used to evaluate material loss due to the impingement of solid particles entrained

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FIGURE 8.36 An Example of a Small, Relatively Low-Speed, Rotating Disk- and Jet Impingement Repetitive Impact Apparatus.66 Reproduced with permission from ASTM.

FIGURE 8.37 A Schematic Diagram of a Large, High-Speed, Rotating Arm- and Spray-Distributed Impact Apparatus.66 Reproduced with permission from ASTM.

8.2 Laboratory measurement

Supply Tube

Nozzle Tube

Nozzle Length

Mixing Chamber

477

Gas Supply

Abrasive Reservoir

Working Distance

Specimen

FIGURE 8.38 Schematic Diagram of a Solid Particle Erosion Apparatus.67 Reproduced with permission from ASTM.

in a gas phase. Figure 8.38 provides a schematic diagram of a typical laboratory apparatus.67 In this apparatus, a stream of gas containing solid particles delivered through a small nozzle impacts the specimen, and its mass loss is determined. Standards providing guidelines for performing erosion test using solid particles include: •

ASTM G76, ‘Standard Test Method for Conducting Erosion Tests by Solid Particle Impingement using Gas Jet’

8.2.3b Dry abrasion The abrasion resistance of a material depends upon the abrasive particle size, shape, and hardness, the magnitude of the stress imposed by the particle, and the frequency of contact of the abrasive particle. When the abrasion conditions are uniform, it may be referred to as scratching abrasion, and may be used to rank various materials in a given abrasive environment. Figure 8.39 presents a typical apparatus used to determine scratching abrasion.68 In this test the specimen is abraded with sand of controlled size and composition. The abrasive is introduced between the test specimen and a rim or tire constructed of a material of specified hardness. The test specimen is further pressed against the rotating wheel with a specified force. The procedure can be varied by several ways. The difference in the mass of the sample before and after the test is determined and converted into a volume loss. Standards providing guidelines for evaluating the resistance of materials to dry abrasion include: •

ASTM G 65, ‘Standard Test Method for Measuring Abrasion Using the Dry Sand/Rubber Wheel Apparatus’

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FIGURE 8.39 Schematic Diagram of an Abrasion Test Apparatus.68 Reproduced with permission from ASTM.

Another test to determine the abrasion resistance of material is pin abrasion testing. Figure 8.40 provides four configurations used to perform this test: pin-on-disk, pin-on-table, pin-on belt, and pinon-drum.69 In all configurations the end of the pin abrades the material under test through the motion of the abrasive surface or the pin. The pin is further pressed against the abrasive surface with suitable loading (e.g., dead weight). The resistance to abrasion of the test specimen is evaluated from the mass loss of the abrasive specimen and the pin. Standards providing guidelines for performing pin abrasion test include: •

ASTM G 132, ‘Standard Test Method for Pin Abrasion Testing’

Gouging abrasion is a severe form of abrasive wear, in which a single contact between an abrading body and the wearing surface may be sufficient to cause a macroscopic gouge. Standards providing guidelines for performing gouging abrasion include: •

ASTM G 81, ‘Standard Test Method for Jaw Crusher Gouging Abrasion Test’

8.2.3c Slurry abrasion When solid particles are mixed in a liquid to enable their transportation in the form of a slurry, abrasion may be an issue. One of the common parameters used to understand the abrasivity of slurries is the Miller number. This is an index in which materials are ranked in terms of their abrasion with respect to a standard reference material; the higher the Miller number, the higher the abrasivity of material. Another index to represent abrasion is the SAR number. This is a generalized form of the Miller number, applicable to materials other than the reference material used to determine the Miller number. In general, slurries with a Miller or a SAR number of approximately 50 or lower cause minor abrasion, and slurries with a Miller or SAR number above 50 cause abrasion damage.

8.2 Laboratory measurement

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WEIGHT WEIGHT LEAD SCREW

LEAD SCREW HELICAL WEAR TRACK

SPIRAL WEAR TRACK

PIN-ON-DISK

PIN-ON-DRUM

WEIGHT WEIGHT

LEAD SCREW

WEAR TRACK

WEAR TRACK PIN-ON-TABLE

PIN-ON-BELT

FIGURE 8.40 Schematic Diagram of Typical Pin Abrasion Machines.69 Reproduced with permission from ASTM.

In this test, a specimen block is moved at the bottom of a trough containing the slurry, by the reciprocating motion of a rotating crank (Figure 8.41).70 A direct load is applied onto the specimen. At one end of each stroke, the specimen is lifted from the bottom to allow fresh slurry material to flow under it. The loss of mass of the specimen is measured to determine the abrasion. In the Miller number method, a standard specimen block of proprietary composition is used and the compositions of the slurry are varied to determine relative abrasivity of the slurries. The nominal composition of this chromium-iron wear block reference material is: carbon 2.5%, manganese 1.0%, silicone 0.6%, nickel 0.25%, chromium 28%, molybdenum 0.3%, vanadium 0.8%, iron – balance. Table 8.8 presents Miller numbers of some common slurry materials. Standards providing guidelines for evaluating slurry abrasivity include: •

ASTM G75, ‘Standard Test Method of Determination of Slurry Abrasivity (Miller number) and Slurry Abrasion Response of Materials (SAR Number)’

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FIGURE 8.41 Schematic Diagram of a Slurry Abrasion Apparatus.70 Reproduced with permission from ASTM.

Table 8.8 Miller Numbers of Some Slurries70 Material

Miller Numbers

Alundum 400 mesh Alundum 200 mesh Ash (fly) Bauxite Clay Coal Copper concentration Gypsum Iron ore Kaolin Lignite Limestone Limonite Magnetite Mud drilling Phosphate Potash Pyrite Sand/sand fill

241 1,058 83, 14 9, 22, 33, 45, 50, 76, 134 34, 36 6, 7, 9, 10, 12, 21, 28, 47, 57 19, 37, 58, 68, 111, 128 41 28, 37, 64, 79, 122, 157, 234 7.7, 30 14 22, 27, 29, 30, 33, 39, 43, 46 113 64, 67, 71, 134 10 68, 74, 84, 134 0, 10, 11 194 51, 59, 75, 85, 93, 116, 138, 149, 246 53, 59 25 1 24, 61, 76, 91, 159, 217, 480, 644

Shale Sewage (raw) Sulfur Tailings

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FIGURE 8.42 Schematic Diagram of Apparatus to Determine Wear Resistant of Materials.71 Reproduced with permission from ASTM.

8.2.3d Wear resistance Resistance to wear is determined in the laboratory in order to select appropriate materials for a given environment. Figure 8.42 presents a typical geometry used in a block-on-ring wear test.71 In this test a block is loaded against a test ring which rotates at a given speed for a given number of revolutions. The frictional force required to keep the block in place is continuously measured during the test. After the test, the volume of scar on the test block is calculated from the scar width and the volume of ring scar is calculated from the ring mass loss. From the volume of scar, mass loss of ring, and the friction force the coefficient of friction values are calculated. Standards providing guidelines for evaluating wear resistance include: •

ASTM G77, ‘Standard Test Method for Ranking Resistance of Materials to Sliding Wear Using Block-on-Ring Wear Test’

8.2.4 Microbiologically influenced corrosion (MIC) As discussed in section 5.14, two types of microbes, planktonic and sessile, cause MIC. The technique used should monitor both types. Microbiologically influenced corrosion monitoring may broadly be classified into: microbiological methods, microbiological influence methods, corrosion monitoring techniques, and simultaneous monitoring of microbiological and corrosion methods.72–75

8.2.4a Microbiological methods As the name implies, these techniques monitor microbial species. These techniques are further classified into two types: culture and direct detection methods.

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Table 8.9 Chemical Composition of Modified Postgate’s Medium Component

Chemical Composition

Nacl (g) MgCl2.6H2O (g) KH2PO4 (g) NH4Cl (g) Na2SO4 (g) CaCl2.2H2O (g) MgSO4.7H2O (g) FeSO4.7H2O (g) Sodium citrate (g) Sodium lactate (60% w/v solution) (mL) Yeast extract (g)

7.0 1.2 0.5 1.0 4.5 0.042 0.03 0.004 0.28 10.0 1.0

i. Culture methods Historically, information on microbial species was obtained by growing them in a culture medium in the laboratory. Culture methods involve taking samples from the field and detecting the presence of microbe by culturing them. From the amount of microbial species their influence on corrosion is estimated. Culture media to grow different microbes have been established. However, the culture medium cannot reflect the actual conditions in the field and several microbial species may not grow under laboratory conditions, leading to under-estimation of the influence of microbes. The most common microbes causing MIC are SRBs. Therefore most of the tests focus on measuring SRBs. However, for understanding the influence fully, all MIC causing microbes must be monitored. Some commonly used culture methods are described in the following paragraphs. Broth bottle test. A sample containing the microbes is incubated for 28 days in a growth medium. The typical composition of the growth medium used in the broth bottle method is commonly known as a modified Postgate medium (composition in Table 8.9). The procedure consists of drawing 1 mL of sample containing microbes into a syringe and injecting it into a broth bottle containing 9 mL of growth medium. Nutrients (typically lactate) and iron fillings are also added into the growth medium. The bottle is then shaken thoroughly, and a new syringe is used to draw out 1 mL of sample and inject it into a new medium bottle. This procedure is repeated to produce as many serial dilutions as required (typically between 5 and 10). If SRB are present in the sample, they reduce the sulfate in the medium to sulfide, which reacts with iron fillings to produce black ferrous sulfide. The number of blackened bottles over a 28 day period is taken as an indication of number of SRB. Figure 8.43 presents typical results obtained in this assay,72 and Table 8.10 presents a general guideline for determining the microbial count based on this number. Standards providing guidelines for performing culture methods include: • •

API RP 38, ‘Recommended Practice for Biological Analysis of Subsurface Injection Waters’ NACE TM0212, ‘Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion on Internal Surfaces of Pipelines’

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FIGURE 8.43 Typical Results Obtained in Broth Bottle Test Measuring SRB Growth (Progressive Blackening of Solution Indicates Presence of SRB).72 Reproduced with permission from Maney Publishing.

Table 8.10 Typical Bacterial Count Based on Broth Bottle Test Results Number of Bottles Turning Black

Bacteria per mL

0 1 2 3 4 5

0 1e10 10e100 100e1,000 1,000e10,000 10,000e100,000

Agar deep test. The agar deep test is a slight modification of the broth bottle test in which semisolid agar is used as the growth medium. Sodium sulfite is added to the medium to scavenge oxygen, i.e., to create anaerobic conditions. The undiluted microbial sample is injected into a vial of semisolid agar and is incubated for 5 to 28 days. As in the broth bottle test, the blackening of the medium is considered as an indication of the presence of bacteria. Relative numbers of bacteria are estimated from the rapidity with which the blackening occurs. The melt agar deep test is a slight modification of the agar deep test, in which the agar tubes are placed in boiling water to liquefy the medium. The medium is then cooled to 40 to 45 C and then the microbial samples are added. The tubes are then incubated for 7 to 21 days. As in agar deep test, the microbial count is determined from the rapidity with which blackening of the medium occurs.

ii. Direct detection methods Unlike culturing techniques, direct detection methods do not require microbial growth during the test, but they still require samples to be taken to the laboratory. These methods determine the presence of either microbial cells themselves or constituents of microbial cells. Direct detection methods simply indicate overall microbial population – they do not indicate presence of specific types of microbes. Further, they are unable to distinguish living cells from dead cells.

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Adenosine-5’-phosphosulfate (APS) assay. Adenosine 5 phosphosulfate (APS) reductase is an enzyme found in microbes; the presence of APS in a sample indicates the presence of microbes. In this test, the sample is first washed to remove interfering chemicals, such as hydrogen sulfide, and is then treated ultrasonically to break the microbial cells and to release the APS. An agent that develops color on reaction with APS is then added. The degree of coloration (typically blue) is considered as proportional to the number of microbes. Adenosine triphosphate (ATP) assay. Adenosine triphosphate is a chemical species present in microbes. The ATP assay involves adding a reagent that releases ATP from the microbe and then adding an enzyme that reacts with ATP photochemically to emit light. The emitted light is measured by a photometer, and the microbial population is estimated from its intensity. As in the APS assay, the sample containing microbes is first washed and filtered to remove interfering substances. Hydrogenase assay. The enzyme hydrogenase is found in all SRB, hence this assay involves processes to release hydrogenase from the SRB and detect the amount released.76 Epifluorescence cell surface antibody (ECSA) assay. In this assay the sample is spread in a special slide with a primary antibody reagent and incubated for 20 minutes. After the sample is washed to remove excess antibody, it is then incubated for another 20 minutes with a second antibody containing a fluorescent compound. The microbe is counted using epifluorescence microscopy. Figure 8.44 presents typical ECSA results.77 Fatty acid sequencing. The fatty acid sequence is specific to each microorganism, and therefore it can be used as a finger-print for the microorganism. In this method, the methyl esters of fatty acids from cell membranes and walls of microorganism are analyzed using gas chromatography to detect the presence of organisms. Deoxyribonucleic acid (DNA) and ribonucleic acid (RNA) sequencing. The deoxyribonucleic acid (DNA) and ribonucleic acid (RNA) sequence is specific to each microorganism. Genetic and subcellular characterization techniques can be used to determine the DNA and RNA sequence, which in turn enables determination of the presence of that particular microorganism. This kind of analysis is very sophisticated; some techniques are: polymerase chain reaction (PCR) technique which amplifies the DNA molecules, and fluorescent in situ hybridization (FISH) technique which targets the 16S rRNA genes. Radioactive method. In this method a radioactive substance is injected into the sample containing the microbes and the microbe is tracked by radioactivity. 35S is commonly used in this method.

iv. Microbiologically influenced methods See section 8.3.17.

v. Corrosion monitoring methods See section 8.3.17.

8.2.4b Simultaneous monitoring of corrosion and microbial activity method A four probe sensor for simultaneously monitoring SRB activity and corrosion rate has been developed78,79 (Figure 8.45). The four probes are the enzyme electrode (EE), working electrode (WE), counter electrode (CE), and reference electrode (RE). A combination of EE, CE, and RE is used to monitor SRB activity and a combination of WE, CE, and RE is used to monitor corrosion rate.

8.2 Laboratory measurement

485

(A)

(B)

FIGURE 8.44 Typical Result of ECSA Assay of Microbes.77 Reproduced with permission from Wiley.

The principle of monitoring SRB is similar to principle of measuring the glucose level in a blood sample. To monitor glucose the glucose oxidase enzyme is used, and for SRB monitoring the sulfide oxidase enzyme is used. Figure 8.46 describes the overall function of the EE in detecting SRB activity. When SRB are active they produce sulfide ions, and the sulfide oxidase (SO) enzyme oxidizes sulfide ions to sulfur: H2 S/S þ 2Hþ þ 2eþ

(Eqn. 8.39)

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CHAPTER 8 Monitoring – Internal Corrosion

W.E

C.E

R.E

E.E

FIGURE 8.45 Biocorrosion Probe for Simultaneous Online Monitoring of SRB and Corrosion Rate.78,79

FIGURE 8.46 Schematic Diagram Explaining the Function of an Enzyme Electrode to Monitor SRB online.

The electron produced in the process is relayed to the sensor electrode by a co-factor. The co-factor is a fast redox species, i.e., the rates of its reduction and oxidation are fast. Ferrocene is commonly used as co-factor. It reduces by accepting the electron produced in Eqn. 8.39 and quickly oxidizes at the electrode surface. The current generated on the electrode by this process is monitored and is proportional to SRB activity.80 To facilitate online monitoring, the SO enzyme and ferrocene are immobilized in a carbon paste and this fills the tip of a graphite electrode (Figure 8.47). An overpotential of 300 mV is applied to the EE. Under the laboratory conditions, the EE responds linearly to sulfide ions produced by SRB (Figure 8.48). The EE is specific to SRB activity, i.e., it will trigger a signal only when SRB produce sulfide ions in situ. Figure 8.49 illustrates the advantages of using the biocorrosion probe.81 However it should be

8.2 Laboratory measurement

487

FIGURE 8.47 Schematic Diagram of Enzyme Electrode. 180 -2

140

-2

S (mg/L)

2

S (mg/L) = 8.31 x I (µA/cm ) 2 R = 0.97

160 120 100 80 60 40 20 0 0

5

10

15

20

25

2

I (µA/cm )

FIGURE 8.48 Variation of Current Measured by Online Sulfide Probe and Sulfide ion Measurement by Offline Method.

CHAPTER 8 Monitoring – Internal Corrosion

1

100

Scenario 3: SRB Inactive; Corrosion rate High (Non-MIC)

Scenario 1: No SRB Activity; No Corrosion

Corrosion Rate, mpy

Scenario 2: SRB Active; Corrosion rate High (MIC)

0.5

60

40

Scenario 4:SRB Active; No Corrosion 20

0 0

10

80

Online Sulphide ion, mg/L

488

20

30

40

50

60

70

80

90

0 100

Duration, Days

FIGURE 8.49 Schematic Diagram of a Multielectrode System in which all Electrodes are Joined Together.

noted that the biocorrosion probe is only a laboratory methodology; its reliability in the field has not yet been proven.

8.2.5 Scaling Section 6.8 describes scale forming tendency. Scale inhibitors are added to control scale formation. This section discusses the typical laboratory evaluation of scale inhibitors. The ability of chemicals to control scale formation is normally evaluated in a laboratory flow loop (Figure 8.50).82 The flow loop consists of a small diameter (typically 40 mil (w1 mm)), long (typically 40 inch (w1 m)) coil which is fitted with filters (2 mm), pressure transducers, pumps and a back

FIGURE 8.50 Schematic Diagram of Flow Loop Used to Evaluate Scale Inhibitors.82 Reproduced with permission from NACE International.

8.2 Laboratory measurement

489

Table 8.11 Water Chemistry of Typical Solutions used in the Scale Inhibitor Performance Tests Ion Sodium Potassium Calcium Magnesium Barium Strontium Sulfate Bicarbonate Chloride

Concentration, mg/L 13,285 2,250 820 125 195 1,375 462 9,925

11,600 420 100 180 8 12 34 2,500 17,000

pressure regulator. This loop is operated for a fixed duration (typically 24 hours), at high temperature (typically up to 202 F (100 C)), and high pressure (typically up to 4,000 psi (28 MPa)) to simulate field operating conditions. During the experiment the pressure inside the coil is measured as a function of time, and any increase is taken to be an indication of scale formation. Additional parameters monitored include filter plugging (particulate formation due to breakdown of inhibitor) and appearance (for phase separation, color change, and other changes). A solution (typical compositions in Table 8.11) which has a high tendency to form scale is pumped into the flow loop.83,84 The inhibitor efficiency and the minimum inhibitor concentration are evaluated by adding the chemicals into the solution before the experiment. Successful scale inhibitors are then subjected to other compatibility tests under simulated field operating conditions. Usually the scale inhibitor performance tests are conducted after first subjecting the chemicals to simulation tests, so that real field inhibitor performances can be evaluated. Some tests are described in the following paragraphs. Thermal stability: The operating temperatures of offshore flowlines may vary between 4 C (39 F) and 100 C (212 F). Therefore the thermal stability of the scale inhibitors is evaluated by placing them in a suitable container (normally stainless steel) for a 28 day test at the operating temperature of the offshore system. After the test, the tendencies for phase separation, precipitation, and solid deposition are analyzed. A good scale inhibitor does not have any of these tendencies. Stability in the umbilical: The scale inhibitors reside in the umbilical for a longer duration before they reach the subsea field. For this reason the stability of the chemical under the umbilical operating conditions is evaluated. Normally the stability is evaluated in a laboratory flow loop. Rheology measurement: The viscosity of the chemicals should be less than 100 cP (0.1 Pa.s) under umbilical operation conditions, which are typically 40 F (w4 C) and 5,000 psi (34,474kPa). A high pressure rheometer is used evaluate the viscosity under umbilical operating conditions. Normally a baseline rheology measurement is taken, then the inhibitor is subjected to pressure and temperature conditions, and then the rheology measurements are repeated. Any change in the rheology is in indication of inhibitor degradation. Compatibility with other chemicals: Several injection lines are bundled inside the umbilical, which is typically between 0.64 and 1.27 cm (0.25 and 0.5 inch) in diameter. The fluids may mix if the

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CHAPTER 8 Monitoring – Internal Corrosion

injection lines inside the umbilical break. Therefore the compatibility of scale inhibitors with other fluids being injected, as well as production fluids, is evaluated. In general, to minimize umbilical blockage, all chemicals are blended together and formation of any products or solids is noted. Standards provide guidelines for evaluating cleanliness include: • •

NORSOK NAS 1638, ‘Subsea Standard Specification for Cleanliness, NAS 1638 Class 6’ ISO 4406, ‘Hydraulic Fluid Power – Fluids – Method for Coding the Level of Contamination by Solid Particles’

Compatibility with materials: The scale inhibitor comes in contact with several materials, including metals and non-metals (e.g., elastomers). The compatibility of scale inhibitors is evaluated by immersing materials into solution containing scale inhibitors. The corrosion rate is calculated from the mass change of the material before and after exposure. If the corrosion rate is more than 0.1 mm/y then the inhibitor is considered to be non-compatible with the material. Similarly non-metals are also exposed to the inhibitor solution and from the changes in the volume, hardness, and mass of the material the compatibility between the non-metal and the inhibitor is accessed. Other tests: The inhibitor is also evaluated for hydrate formation tendency, environmental friendliness, and performance as a corrosion inhibitor before being used in the field.

8.2.6 High temperature corrosion Exposure to higher temperature causes corrosion both in gaseous and liquid phases (see section 5.15). The susceptibility of materials to high temperatures is normally tested in a furnace at temperatures normally above 540 C (1004 F). The temperature may be held at a constant value or varied. High temperature corrosion depends on both duration and temperature. For this reason, specimens are tested for a minimum of three time periods. The furnace is heated using an electric-resistance-heated technique. The heat zone in a vertical furnace is not uniform. An open-tube furnace may have variable convection currents. The extent and location of the constant temperature zone within the furnace is measured and samples are exposed to different zones. Standards providing guidelines for evaluating materials at high temperatures include: •

ASTM G54, ‘Standard Practice for Simple Static Oxidation Testing’

The extent of corrosion after the specimens are exposed can be determined by several methods, but four are commonly used: mass gain, metallography, diffusion profile, and change in mechanical properties.

8.2.6a Mass gain The test specimen is exposed to a high temperature environment for a pre-determined duration and the mass gained by it is measured. This test requires a specimen of known exposed surface area and an accurate weighing machine (accuracy in 0.1 mg range).

8.2.6b Metallography After exposure to the high temperature environment the specimen is cut, mounted in a suitable mold, polished, and etched. It is then examined under a microscope to investigate the extent of corrosion and

8.2 Laboratory measurement

491

the microstructure. When the boundary layers are not well-defined, the results obtained by this method may not be accurate. This method is destructive, i.e., the sample cannot be reused.

8.2.6c Diffusion profile This method is used mostly to investigate the extent of carburization. This method analyses consecutive layers of an exposed sample using a wavelength dispersive X-ray technique. A sample for analysis may be removed from a structure using a suitable machining technique such as milling or turning. Standards providing guidelines to evaluate the susceptibility of material to carburization include: •

ASTM G79, ‘Standard Practice for Evaluation of Metals Exposed to Carburization Environments’

8.2.6d Mechanical properties Exposure to higher temperatures may influence mechanical properties such as strength, ductility, and hardness. Therefore hardness, tension, impact, creep, and bend tests are performed on materials exposed to high temperature and the results are compared with those obtained from materials not exposed to higher temperature.

8.2.7 Crevice corrosion In practice, crevice forms by two means: natural, i.e., created by biofouling, sediment, debris, and deposits, and man-made, i.e., created by improper manufacturing, fabrication, or assembly. The susceptibility to crevice corrosion is evaluated in the laboratory using ‘crevice formers’. These may be metal coupons, gasket washers, spacers, non-metallic strips, O-rings, and plateau assemblies. Figure 8.51 presents typical geometries of crevice formers.85 They can be metal or non-metal. Nonmetallic crevice formers produce tighter crevices which readily promote crevice corrosion initiation. Some commonly used non-metallic crevice formers include acrylic plastic, nylon, polyethylene, and

FIGURE 8.51 Typical Designs of Crevice Formers Used in Crevice Corrosion Tests.85

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CHAPTER 8 Monitoring – Internal Corrosion

PTFE-fluorocarbons. Metallic crevice formers are fabricated from the same material that is being tested for susceptibility to crevice corrosion. The crevice formers are attached to the material being tested with fasteners, which may be nut or bolt type. Metallic fasteners are preferred over non-metallic fasteners because of their strength. Metallic fasteners are typically fabricated from CRAs (Alloy 625 [UNS No. N06625] and Alloy C-276 [UNS No. N10276]) and are coated with insulating material or otherwise electrically insulated to avoid galvanic corrosion. The severity of the crevice corrosion test depends on the width or space between the metal surface and the crevice former, on the depth between the crevice mouth and the center or base of the crevice, and on the size and physical properties of crevice former. Standards providing guidelines for evaluating the susceptibility to crevice corrosion of materials include: •

ASTM G78, ‘Standard Guide for Crevice Corrosion Testing of Iron Base and Nickel Base Stainless Alloys in Seawater and Other Chloride-Containing Aqueous Environments’

8.2.8 Intergranular corrosion Susceptibility to intergranular corrosion is usually determined by comparing the corrosion rate of unannealed material to that of annealed material. However it should be recognized that even when the material is not susceptible to intergranular corrosion, the corrosion rate of properly annealed material varies from one alloy to another. Susceptibility to intergranular corrosion is determined by immersing test specimens in a given test solution. Two commonly used test solutions are: ferric sulfate-sulfuric acid and mixed acid-oxidizing salt. The susceptibility is determined from the mass loss of specimens from exposure in one of the solutions. In addition, the materials are metallographically examined to evaluate the degree of intergranular corrosion. Standards providing guidelines for evaluating the susceptibility to intergranular corrosion include: • • • •

ASTM G28, ‘Standard Test Methods of Detecting Susceptibility to Intergranular Corrosion in Wrought, Nickel-Rich, Chromium Bearing Alloys’ ASTM E3, ‘Methods of Preparation of Metallographic Specimens’ ASTM E 112, ‘Test Methods for Determining Average Grain Size’ ASTM A 262, ‘Practices for Detecting Susceptibility to Intergranular Attack in Austenitic Stainless Steels’

An electrochemical reactivation (EPR) test is used to study the effect of sensitization on intergranular corrosion and intergranular stress corrosion cracking behavior. The results of this test correlate reasonably well with those of ASTM G 28 and ASTM A 262 tests. During this test the corrosion potential is measured for 2 minutes, and then an anodic potential is applied to passivate the surface (typically þ200 mV vs. SCE for stainless steel) and then the potential is scanned in the negative direction (active direction). The current density is recorded until the potential reaches 50 mV positive to the initial corrosion potential. The current is then integrated to obtain the charge passed in coulombs (Q). Figure 8.52 presents a typical EPR test procedure and test result.86 Materials susceptible to intergranular corrosion (e.g., sensitized steels) have higher Q values than those which are not susceptible to intergranular corrosion.

8.3 Field monitoring

493

FIGURE 8.52 Schematic Diagram of Typical EPR Test Procedure and Test Result.86 Reproduced with permission from ASTM.

Standards providing guidelines for determining sensitization of stainless steel as well as to determine susceptibility of materials to intergranular corrosion include: •

ASTM G108, ‘Standard Test Method for Electrochemical Reactivation (EPR) for Detecting Sensitization of AISI Type 304 and 304L Stainless Steels’

8.3 Field monitoring In principle all techniques used to monitor the corrosion in the laboratory can be used in the field. However, field monitoring is relatively difficult and requires some modifications and simplifications. In addition, operating conditions in the field vary widely and may not be controlled from the perspective of corrosion. For this reason, field monitoring is not as accurate as laboratory monitoring. Several techniques are available and they can be categorized in different ways. Table 8.12 lists some common field monitoring techniques and categorizes them into various groups. Further, it should be recognized that a particular monitoring technique may fall into more than one category. In categorizing the techniques the following differences should be understood: monitoring vs. inspection, intrusive vs. non-intrusive, online vs. offline, leading indicators (real time) vs. lagging indicators, probe monitoring vs. structural monitoring, direct vs. indirect, general vs. localized corrosion, and destructive vs. non-destructive. Monitoring vs. Inspection: There is a fine line between monitoring and inspection techniques. A technique that can be placed in one location to determine corrosion over a period of time may be considered as ‘monitoring technique’, whereas a technique that can be handheld or placed on an instrument to determine corrosion in several locations of an infrastructure at one point of time is an ‘inspection technique’. One technique that may fall in both categories is ultrasonic (UT). If it is placed

Table 8.12 Categories of Monitoring and Inspection Techniques Nature of the Technique

Electrical probe LPR Noise EIS) Potentiodynamic polarization Galvanic couple (ZRA) Multielectrode Ultrasonic

Monitoring or Inspection

Intrusive or NonIntrusive

Online or Offline

Leading or Lagging Indicator

External or Inline Inspection

Probe or Structure Monitoring

Destructive

Monitoring

Intrusive

Offline

Lagging

NA

Probe

General corrosion, erosion-corrosion, and localized corrosion General corrosion and erosion-corrosion General General and pitting General General and localized

Non-destructive

Monitoring

Intrusive

Online

Lagging

NA

Probe

Non-destructive Non-destructive Non-destructive Destructive

Monitoring Monitoring Monitoring Monitoring

Intrusive Intrusive Intrusive Intrusive

Online Online Online Online

Leading Leading Leading Leading

NA NA NA NA

Probe Probe Probe Probe

Galvanic and MIC

Non-destructive

Monitoring

Intrusive

Online

Leading

NA

Probe

General, galvanic, and localized General, erosion, and localized General, erosion, and localized General, erosion, and localized General, erosion, and localized

Non-destructive

Monitoring

Intrusive

Online

Leading

NA

Probe

Non-destructive

Inspection

Online

Lagging

External)))

Structure

Non-destructive

Inspection

Online

Lagging

External)))

Structure

Non-destructive

Inspection

Online

Lagging

External

Structure

Non-destructive

Inspection

Nonintrusive)) Nonintrusive)) Nonintrusive Nonintrusive

Online

Lagging

External

Structure

Non-destructive

Inspection

Online

Lagging

External

Structure

Non-destructive

Monitoring

Online

Lagging

NA

Structure

Non-destructive

Monitoring

Nonintrusive Nonintrusive Nonintrusive

Online

Leading

NA

Structure

Non-destructive

Monitoring

Nonintrusive

Online

Leading

NA

Structure

Magnetic flux leakage (MFL) Electromagnetic e Eddy current Electromagnetic e Remote field technique (RFT) Radiography)))) General, erosion, and localized Electrical field General, erosion, and mapping (EFM) localized Hydrogen probe General and hydrogen monitoring effects (HIC, SSC, HE, and HB) Corrosion potential General and localized corrosion tendency

NA e Not applicable Not proven in the field May also be used as intrusive probe (see inline inspection) ))) May also be used as inline inspection tool )))) Another type of radiography, known as surface activation and gamma radiometry, technique is in the early stages of development. In this technique the internal surface of the infrastructure or a coupon is irradiated with a low level of radioactive material. The corrosion is monitored from measuring the radiation from the irradiated material and comparing that with a reference material )

))

CHAPTER 8 Monitoring – Internal Corrosion

Mass loss

Destructive or NonDestructive

494

Technique

Type of Corrosion Monitored

8.3 Field monitoring

495

in one location, it is categorized as a ‘monitoring technique’, and if it is handheld or placed on a pig it is categorized as an ‘inspection technique’. A monitoring technique may be a lead indicator or lagging indicator depending on its nature, but all inspection techniques are lagging indicators. Intrusive vs. Non-intrusive: Intrusive techniques must penetrate the wall of the infrastructure to reach its interior in order to measure the corrosion rate. Non-intrusive techniques do not reach the internal surface of the infrastructure; they measure corrosion rate with sensors or probes located on the outside wall of the infrastructure. In general, the sensitivity of intrusive methods is higher than that of non-intrusive methods. For example, the resolution of non-intrusive techniques typically is in 10 mils (0.25 mm), whereas typical resolution of an intrusive technique may be as low as 1 mil (0.025 mm). However, non-intrusive methods measure the thickness of actual infrastructure whereas intrusive methods measure the corrosion rate of probe or sensor placed inside it. Online vs. Offline: Online techniques measure the corrosion rate while the probe is still inside or on the infrastructure. Offline techniques require removal of the probe or sensor from the infrastructure to measure the corrosion rate. In a mass loss method, the actual mass is lost due to corrosion while the probe is inside the infrastructure, but the extent of loss can only be determined by removing the probe, cleaning, and weighing it. Hence the mass loss method has more offline than online characteristics. Leading (Real time) vs. Lagging: Leading monitoring techniques measure corrosion as it happens. Using these techniques, a corrosion mitigation program, e.g., addition of corrosion inhibitor, can be implemented before corrosion progresses to a significant extent. Lagging monitoring techniques can indicate occurrence of corrosion only after certain amount of mass or wall thickness has been lost over a period of time. Probe Monitoring vs. Structural Monitoring: Certain techniques monitor the corrosion of the probe element inserted into the environment. With such techniques it is assumed that the corrosion rate of the infrastructure in the given environment is similar to that of the probe in the same environment. For this reason the probe element should be constructed from the same material as the infrastructure, and it should be placed in locations susceptible to corrosion. Certain monitoring probes, on the other hand, are attached onto the infrastructure and measure directly the wall loss of the structure. Destructive vs. Non-Destructive: Monitoring techniques should not interfere with the process and should not alter the surface conditions of materials during measurement; i.e., they should be nondestructive. Certain monitoring techniques, however, measure the corrosion rate by changing the surface of material. They either require removal of probe or coupon from the system to determine the corrosion rate (e.g. mass loss), or attack the surface of the probe or coupon during the measurement (e.g. potentiodynamic polarization). Such techniques are destructive techniques. With destructive techniques the coupon or probe can only be used once, whereas with non-destructive techniques the corrosion rate can be measured repeatedly using the same probe or coupon. General vs. Localized Corrosion: Almost all corrosion failures occur due to localized as opposed to general corrosion. Certain monitoring techniques measure only general corrosion whereas others measure only localized corrosion. Direct vs. Indirect: Direct monitoring techniques measure either corrosion rate or mass loss, whereas indirect monitoring techniques measure parameters that may influence or may be influenced by corrosion rate or wall loss. Chapter 12 discusses indirect techniques, and the following section discusses direct monitoring techniques.

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8.3.1 Mass loss Mass loss method is a destructive, intrusive, offline, lagging, probe monitoring technique. Monitoring corrosion in the field by mass loss method is similar to that used to measure corrosion rate in the laboratory (as described in section 8.2.2b). The mass lost by the coupon may be due to both corrosion and erosion. The extent to which the coupon is inserted into the system depends on both the corrosion and erosion rates. As a general rule, the duration of exposure in hours is approximately 50 divided by expected corrosion rate in mm/y (or 2,000 divided by expected corrosion rate in mpy).87 Analysis of the coupon after exposure provides information regarding localized corrosion. Inserting and withdrawing the coupons in the field, especially the ones operating at higher temperature and/or higher pressure, requires sophisticated equipment. When using mass loss coupons it is important to place them properly inside the vessel at a location where the conditions are severe to give a meaningful representation. Figure 8.53, as an example, compares the corrosion rates of probes placed in an oil and gas production pipeline and that of pipeline itself.88 In this example, the corrosion rates of the probes are higher than those of the pipe, and the corrosion rates of the coupons depend on where they are placed; the bottom coupons exhibit the highest corrosion rates, as they are exposed to aqueous phase, the middle coupons exhibit moderate corrosion rates as they are exposed to both aqueous and oil phases, and the top coupons exhibit the lowest corrosion rates as they are partially exposed to gaseous phase. However the corrosion rates of all coupons are higher than that of the pipeline because the flow severity on coupons is higher than that on the pipe itself.

100 Top (9-12-3 o'clock) Bottom (3-6-9 o"clock) 6 o,clock Bottom

60

Middle

40 Top

Pit Depth, mils

80

20

0

Co

on up

(1

0"

) Co

on up

(6

") 3"

a Fl

e ng

3

i "P

pe

(L

h gt en

#1

3

)

ip "P

e

(L

h gt en

#2

)

3

to

pa Ex " 10

i ns

on

e ip "P 10

FIGURE 8.53 Comparison of Pit Depths in the Coupons (Exposed for Only 15 Days in the Pipe Section) and in the Pipe Section (Exposed for 8 Months).91,92 Note: The coupon was exposed into an experimental pipe section of 3, 6, and 10” in diameter.

8.3 Field monitoring

497

An industry survey indicated that mass loss coupons are the most widely used monitoring technique in the field.89 Standards providing procedures for monitoring corrosion rates by mass loss methods include: • • •

NACE Standard RP0775, ‘Preparation and Installation of Corrosion Coupons and Interpretation of Test Data in Oil Field Operations’ NACE Standard RP0497, ‘Field Corrosion Evaluation Using Metallic Test Specimens’ ASTM G 4, ‘Standard Guide for Conducting Corrosion Coupon Tests in Field Applications’

8.3.2 Electrical resistance (ER) probe An electrical resistance (ER) probe is a non-destructive, intrusive, online, and lagging, probe method to monitor general corrosion and erosion. This method works on the principle that the electrical resistance of a metallic wire or strip increases as its cross-sectional area decreases, as defined in Eqn. 8.40: R ¼ smetal

L A

(Eqn. 8.40)

where R is the resistance, smetal is the resistivity of metal (varies with temperature), L is the length, and A is cross-sectional surface area. When the wire or strip is exposed in a corrosive or erosive environment, the increase in electrical resistance can be correlated to corrosion, erosion, or both. Variations in temperature affect the electrical resistance, so in practice two probe elements are used (one exposed to the environment and another insulated from the environment) and the electrical resistance between them is measured. Some characteristics of ER probes are described in the following paragraphs. It is generally assumed that the cross-sectional area of the probe reduces uniformly due to corrosion or erosion or both. A rapid increase in the electrical resistance of the probe may sometimes be assumed to be due to pitting corrosion, but the ER probe is not suitable for monitoring localized corrosion. The electrical resistance of the probe is very low hence sensitive measuring techniques and cables are used to minimize the cable resistance and electrical noise. The cross-sectional area of the probe is optimized based on the expected corrosivity to find to an acceptable resolution. The electrical probe is susceptible to several types of noises including thermal (due to environment temperature fluctuation), stressinduced (due to physical stress on the probe element) and electrical (due to the nearby presence of noisy sources such as power cables, heavy duty motors, switch gear, and radio transmitters). The electrical probe may be shorted by conductive deposits (e.g., iron sulfide). Under such conditions the probe may show a mass gain. Proper design of the probe element may to some extent decrease this interference. The response depends on the metal used. Therefore the probe should represent the structural material to the extent possible. When the probe is first introduced into a system, its corrosion behavior may be different from the structural material until the probe surface is covered with typical materials covering the structural materials. This may take sometime from a few hours to several days; sometimes the probe may never reach the condition of the structure. An industry survey indicated that ER probes are as widely used as mass loss techniques in the field.89 Standards providing guidelines for using electrical probes include: •

ASTM G96, ‘Standard Guide for Online Monitoring of Corrosion in Plant Equipment (Electrical and Electrochemical Methods)’

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CHAPTER 8 Monitoring – Internal Corrosion

Table 8.13 Differences in Using Polarization Resistance Method in the Laboratory and in the Field89 Electrochemical Parameters

Laboratory

Field

Auxiliary electrode

Platinum or graphite e two electrodes Standard reference electrode

Normally made of the same material as that of working electrode Normally made of the same material as that of working electrode Normally assumed

Reference electrode Tafel constants Luggin capillary Corrosion potential

• •

Determined by Tafel extrapolation method Used Measured and reported against standard reference electrode

Not used Only stable values are noted

NACE 3D170, ‘Electrical and Electrochemical Methods for Determining Corrosion Rates’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.3 Polarization resistance Polarization resistance (LPR) is a non-destructive, intrusive, online, and leading probe method for monitoring general corrosion. Section 8.2.2b discusses the general principles and operation of the LPR technique. This method has the advantage of providing an instantaneous corrosion rate; hence it is the method most widely used in the field for determining general corrosion. Table 8.13 compares the main differences in measuring corrosion rate by using the polarization resistance method in the laboratory and in the field.89 Equipment is available for introducing and retrieving polarization resistance probes under pressure and temperature. Several configurations of polarization resistance probes are used. Figures 8.54 and 8.55 present some of the commonly used ones.90,91 It is necessary to place the probes in the most corrosive location in the system. For instance, referring to Figure 8.55, measurements using probes 5 and 6 may not be relevant, as they may be in the oil or gas phase. Placing the probes in those locations is relatively easy from the operational standpoint, but the results obtained may be irrelevant or erroneous. Measuring the polarization resistance using probes 1 and 2 is most relevant, because these probes are in the aqueous phase (high-conductivity). Data from probes 3 and 4 can be used when it is ensured that they are in aqueous phase. As discussed in section 8.2.2b, the total resistance (R) is measured by the polarization resistance method, which is the sum of both solution resistance (Rs) and polarization resistance (RP). For a conducting solution, the value of Rs is low, so that the measured resistance is assumed to be equal to Rp. In order for this assumption to be valid, the measuring probe should be immersed in a conducting solution. Figure 8.24 provides general guidelines on the ranges of solution resistance in which different configurations of polarization resistance probes can be used. Further electrical connections from the probes to the measuring instrument must be shielded sometimes installation of such a system may be costly and cumbersome.

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FIGURE 8.54 Schematic Diagram of a Typical Three Electrode Polarization Resistance Probe.90 (A) For determining corrosion rate in the field and installation of such probe in pipe fitting (B), in weld line (C), and in pipe tee (D). Reproduced with permission from ASM International.

An industry survey indicated that LPR is the most widely used electrochemical technique in the field.89 Standards providing guidelines for monitoring corrosion rates using the LPR technique include: • • •

ASTM G96, ‘Standard Guide for Online Monitoring of Corrosion in Plant Equipment (Electrical and Electrochemical Methods)’ NACE 3D170, ‘Electrical and Electrochemical Methods for Determining Corrosion Rates’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.4 Electrochemical noise EN is a non-destructive, intrusive, online, leading, probe method to monitor general and localized corrosion. Section 8.2.2b discusses the general background, equipment needed and analysis procedure of the electrochemical noise technique. The field equipment used to monitor corrosion rate using the noise technique is similar to that used in the LPR technique. Additional limitations and precautions in using electrochemical noise are discussed in the following paragraphs. As is the case with the polarization resistance method, the noise probe should be placed in a conductive solution, otherwise the results are meaningless. As with any method that monitors the corrosion rate of a probe, when first introduced into a system, the corrosion rate of the noise probe may be different from that of the structure. Noise can originate from thermal, electrical, and mechanical sources, but corrosion is related to noise originating from electrochemical processes. Therefore care

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FIGURE 8.55 Photo of a Holder to Mount a Six Coupon Assembly in an Operating Field Pipeline.91

should be exercised to minimize noise from other sources. The probe configuration should be free from crevices or leaks at the interface between the probe element and the sealant, otherwise unusually high corrosion rates may be recorded. The three electrodes should be electrically isolated from one another to establish the electrochemical system. The presence of conducting substances (e.g., iron sulfide in sour media) may short the electrodes, causing erroneous measurements. One study conducted in oil and gas production pipelines indicated that the reliability of electrochemical noise technique is as good as the mass loss method for general corrosion, and that it produces reasonably reliable information about localized corrosion.92 An industry survey indicated that noise technique is becoming popular as a measuring technique in the field.89

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8.3.5 Electrochemical impedance spectroscopy (EIS) EIS is a non-destructive, intrusive, online, leading, probe method for monitoring general corrosion. It has been used extensively as a laboratory-based research tool for studying corrosion and corrosion control strategies, especially corrosion inhibitors and polymeric coatings (see section 10.2.2b), but it has not been successful in field monitoring. One study on the applicability of EIS for corrosion inhibitor evaluation in the field found the reliability of this technique to be poor.9–14 Some limitations of this technique, which prevent its extensive use in the field, include: longer duration (typically in minutes or in hours) to collect proper data – this requirement makes the use of technique difficult in systems with wide temperature and operational changes; ambiguity in the selection of proper equivalent circuit to represent the corrosion system; complexity in the analysis of results; and requirement of higher level of technical understanding to use this technique. An industry survey indicated that EIS is not at all used in the field.89

8.3.6 Potentiodynamic polarization Potentiodynamic polarization is a destructive, intrusive, online, leading, probe method to monitor general and localized corrosion. Section 8.2.2b discusses this technique in detail. This technique is actually not a monitoring technique, though it is sometimes used in the field to determine the pitting tendency of a material. Using the same set-up used for LPR measurement, the potential is scanned first in the anodic direction and then the direction of scan is reversed. The pitting tendency is obtained from the hysteresis plot (Figure 8.56). After the run the probe is retrieved to observe the formation of any pits. An industry survey indicated that potentiodynamic polarization is used in the field to a smaller extent.89

8.3.7 Galvanic couples The galvanic couple technique (commonly known as the zero resistance ammeter (ZRA) method) is a nondestructive, intrusive, online, leading, probe method to monitor galvanic corrosion and MIC. Section 5.4 discusses the basic principles of galvanic corrosion. This technique is simple and can be used directly in systems operating at high pressure (as high as 40 MPa (6,000 psi)). The two electrodes used in the technique may have one of the following three configurations: dissimilar metals or alloys (in which one is preferably more cathodic and another is preferably more anodic in the galvanic series); same metal or alloy with a different metallurgical or electrochemical state; and same metal or alloy of identical size and shape. Standards providing guidelines for using galvanic couples include: •

NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

In all configurations the electrodes are connected externally through a ZRA which measures the current between the couples. Changes occurring in the system in which the galvanic couple is placed increase the potential difference between the couples, thereby increasing the current flowing between them. Such changes include variations in metallurgy (e.g., heat treatments such as welding, stress relieving, or annealing); different electrochemical state (e.g., only one electrode is in the passive state and the other is in the active state); bacterial growth or biofilm formation on one of the electrodes; differential aeration or presence of different concentrations of dissolved gases and chemicals (e.g., ammonia and cyanide) at the electrodes; and formation of films (including corrosion inhibitor, corrosion product, and

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1.2

POTENTIAL (VOLTS VS S.C.E.)

1.0

0.8 Metal 2 0.6

0.4

0.2

0

–0.2

–0.4

Metal 1 100

102 101 CURRENT DENSITY (µA/cm2)

103

FIGURE 8.56 A Typical Potentiodynamic Polarization Curve to Determine Pitting Corrosion Tendency.93

passive) on one of the electrodes. This method is quantitative when only one parameter affects the galvanic current, but in most field operating conditions more than one parameter affects the galvanic current. For these reasons this technique is only used as a qualitative indicator. Further, the current between the galvanic probes does not necessarily indicate actual galvanic corrosion rates of the structure because of the smaller size and geometry of the probe compared to that of the structure. This technique does not distinguish anodic or cathodic reaction or the activity of one particular electrode of the pair, but simply measures the current between them. Solution resistance may affect the reading in poorly conducting solutions. Standards providing guidelines for using galvanic couples include: • •

NACE report 1C187, ‘Use of Galvanic Probe Corrosion Monitors in Oil and Gas Drilling and Production Operations’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.8 Multielectrode technique The multielectrode technique is a non-destructive, intrusive, online, leading, probe method for monitoring general corrosion, galvanic corrosion, and localized corrosion. Microelectrodes are in a way a variant of galvanic couple electrodes, except that in this techniques several electrodes (as many as 100) are used.

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FIGURE 8.57 Schematic Diagram of Multielectrode System in which All Electrodes are Joined Together.94 Reproduced with permission from NACE International.

The multielectrode technique may also be known as the microelectrode technique, because the electrodes are of the order of micrometers in diameter (typically between 0.1 mm and 2 mm) with micrometers of space between them (typically between 1 mm and 1 mm) space in between them. There are broadly three types of multielectrode configuration: • • •

All electrodes are electrically connected into a common joint (Figure 8.57); i.e., the multielectrodes are treated as one electrode and the corrosion rate of one electrode is monitored.94 Each electrode is considered as individual electrode and the corrosion rate of each is monitored independently (Figure 8.58). This is the most common method.95 A combination of both the above is used, i.e., the corrosion rate of each electrode or of all combined electrodes is monitored (Figure 8.59).96

Voltmeters

Resistors Concrete external surface

Concrete Cathode

Anodes

FIGURE 8.58 Schematic Diagram of Multielectrode System in which Each Electrode is Individual.95 (Note multiple ZRA box with individual connection to each electrode). Reproduced with permission from Woodhead.

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Potentiostat

A V

Manual switches

Oil-coated specimens Test cell Solution

Counter electrode

Reference electrode

FIGURE 8.59 Schematic Diagram of Multielectrode System in which All Electrodes can be Joined or an Individual Electrode Can Be Separated.96 Reproduced with permission from Woodhead.

In all configurations, a counter electrode and a reference electrode are used. The counter electrode may be constructed from ZRAs (e.g., stainless steel or platinum) or be one of the multielectrodes. Similarly the reference electrode may be a standard reference electrode or one of the multielectrodes. Figure 8.6097 presents a typical response of a microelectrode consisting of 16 identical electrodes. In an ideal situation, the current response of all 16 microelectrodes should be the same, but in reality this is never the case. The probability of the initiation and propagation of localized corrosion is determined from the response of each electrode, as follows: the anodic currents of all microelectrodes are sorted to obtain the maximum current, or the anodic currents are averaged to obtain the average current. It is assumed that if the maximum current or average current is higher, the tendency for the material to corrode is also higher. In this analysis, the cathodic current is totally ignored, i.e., if an electrode exhibits a cathodic current, its value is not considered in the analysis. Several methods to convert the maximum or average current into a corrosion rate and to analyze the data are available. The microelectrodes simulate the mixed anodes and cathodes that exist in real metals and alloys. They can be used in solutions of higher resistance, in which conventional electrodes cannot be easily used. This is because the microelectrodes are closely packed, so the influence of solution resistance is decreased. However the close proximity of the electrodes makes them vulnerable to short circuiting by corrosion products, e.g., the formation of FeS in a sour medium. Preparation of electrodes is critical to

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2.0E-10 lmax–Maximum anodic current (lmax = l4)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 Max Avg

1.5E-10

Anodic current (A)

1.0E-10

5.0E-11

0.0E+0

–5.0E-11

lavg–Average anodic current –1.0E-10 4:12 4:40 3:43 5:09

5:38

6:07

6:36

7:04

Time (hour:min)

FIGURE 8.60 Typical Current Response of a 16-Probe Microelectrode.97 Reproduced with permission from NACE International.

avoid crevice corrosion; improper preparation of micro electrodes will result in the formation of crevices which show higher currents. The theory for converting the measured current into the corrosion rate is not fully understood. No standard is currently available to provide guidelines for using this technique.

8.3.9 Ultrasonic (UT) The ultrasonic technique is a non-destructive, non-intrusive, online, lagging, structural inspection technique to determine general wall loss including that due to general corrosion, erosion, and localized corrosion. The ultrasonic technique (UT) measures the thickness of solid materials. During UT inspection, a piezoelectric crystal (commonly known as a transducer) is placed on the object to send a timewave through it. To transmit the time-wave between the transducer and the object a liquid couplant is placed between them. The transducer oscillates and sends the wave across the material. The velocity of wave through the material depends on the material itself and its wall thickness. The thickness is determined from the time it takes for the wave to travel across the material. In practice, the transducer is calibrated using a material of known thickness. Although several variations and advances have been made to transmit and process the data from the transducer to the display

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system, the basic principle of transduction between transducer and the material remains the same, i.e., UT measures the thickness at the point at which the transducer is placed. In some designs, the UT transducer is permanently placed in one location of the structure to monitor the loss of wall as a function of time. A 12 year study indicated that the handheld UT technique is the best non-intrusive technique. The study further indicated that development of a liquid couplant that will not dry over time, and that will continue to attach the probe onto the substrate would advance the fixed-UT technique.98 In principle, UT can detect wall losses of 0.025 mm (1 mil) when the transducer is accurately placed and the process is accurately controlled. The measurement accuracy depends on several factors, including the variations of sound velocity in different metals, temperature variations in the substrate, and discrimination of the acoustic reflections. For these reasons, in real field conditions, UT can detect wall losses only in excess of 0.1 mm (4 mil). The best resolution of the UT-handheld technique observed in one study was 0.25 mm (10 mil), whereas the resolution of intrusive techniques may be as good as 0.025 mm (1 mil). Standards providing guidelines for using the UT technique include: • • • •

ASME(4) Boiler & Pressure Vessel Code, Section V, ‘Non-destructive Examination’ New York, NY: ASME ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, ‘Rules for Construction of Pressure Vessels’ New York, NY: ASME ASNT Recommended Practice No. SNT-TC-1A, ‘Personnel Qualification and Certification in Non-destructive Testing’ Columbus, OH: ASNT, and NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.10 Magnetic flux leakage (MFL) The magnetic flux leakage (MFL) technique is a non-destructive, non-intrusive, online, lagging, structure inspection technique to determine general wall loss, including that due to general corrosion, erosion, and localized corrosion. This technique measures the flux flowing between the opposite poles of two magnets. The magnets send flux into the structure to be inspected. Sensors – placed near the structure or moved along the structure – monitor the leakage of flux from the structure. If there are anomalies (wall loss) in the structure, the flux leaks through them and is detected by the sensors. MFL is useful for locating defects such as pits, but is not accurate in sizing them. The MFL inspection tool is relatively fast and is portable, but is sophisticated and the analysis is complicated. Most inspections can be performed while the structure is in service, but some structures (e.g., tank floors) should be out of service during inspection. The sensitivity of the MFL tool depends on the contact of the sensors with the surface being inspected. Therefore the cleanliness of surface is important; otherwise random noise is created. The sensitivity also depends on tool speed and temperature; variation in any of them produces noisy signals. The sensitivity is typically reported as a percent of the wall thickness. As such, it is a good inspection tool (see section 8.4) but not the best technique for measuring corrosion rates from two successive inspections.

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• • • •

507

Standards providing guidelines for using MFL tools include: ASME Boiler & Pressure Vessel Code, Section V, ‘Non-destructive Examination’ New York, NY: ASME ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, ‘Rules for Construction of Pressure Vessels’ New York, NY: ASME ASNT Recommended Practice No. SNT-TC-1A, ‘Personnel Qualification and Certification in Non-destructive Testing’ Columbus, OH: ASNT NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.11 Electromagnetic – Eddy current The eddy current technique is a non-destructive, non-intrusive, online, lagging, structural inspection technique to determine general wall loss including that due to general corrosion, erosion, and localized corrosion. This technique can be used only to inspect non-magnetic materials. An eddy current is an electrical current circulating in a conductive material which is induced by an alternating magnetic field. An eddy current inspection system consists of a signal generator and a sensor. The signal generator generates an alternating current which induces eddy currents in the structure to be inspected. The eddy currents in turn induce an alternating current in the sensor coil. The change of the two current fields is used to detect corrosion pits, other defects, and wall thinning. Before inspection, the frequency and amplitude of the alternating current, as well as the distance between generator, structure, and the sensor are optimized. The distance between generator, structure, and sensor remains constant throughout the inspection, as the probe moves along the infrastructure. The equipment is also calibrated with materials with known cracks, pits, and wall thinning before inspection. The accuracy of this technique depends on the size and orientation of the defect. Under ideal conditions, an accuracy of  5% of wall thickness may be obtained. The eddy current tool is relatively fast, the instrument is potable, and it is useful for inspecting parts of infrastructure where access is limited. The sensitivity of the technique depends on surface finish, magnetic permeability, and temperature. It is not sensitive to magnetic material and its accuracy decreases with the distance between the probe and the structure being inspected. The eddy current technique is used in the industry using computer controlled robotic systems containing sophisticated, digitized, multichannel equipment. The structure should not be in service during eddy current inspection. Although the data can be processed while the survey is in progress, this is not done in practice. The inspection can be repeated on the same area to determine metal loss over time and to calculate the corrosion rate. Standards providing guidelines for carrying out eddy current inspections include: • •

ASME Boiler & Pressure Vessel Code, Section V, ‘Non-Destructive Examination’ Article 8, ‘Eddy Current Examination of Tubular Products’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.12 Electromagnetic – remote field technique (RFT) The electromagnetic remote field technique (RFT) is a non-destructive, non-intrusive, online, lagging, structure inspection technique to determine general wall loss including that due to general corrosion,

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erosion, and localized corrosion. This technique is predominantly used to inspect magnetic materials, for which the eddy current technique is ineffective. This system is extensively used to inspect oilfield tubulars as well as small bore tubes, heat exchangers, and boiler tubes. It consists of an exciter, amplifiers, and receivers. The exciter imposes a magnetic field on the structure and the detector measures the changes in the phase and amplitude of that magnetic field. The wall thickness of the infrastructure influences the phase between the exciter and the detector, whereas any wall defects influence the amplitude of the magnetic field. The data obtained is compared with that of calibrated standard materials of similar dimensions. Although the technique is primarily used as an inspection technique, it can be used to monitor the corrosion growth as a function of time. This technique does not require much cleaning of the structure to be inspected. In general, it can determine pit depth with about  10% accuracy. The equipment is portable, and used to inspect structures with limited access and smaller pieces of equipment. This technique however cannot differentiate internal and external defects, is affected by changes in temperature and magnetic permeability, and cannot detect closely located cracks. Standards providing guidelines for using RFT include: • •

ASME Boiler & Pressure Vessel Code, ASME Section V ‘Non-destructive Examination.’ Article 8, ‘Eddy Current Examination of Tubular Products’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.13 Radiography Radiography is a non-destructive, non-intrusive, online, lagging, structure inspection technique to determine general wall loss including that due to general corrosion, erosion, and localized corrosion. Pit depth is calculated from the difference in optical density of the radiography film between an image of a non-corroded area and that of a corroded area. This technique is not accurate enough to determine the thickness of the structure, so a nominal thickness is assumed to calculate the pit depth. The corrosion rate as a function of time can be determined with this technique by repeating the survey in the same area. The greatest advantage of this technique is that physical access to the structure is not necessary, so it is used extensively to monitor corrosion rates of insulated, clad, bundled, or otherwise inaccessible structures. However, the distance between the structure and source of radiation and the strength of radiation source determine the accuracy of detection. Normally a distance of less than one meter between the infrastructure and radiation source is preferred. The accuracy of detection also depends on density of the product in the structure, wall thickness, and the type of source used to produce the radiation beam. In general, this technique can determine pit depth with about  10% accuracy; however the accuracy decreases in the presence of scale or other debris in the corroded area or within the pit. Standards providing guidelines for using radiography include: •

ASME Boiler & Pressure Vessel Code, Section V, ‘Non-Destructive Examination’ New York, NY: ASME

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• • •

509

ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, ‘Rules for Construction of Pressure Vessels’ New York, NY: ASME ASNT Recommended Practice No. SNT-TC-1A, ‘Personnel Qualification and Certification in Non-destructive Testing.’ Columbus, OH: ASNT. Benefits NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.14 Electrical field mapping (EFM) Electrical field mapping is a non-destructive, non-intrusive, online, lagging, structure monitoring technique to determine general wall loss including that due to general corrosion, erosion, and localized corrosion. The basic principle of EFM is same as that of the electrical resistance probe technique (see section 8.3.3), but in this technique the measurement is made on the external surface of the structure rather than by inserting a probe into it. The electrical connections are made by welding, gluing, or springloading contact pins onto the structure. In some parts of the world, regulatory requirements prevent the direct welding of contact pins onto a structure handling sour gas or sour oil due to the concern of increased hardness which may result in hydrogen effects (see section 5.18). Under this situation the contact pins are welded onto another pipe section which is clamped onto the pipe being monitored; however in this configuration the accuracy of measurement decreases. Several contacts pins are attached at various distances (typically between a few centimeters to a few meters). The number of contact pins and the distance between them depends on the type of corrosion. To monitor general corrosion, the contact pins are placed far away from one another, and to monitor localized corrosion they are placed more closely. However no guideline is available on the relationship between the pin distance and type of corrosion. During the measurement, a current is applied directly onto the surface through these contact pins and the potential variations are measured. The potential response is then compared with those of a similar structure/sample of the same thickness with no defect and the corrosion rate is established from the comparison. The sensitivity of the measurement depends on many factors, but no information is publicly available on the accuracy and sensitivity. The measurements can be performed repeatedly. This technique does not distinguish external or internal defects. It is assumed that the signal arises from the internal corrosion as the external surface is covered by the sensor. Standards providing guidelines for using EFM include: •

NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.15 Hydrogen probe The hydrogen probe is a non-destructive, non-intrusive, online, leading, structure monitoring technique to determine general corrosion and hydrogen effects. As discussed in section 5.18, when the cathodic reaction is hydrogen reduction, atomic hydrogen diffuses through metal. The hydrogen probe monitors this atomic hydrogen. It is assumed that the volume of hydrogen permeating through the metal is proportional to the corrosion rate occurring inside

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the structure. The permeation of hydrogen depends on the cathodic reaction rate, flow, temperature, and contaminants (especially location of microalloying elements) in the metal. There are three principle types of hydrogen probes. Hydrogen pressure (or vacuum) probe: In this design, the flux of hydrogen atoms permeating through the structure is determined by collecting and measuring the volume of hydrogen gas. To facilitate the collection of hydrogen, a metal patch with a cavity or space between it and the structure is attached onto the external surface. The increase in pressure within the cavity is measured using a pressure gauge. In one design, a vacuum is created in the space between the hydrogen probe and the structure before measurement starts, and the increase in pressure is monitored until it reaches atmospheric pressure. The sensor requires frequent depressurization, i.e., creation of vacuum. In another design, positive pressure above atmospheric pressure is measured. In either design, the rate of increase in pressure is taken as the measure of the corrosion rate. Electrochemical liquid hydrogen probe: In this design the hydrogen permeation rate is measured by an electrochemical technique. The electrochemical probe is attached to the external wall of the structure. The probe consists of two electrodes immersed in a solution; normally nickel is used as the working electrode and palladium foil is used as counter electrode. The palladium foil is often used to isolate the electrolyte of the probe from contact with the wall of the structure. The potential of the working electrode is adjusted so that hydrogen atoms entering into the electrochemical cell are oxidized. The oxidation current is measured and is proportional to the hydrogen flux through the structure. Electrochemical solid hydrogen probe: This device is similar to the electrochemical liquid hydrogen probe, except that the electrolyte in this design is solid or gelled. If the hydrogen probe is welded onto the structure, the structure should be stress relieved by heat treatment. If the probe is sealed by glue, any leakage of air from the atmosphere should be prevented. The response time of the probes is measured in minutes for pressure probes and in seconds for electrochemical probes. The probes are sensitive to small amounts of hydrogen. This probe can provide early warning that excess hydrogen is produced which may result in hydrogen blistering, HIC, or SSC. However, no correlation exists between the hydrogen diffusion rates and corrosion rate, cracking, or blistering. This technique is only applicable in conditions where hydrogen reduction is the cathodic reaction, and is not useful in alkaline or neutral solutions where oxygen reduction is the most likely reduction reaction. Further, the hydrogen measured by the probes does not necessarily originate from corrosion in the locations where the probes are placed. Standards providing guidelines for using hydrogen probe include: • •

NACE Publication 1C184, ‘Monitoring Internal Corrosion in Oil and Gas Production Operations with Hydrogen Probes’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.16 Corrosion potential (Ecorr) Corrosion potential measurement is a non-destructive, intrusive, online, leading, structural monitoring technique to determine the tendency of metals to corrode (see section 5.2). The corrosion potential of the internal surface of an infrastructure is measured by placing a reference electrode close to it. Whereas corrosion potential measurement is routinely and easily performed in the laboratory, measurement in an operating field is frequently complicated by several

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factors, including the fouling of electrodes, high pressure, gas bubbles, oil layers, surface layers, temperature variations, and process variations. The corrosion potential can be measured in the field by isolating the reference electrode (i.e., external reference electrode) from the process fluids, while at the same time maintaining electrical contact. Some elements that can be used to provide electrical contact between the reference electrode and working electrode are semi-permeable hydrophilic membranes, e.g., NafionÔ , ceramic, zirconia, and hard wood. These materials are impregnated with conducting salts, e.g., potassium chloride, to ensure electrical conductivity. Figure 8.61 presents a typical high

FIGURE 8.61 Typical High Temperature, High Pressure Reference Electrode.99 Reproduced with permission from Caproco.

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FIGURE 8.62 High-Temperature, High-Pressure Reference Electrode Tip.99,100 (Solid junction made from dowel that was highly impregnated with potassium chloride).

temperature, high pressure reference electrode set-up for measuring corrosion potential in the field,99 and Figure 8.62 shows the tip of the reference electrode.100 By measuring the corrosion potential and comparing it with the potential in a polarization curve, the susceptibility of the material to uniform corrosion, passivation, pitting corrosion, and stress corrosion cracking can be predicted. Corrosion potential measurement is also useful to ensure that adequate protection (e.g., cathodic and anodic protection) is applied in the field. The measurement is instantaneous and is useful for assessing whether a corrosion system is changing with time, and how fast it is changing. The merit of such measurement depends on the stability of reference electrode under the operating conditions of the plant or infrastructure, the ability to overcome interfering elements, and proper electrical contact between the reference electrode and the structure. Further it should be noted that this technique does not provide a corrosion rate, but only a tendency for corrosion to occur. Standards providing guidelines for measuring corrosion potential in the field include: • •

ASTM C 876, ‘Standard Test Method for Half-Cell Potentials of Uncoated Reinforcing Steel in Concrete’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.3.17 MIC monitoring techniques In theory, all techniques described in section 8.2.4 can be used in the field, but MIC techniques and corrosion monitoring are predominantly used in practice. An industry survey indicated that broth bottle test (see section 8.2.4a) is the most widely used MIC test in the field.89

8.3.17a Microbiological influence The presence of sessile microorganisms or biofilms on a metallic surface may change some properties of the system. By following these changes, the onset of MIC may be deduced, so these techniques may

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be used as online monitors. However they are not specific to MIC; many other parameters interfere with these measurements. Some techniques are described in the following paragraphs.

i. Deposition accumulation monitor The deposition of biofilms increases any pressure drop in a system. Thus, by monitoring pressure drop, the accumulation of biofilm can be determined. However pressure drop occurs due to several other reasons, so this technique is not specific to biofilm formation or to MIC.

ii. Heat transfer resistance The deposition of biofilms increases heat transfer resistance across heat exchangers. This method is more sensitive to biofilm formation than pressure drop, but is similarly not specific to the accumulation of biofilms. In addition, this technique can only be used in systems in which heat exchange occurs.

8.3.17b Corrosion monitoring All monitoring techniques discussed in section 8.3 potentially provide information on MIC as well. Some specific issues with respect to monitoring MIC using these techniques are discussed in the following paragraphs.

i. Mass loss coupons Mass loss coupons provide a method for evaluating the morphology of corrosion and pit distribution. Some groups use morphology to differentiate MIC from non-MIC; however this practice is not correct. Any morphology produced by microbial activity can be produced by non-microbial activity. Therefore morphology should only be considered as an indication of corrosion – whether it is due to MIC or nonMIC. However, mass loss coupons allow the evaluation of sessile bacteria and any biofilm adhered onto them. This information can be used to establish a correlation between microbial activity and corrosion morphology. Without such correlation no attempt should be made to interpret MIC based only on morphology.101 Standards providing guidelines for monitoring MIC using metal loss coupons include: • •

NACE TM0212, ‘Standard Test Method for Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion of Internal Surfaces of Pipelines’ NACE TM0194, ‘Field Monitoring of Bacterial Growth in Oil and Gas Systems’

ii. Electrochemical techniques All electrochemical techniques discussed in sections 8.3.2 through 8.3.8 provide information on corrosion rates caused by all factors including microbial activity. Corrosion rates specific to microbial activity cannot be determined using electrochemical techniques. A specific electrochemical technique that is used to monitor the activity of biofilm is described in the following paragraph. Two sets of identical electrodes constructed from corrosion resistant alloys (typically stainless steel or titanium) are exposed to the environment. The potential difference between them is monitored continuously. At pre-determined intervals (typically once a day) one electrode is polarized (by applying current) relative to the other to establish a specific potential difference between them. The current required to polarize the electrode is monitored. From the results, a baseline potential difference between the electrodes and the current needed to polarize the electrodes are established. Deviation from these baseline results is monitored, and is assumed to be due to the formation of biofilm on the electrodes. The change in potential or current measured in this technique can however occur due to

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several reasons, including formation of surface films, solid deposition, and biofilm deposition, so this technique should be considered as a very qualitative indication of potential microbial activity.

8.3.18 Residual corrosion inhibitors Residual corrosion inhibitors can be monitored at specific locations to indirectly determine the corrosion rate. Reliable techniques are available to collect samples and to perform the analysis in the laboratory. This measurement can be used to ensure that the corrosion inhibitor reaches various parts of the infrastructure, and to optimize corrosion inhibitor ports, injection frequencies, and corrosion inhibitor concentrations. Standards providing guidelines for analyzing residual corrosion inhibitors include: •

NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.4 Field inspection Monitoring techniques (see section 8.3) are most associated with determining the corrosion rate and the effectiveness of corrosion control strategies. On the otherhand, the inspection techniques are more focussed on determining the size of the defects (including corrosion defects), on establishing maximum allowable operating pressure (MAOP), as well as on maintaining system integrity. An infrastructure is normally inspected during construction to ensure that it is free from any manufacturing and construction damage and is safe to commission. During operation it is inspected again to ensure that it continues to be safe. Inspection is a lagging indicator which can be performed from the outside, i.e., external inspection, or by introducing the probe inside, i.e., inline inspection. Inline inspection is normally carried out on transmission pipelines, and external inspection is normally carried out on other sectors of the oil and gas industry (see Chapter 2 for different sectors). General aspects of field inspection techniques are discussed in this section.

8.4.1 Physical inspection Physical inspection of corrosion damage is the most desirable method to obtain first hand information on the nature and extent of corrosion. The process of physical inspection has two components: visually examining the area with the naked eye along with flashlight and magnifying aids, and physically measuring the type, extent, depth, and length of corrosion features. Physical inspection is frequently not possible without a system shutdown or is made difficult by geometrical restrictions (e.g., smaller diameter pipeline). It requires the surface to be cleaned before inspection and restored afterwards. The restoration process may be application of internal coating or reformation of protective surface layers (inhibitor or corrosion). Physical inspection is labor intensive and depends to a large extent on operator experience, knowledge, and interpretation. Standards providing guidelines for performing physical inspections include: • •

ASME Boiler & Pressure Vessel Code, Section V, ‘Non-destructive Examination’ ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, ‘Rules for Construction of Pressure Vessels’

8.4 Field inspection

• •

515

ASNT Recommended Practice No. SNT-TC-1A, ‘Personnel Qualification and Certification in Non-destructive Testing’ NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’

8.4.2 Boroscopy A boroscope is an optical device consisting of three main components: an object lens, a relay lens, and an eyepiece (Figure 8.63).102 The object lens of a boroscope takes an image of the object (similarly to a camera lens) and transmits it to the relay lens. Torchlight may be placed near the object lens to illuminate the viewing area. In some advanced designs, the lenses are replaced by a video camera. The relay lens relays the image along the length of the boroscope to the eyepiece. Typically there is more than one relay lens. A boroscope is typically up to 6.6 inch (2m) in length, depending on the number of relay lenses. The eyepiece is an adjustable ocular lens used to view the image. This can be focused to increase the clarity of the image. The boroscope is useful for inspecting inaccessible areas. They typically range between 235 and 510 mil (6 and 13 mm) in diameter and their accuracy under ideal conditions is within approximately 1 mil (25 mm). This depends on the distance between object lens and the eyepiece, i.e., the length of the boroscope. Their magnification is higher if the distance is smaller. Boroscopes are straight, and hence require vertical access to the area to be inspected. Object Eyepiece and focusing mount

Optical relay carrying image back

Fiber optics carrying light to object

Image Flashlight adapter

FIGURE 8.63 Schematic Picture of a Boroscope.102 Reproduced with permission from Wiley.

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8.4.3 Fiberscopy Fiberscopes are similar to boroscopes except that they are flexible and can curl into inaccessible areas. In fiberscopes, the image or video from the object lens is transmitted to the eyepiece by fiber optic cables.

8.4.4 Liquid penetrant inspection The basic principle of this technique is that liquids penetrate into cracks and other surface imperfections due to capillary action. During measurement, a liquid penetrant (normally a colored dye or a fluorescent material) is applied after cleaning the surface. The liquid penetrates into the cracks and imperfections. These can then be visually observed, or a ultraviolet lamp can be introduced for observing fluorescent material. The liquid penetrant is normally water soluble, so that after inspection it can be cleaned from the surface by water washing.

8.4.5 Magnetic particle inspection (MPI) The magnetic particle inspection (MPI) technique can only be used to inspect magnetic materials such as carbon steel but not non-magnetic materials such as austenitic stainless steel, aluminum, or copper. MPI is widely used in the oil and gas industry to inspect environmental cracks (SCC or HIC). The surface to be inspected is magnetized either by using a permanent magnet or an electromagnet. When surface imperfections such as cracks are present, they distort the magnetic field and consequently leak flux. The imperfections are therefore identified by detecting the flux. To facilitate detection, fine magnetic particles are applied onto the surface. The particles are attracted to the surface imperfections when the structure is magnetized. The iron powders may be black, or red or yellow, and to facilitate detection they may also be coated with white paint or fluorescent material. Physical access to the surface to be inspected is required in order to carry out an MPI.

8.4.6 Thermography Thermography monitors thermal patterns in a structure. This technique can detect an 32 F (0.2 C) temperature difference between room temperature and 930 F (500 C), and a 35 F (2 C) temperature difference between 930 and 6,300 F (500 and 3,500 C). Among thermography techniques, the infrared camera is being used increasingly. In this technique, the material to be inspected is irradiated with infrared energy, and the energy reflected back from the surface is monitored by an infraredsensitive camera. In general the infrared camera is a global non-invasive non-contact (remote) inspection technique. Imperfections (pits, cracks, and other defects) reflect thermal radiation differently to intact areas. The locations of any imperfections are determined from the variations in the infrared image. Thermographic inspection only provides information on the location of imperfections. Additional techniques should be used to characterize them and to ensure that the imperfections are corrosion features.

8.4.7 Inline inspection (ILI) – magnetic flux leakage (MFL) Section 8.3.10 discusses the use of MFL as an external inspection technique. The mechanism of ILIMFL is the same as using MFL as external inspection tool. ILI-MFL is perhaps the most commonly

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used ILI techniques. Some of the characteristics of the method are discussed in the following paragraphs. Depending on the number of sensors used, ILI-MFL can be further classified as standard resolution (SR MFL), high resolution (HR MFL), or extra high resolution (EHR MFL). The main differences between these categories are the number, size, and orientation of the MFL sensors, the magnetic circuit design, the level of magnetization, and the sophistication of analysis. Table 8.14 compares some characteristics of various MFL tools.103 Additional sensors are used in HR MFL and extra HR MFL to discriminate between internal and external corrosion. MFL technology is suitable for both oil and gas pipelines. It only requires moderate cleaning. MFL tools are available for inspecting pipelines of diameter 3 in. (8 cm) and above. Several factors are considered before using ILI-MFL, including the mechanical characteristics of the steel, type of welds, length, internal diameter of the pipeline, elevation profile, availability of ILI launchers and receivers, pipe cleanliness, valves, bends, intrusions, internal coatings, drips, pyrophoric (materials that may catch fire, e.g., iron sulfides), and ability to analyze the data. Standards providing guidelines for using ILI-MFL tools include: • • • •

NACE SP0102, ‘Inline Inspection of Pipelines’ NACE Publication 35100, ‘Inline Non-destructive Inspection of Pipelines’ ANSI/ASNT-ILI-PQ, ‘Inline Inspection Personnel Qualification and Certification’ API 1163, ‘Inline Inspection Systems Qualification Standard’

8.4.8 Inline inspection – ultrasonic (ILI-UT) Section 8.3.9 discusses the use of UT as external inspection technique. Similar to ILI-MFL, UT is also used for the inline inspection of pipelines (ILI-UT). ILI-UT tools travel along the inside of the pipeline measuring the thickness of the pipe wall. The tools emit ultrasonic signals perpendicular to the wall. The wall thickness is calculated from the echo received from both the inner and outer wall, and the speed of ultrasound in pipe steel. A liquid couplant is required to transfer the sound between the transducer and the pipe. The oil being transported can serve this purpose; however gas is not a good couplant, so to use ILI-UT to inspect gas pipelines, the pipeline is filled with liquid (diesel or water) as a slug between two pigs. Some typical characteristics of ILI-UT are described in the following paragraphs. ILI-UT displays the data in three modes: A-scan, B-scan, and C-scan for easier analysis (Figure 8.64).104 This makes the interpretation of data relatively straightforward. It measures the wall thickness directly; therefore the depths of pits are reliable. It discriminates between internal corrosion and external corrosion features. A minimum wall thickness is required for reliable measurement. The technique measures the length and depth of corrosion features, therefore the data is used in the calculation of maximum allowable operating pressure (MOAP). However this technique cannot be used for pipelines below an internal pipe diameter of 6 in. (15 cm). Several factors including external corrosion, HIC, sharp dents, flat dents, buckles, wrinkles, ripples, inline valves, fittings, bends, branch appurtenances, hot taps, pipeline coordinates, repair sleeve, patches, laminations, inclusions, grind marks, girth weld anomaly, scabs, slivers, paraffins, and blisters may affect UT-ILI.

Table 8.14 Comparison of Characteristics of Inline Inspection e Magnetic Flux Leakage (ILI-MFL) Tools103 Standard Resolution

High Resolution

Ultra-high Resolution

Analog recording 40 to 150 (1.6 to 6.0)

2 (0.08)) 8 to 17 (0.3 to 0.7)

2 (0.08)))))) 4 to 12 (0.16 to 0.47)

• No discrimination between

• Discrimination between internal

• Discrimination between internal

• Minimum defect depth, % of wall thickness Minimum inspection speed requirement, m/s (mph) Maximum inspection speed requirement, m/s (mph) Depth sizing accuracy, % of wall thickness Length sizing accuracy, mm (in) Location accuracy, axial (relative to closest girth weld), mm (in.) Location accuracy, circumferential,  Confidence level of detection, % Inspection of internal corrosion Other features interfering during the ILI-MFL inspection of internal corrosion

)

internal and external defects. Approximate estimation corrosion severity

and external corrosion

and external corrosion.

20

10

3

0.34 (0.75)

0.5 (1)

4 (9)

5 to 5 (9 to 11)

2 (4.5))))))

15

10))

5 to 10

 13 (0.5) 50 (2.0)

10 (0.4))))  0.1 (4)))))

10 (0.4)  0.1 (4)

 30 80 No internal and external corrosion discrimination External corrosion, narrow axial external corrosion, sharp dents, flat dents, buckles, wrinkles, ripples, inline valves, fittings, casings (concentric), casings (eccentric), bends, branch appurtenances, hot taps, close metal objects, sleeves, puddle welds, laminations, inclusions, grind marks, girth weld anomaly, and scabs/slivers/ blisters

5 80 Yes

5 80 Yes

External corrosion, narrow axial external corrosion, circumferential cracks, sharp dents, flat dents, buckles, wrinkles, ripples, inline valves and fittings, casings (concentric), casings (eccentric), bends, branch appurtenances, hot taps, close metal objects, pipeline coordinates, sleeves, laminations, inclusions, hard spots, grind marks, girth weld anomaly, and scabs/slivers/blisters

External corrosion, narrow axial external corrosion, circumferential cracks, sharp dents, flat dents, buckles, wrinkles, ripples, inline valves and fittings, casings (concentric), casings (eccentric), bends, branch appurtenances, hot taps, close metal objects, pipeline coordinates, sleeves, laminations, inclusions, hard spots, grind marks, girth weld anomaly, and scabs/ slivers/blisters

if the tool operates with a fixed sampling frequency, the axial sampling distance increases with inspection speed for general metal loss, circumferential grooving metal loss, axial slotting metal loss, and corrosion at girth weld (for pitting corrosion: 10 to 20% and axial grooving metal loss: 20%) ))) in the axial direction; width sizing accuracy is  10 to 17 mm (0.4 to 0.7 in.) )))) Relative to the closet girth weld ))))) up to inspection speeds of 2 m/s (4.5 mph) ))

CHAPTER 8 Monitoring – Internal Corrosion

Characteristics Axial sampling distance, mm (in) Circumferential sensor spacing, mm (in.) Detection limit

518

Type of ILI-MFL

8.4 Field inspection

(A)

519

Scan

C

B

A

Defect in the structure

(B) 10 9 IP 8 7 C Signal strength

6 5 B

A 4 BW

3 2 1

0

1

2

3

4

5

6

7

8

9

0 10

Time A-Scan presentation of defects shown in Fig. 64.A

FIGURE 8.64 Typical A-, B-, and C-Scans of ILI Data.104 Reproduced with permission from Wiley.

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0

(C)

IP

1

C

2 Time/depth

3 4 B

5 6 7

A

8 9 0

1

2

3

4

5

6

7

8

9

10 10

BW

Scan distance B-Scan presentation of defects shown in Fig. 64.A

Test piece Defect Side view Scan pattern

Top view

(D)

Typical C-Scan presentation

FIGURE 8.64 (continued).

8.4 Field inspection

521

Standards providing guidelines for using ILI-UT tools include: • • • •

NACE SP0102, ‘Inline Inspection of Pipelines’ NACE Publication 35100, ‘Inline Non-Destructive Inspection of Pipelines’ ANSI/ASNT-ILI-PQ, ‘Inline Inspection Personnel Qualification and Certification’ API 1163, ‘Inline Inspection Systems Qualification Standard’

8.4.9 Other inline inspection tools103 Some ILI tools have some special features to control the tools (tethered tool), to control tool speed (bypass tools), and to inspect dual-diameter pipe (collapsible tools). Tethered tools are operated by using umbilical or tethered cable trucks. Normally, the ILI tools are transported at the speed of the fluid being transported, but bypass tools may have special features to control their speed. These special features control speed either by bypassing the flow or by using speed control units. The inspection speed of these tools remains constant for the entire run. Collapsible tools can travel through interconnected pipes of different diameters, and can continuously inspect both pipe sections. In addition to ILI-MFL and ILI-UT, several other ILI tools are used.

8.4.9a Eddy current tool These tools are especially useful to inspect internal cracks. The eddy current has limited ability to penetrate the pipe wall; hence this technique is not widely used.

8.4.9b Geometry tools (Caliper tools) Geometry tools are used to measure the inner diameter of the pipe, to detect dents caused by backfill, mechanical damage, and third party damage. They are normally used before sophisticated ILI tools are used. They use either mechanical arms or electromagnetic features to measure inner diameter.

8.4.9c Mapping tools Mapping tools are used to establish the absolute coordinates of the pipeline as longitude, attitude, altitude, and elevation. They measure coordinates (in the X, Y, and Z directions) using inertial navigation techniques. Gyroscopes are used to measure angular changes and accelerometers are used to measure velocity changes.

8.4.10 Reliability of corrosion data Before using the corrosion rate data, certain general aspects should be understood. They are significant decimals and reliability of measurement.

8.4.10a Significant decimals Corrosion rates – whether from the laboratory or from the field – are calculated from a measured parameter. When the measured parameter is converted into a corrosion rate using electronic calculators or spreadsheets, significant decimal points are placed. However, beyond certain points the digits are not significant. Standards providing guidelines for determining the proper number of significant digits include: •

ASTM E 380, ‘Standard for Metric Practice’

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Aluminum in B100 Inside Face 1000 100 10 1 0.1 0.01

0. 0 3. 1 6. 2 9. 3 12 .4 15 .5 18 .6 21 .7 24 .7 27 .8 30 .9 34 .0 37 .1 40 .2 43 .3 46 .4 49 .5 52 .6 55 .7

0.001

pit depth (um ) pits/mm2 of this depth

total pits/mm2 deeper than this depth

FIGURE 8.65 Typical Example of Plotting a Dataset in the Histogram Form.

8.4.10b Statistical analysis Section 12.2f discusses errors in any measurement. Corrosion test results, by their nature exhibit more scatter than any other test results. For this reason, a statistical analysis is frequently carried out. This allows estimation of the confidence in the test results. Some commonly used statistical methods to analyze corrosion test results are discussed in this section. Histogram: A histogram is a bar graph to display the scatter of the data. Figure 8.65 represents a typical histogram. It is constructed by segregating the corrosion test data into equal intervals and then presenting the number of data points within each interval as a bar. The number of intervals is selected so that each interval contains at least three points. A sufficient number of intervals is selected to depict the shape and symmetry of the bar heights. The development of a histogram thus requires many data points. Normal Distribution: If the distribution is normal, then it will be bell-shaped or symmetrical (Figure 8.65). Many statistical analyses assume that the distribution of the data points is normal, so this is verified before a statistical analysis is performed; otherwise the analysis leads to erroneous conclusions. Normal Probability Paper: If the data does not exhibit a normal distribution (i.e., it does not exhibit the distribution presented in Figure 8.65), the data may be examined by constructing a normal probability plot. Figure 8.66 illustrates a typical normal distribution paper. Standards providing procedures for constructing a normal probability plot include: •

ASTM G16, ‘Standard Guide for Applying Statistics to the Analysis of Corrosion Data’

Other Probability Paper: If the histogram is not symmetrical and bell-shaped, or if the normal probability plot does not show linearity, the data may be transformed to another data set that may be

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523

FIGURE 8.66 Illustration of a Typical Normal Distribution Paper.106 Reproduced with permission from ASTM.

normally distributed. Some commonly used transformation methods include Fourier analysis, analysis of variance (ANOVA), covariance, moving average, and regression. If the transformed data yield an approximately straight line on a probability plot, then the statistical analysis may be performed using them. However, the confidence intervals of the transformed data should be understood and reported along with the statistical analysis. Unknown Distribution: When the corrosion data points are insufficient or when the distribution cannot be determined by normal statistical analysis, the data points are considered as having unknown distribution. The unknown distribution data points may be analyzed either by assuming that they follow the pattern of similar types of data, or by using non-parametric methods which do not use the data efficiently. In both cases it should be understood that the result of the analysis is not accurate. Extreme Value Analysis: For determining the probability of localized corrosion, especially pitting corrosion or cracking (SSC and SCC), statistical tools for analyzing normal distributions are not useful. In this case, extreme value statistical analyses such as Weibull and Gumbel extreme value analyses are used.105 Standards providing guidelines for analyzing pitting corrosion data include: •

ASTM Standard G 46, ‘Standard Guide for Examination and Evaluation of Pitting Corrosion’

Mistakes during an experiment, recording the field data, or in calculating corrosion may preclude the statistical treatment of data, or lead to erroneous conclusions if included in the analysis. Sometimes a statistical analysis may identify mistakes by indicating that the probability of obtaining a particular result is very low. On the other hand, if the corrosion rate is a function of several independent variables,

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and those variables have errors associated with them, the error in the corrosion rate can be estimated by a special statistical technique called ‘propagation of variance technique’. Standards providing guidelines on statistical analysis include: •

ASTM G 16, ‘Standard Guide for Applying Statistics to Analysis of Corrosion Data’

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71. ASTM G77, ‘Standard test method for ranking resistance of materials to sliding wear using block-on-ring wear test’. 72. Microbiological degradation of materials – and methods of protection, European Federation of Corrosion, Number 9, 1992, The institute of Materials, ISBN.0–901716–02–2, London, England. 73. Little BJ, Wagner PA, Mansfeld F. Microbiologically influenced corrosion. Houston, Texas: NACE Corrosion Testing Made Easy; 1997. ISBN: 1–57590–035–1. 74. G. 1–877914–56–8, Kobrin, ‘A practical manual on MIC’NACE. Houston: Texas; 1993. ISBN. 75. Videla HA. Manual of biocorrosion. ISBN: CRC Press; 1996. 0–87371–726–0. 76. Pope DH. Discussion of methods for the detection of microorganisms involved in microbiologically influenced corrosion, biologically induced corrosion. NACE-8. In: Dexter SC, editor. Houston: NACE; 1985. p. 275. 77. Revie RW. Uhlig’s corrosion handbook. Pennington, New Jerse: John Wiley and Sons, Inc; 2000. 0–471–15777–5. 78. Papavinasam S, Gould WD, Macleod A, Revie RW, Attard M. Biosensor Development for monitoring of activity of sulfate-reducing bacteria in oil and natural gas pipelines. US Patent No 6,673,222; January 6, 2004. 79. Papavinasam S, Gould WO, Macleod A, Revie RW, Attard M. Biosensor development for monitoring of activity of sulfate-reducing bacteria in oil and natural gas pipelines. Canadian patent # 2,376,549; January 5, 2010. 80. Sooknah R, Papavinasam S, Revie RW. Validation of a predictive model for microbiologically influenced corrosion. Paper 8503. Houston, Texas: NACE; 2008. 81. Haile T, Papavinasam S, Gould D. Evaluation of a portable online 4-probe sensor for simultaneous monitoring of corrosion rate and SRB activity. CORROSION 2013, Paper # 2148. Houston, TX: NACE International; 2013. 82. Guan H, Jenkins A. Test equipment and procedures suitable to evaluate deepwater scale and corrosion inhibitors. NACE CORROSION CONFERENCE 2011, Paper #11345. Houston, TX: NACE; 2011. 83. Wang S, McMahon J, Wylde J, Welmer E, Fell D. Scale inhibitor solutions for high temperature wells in a steam drive reservoir. NACE CORROSION CONFERENCE 2010, Paper #10133. Houston, TX: NACE; 2010. 84. Becker JR. Corrosion and scale handbook, ed. l. 1998: PennWell. 85. ASTM G78, ‘Standard guide for crevice corrosion testing of iron base and nickel-base stainless alloys in seawater and other chloride-containing aqueous environments’. 86. ASTMG108, ‘Standard test method for electrochemical reactivation (EPR) for detecting sensitization of AISI Type 304 and 304L stainless steels’. 87. ASTM G31, ‘Standard practice for laboratory immersion corrosion testing of metals’. 88. Attard M, Papavinasam S, Revie RW, Demoz A, Sun H, Donini JC, Michaelian K. Comparison of pitting corrosion rates of coupons with those of pipe, materials performance. Materials Performance 2000;39:58. #10. 89. Papavinasam S, Doiron A, Revie RW. ‘Industry Survey on Techniques to Monitor Internal Corrosion’. Materials Performance 2012;51(2) p.34. 90. Dean SW. In-service monitoring. In: Davis JR, editor. ASM Handbook. Corrosion, ASM International, Figure 5, p. 197, vol. 13. ASM International; 1987. ISBN 0–87179–007–7. 91. Demoz A, Michaelian KH, Donini J, Papavinasam S, Revie RW. Corrosion monitoring methods evaluated on gathering lines. Pipeline & Gas Industry 2001;84(10):48. 92. Papavinasam S, Attard M, Revie RW, Demoz A, Michaelian K. Comparison of techniques for monitoring corrosion inhibitors in oil and gas pipelines. NACE Corrosion 2003;59(12):1096. 93. Martin RL. Potentiodynamic polarization studies in the field. Materials Performance 1979;18(3):41.

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94. Yang L. Multielectrode systems,‘ in ’chapter 8: Techniques for corrosion monitoring. Figure 8.9 (b), p. 197. In: Yang L, editor. UK: Woodhead Publishing; 2008. ISBN, 1–84569–187–3. 95. Yang L. Multielectrode systems,‘ in ’chapter 8: Techniques for corrosion monitoring. Figure 8.7, p. 195. In: Yang L, editor. UK: Woodhead Publishing; 2008. ISBN, 1–84569–187–3. 96. Yang L. Multielectrode systems,‘ in ’chapter 8: Techniques for corrosion monitoring. Figure 8.2, p. 189. In: Yang L, editor. UK: Woodhead Publishing; 2008. ISBN, 1–84569–187–3. 97. Yang L. Multielectrode systems. Figure 8.14, p. 207. In: Yang L, editor. chapter 8: Techniques for corrosion monitoring. UK: Woodhead Publishing; 2008. ISBN, 1–84569–187–3. 98. Papavinasam S, Doiron A, Attard M, Demoz A, Rahimi P. Non-intrusive techniques to monitor internal corrosion of oil and gas pipelines. CORROSION 2012, Paper #: 2012–23792. Houston, TX: NACE; 2012. 99. Demoz A, Papavinasam S, Michaelian K, Revie RW. Measurement of corrosion potentials of the internal surface of operating high pressure oil and gas pipelines. J ASTM Int, 5, 6, Paper ID JAI 101244. 100. Demoz A, Donini J, Papavinasam S, Revie W. Lessons learned from an instrumented field corrosion test loop. International Pipeline Conference, Calgary, Alberta, Canada. New York: American Society of Mechanical Engineers; 1998 vol. 1. p. 521. 101. Eckert RB. Field guide for investigating internal corrosion of pipelines. Houston, TX: NACE; 2003. 102. Roberge P. ‘Corrosion inspection and monitoring’, John Wiley series, Series Editor R.W. Revie, chapter 5: Non-destructive evaluation, Figure 5.14, p. 338, ISBN: 978–0-471–74248–7 (2007). 103. ‘Inline non-destructive inspection of pipelines’, NACE, Houston, TX. 104. Roberge P. ‘Corrosion inspection and monitoring’, John Wiley series, Series Editor R.W. Revie, chapter 5: Non-destructive evaluation, Figs. 5.10, 5.11, 5.12, and 5.13, p. 334–336, ISBN: 978–0-471–74248–7 (2007). 105. Gumbel EJ. Statistical theory of extreme values and some practical applications. U. S. Dept. of Commerce Applied Mathematics Series 1954;33. 106. ASTM G16, ‘Standard guide for applying statistics to analysis of corrosion data’.

CHAPTER

Mitigation – External Corrosion

9

9.1 Introduction The external surfaces of oil and gas infrastructure are exposed either to the atmosphere (aboveground structure) or an underground environment (buried in soil or submerged in water). The standard procedure for controlling external corrosion of structures exposed to the atmosphere is the application of electrically insulating coatings, and for underground structure, is the use of electrically insulated coatings and cathodic protection (CP).1–3 Coating is the first line of defense against external corrosion. If this fails, CP should act as backup, protecting those areas where the coatings have failed. Regulations in many countries require that all the external surfaces of underground structure are protected by these two systems. This chapter provides an overview of the coatings and cathodic protection used to mitigate external corrosion in oil and gas infrastructures.

9.2 Coatings Coatings control corrosion by physically isolating the structure from the environment. The coatings used in the industry have evolved over the years. They can be broadly classified into polymeric coatings, metallic coatings, girth weld coatings, insulators, and concrete coatings. Table 9.1 presents the various oil and gas sectors in which different classes of coating are used.

9.2.1 Polymeric coatings Polymeric coatings are the workhorse in the oil and gas industry, and are used to protect the external surface of many infrastructures.4 They are used as aesthetic and anti-corrosion coatings for aboveground structures, and as anti-corrosion coatings for buried or submerged infrastructures. Figure 9.1 presents the polymeric coatings used over the past 80 years.5 In the 1930s and 1940s, coal tar coatings were commonly used and were applied in the field. In the 1950s and 1960s, asphalt and coal tar coatings were commonly used and were applied in the field. Wax and vinyl tapes were also used to some extent during this time. In the mid-1950s, extruded polyethylene (two layer) coatings applied in the mill were introduced, and have continued in use since then primarily on small diameter pipes. From the 1960s to the 1980s, polyethylene (PE) tape coatings, either single or double wrap, were applied in the field. In the early 1970s, mill-applied fusion bonded epoxy (FBE) coatings were introduced, and have been increasingly used on large diameter lines since Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00009-1 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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CHAPTER 9 Mitigation – External Corrosion

Table 9.1 External Coatings Used in Various Oil and Gas Sectors Type of External Coatings

Sector

Component

Production

Drill Pipe Casing Pipe Downhole Tubular

• • • •

Usually not used Usually not used Polymeric Concrete

Acidizing Pipe

• • • • • • •

Polymeric Concrete Polymeric Polymeric Not applicable Polymeric Insulators

Wellhead Pipelines

• • • • •

Polymeric Polymeric Insulators Thermal spray Girthweld

Heavy Crude Oil Pipelines

• • • • • • • •

Polymeric Insulators Girthweld Polymeric Girthweld Polymeric Polymeric Polymeric

• • • • • • •

Polymeric Insulators Polymeric Girthweld Polymeric Girthweld Polymeric

Water Generators Gas Generators Open mining In situ Production

Hydrotransportation Pipelines Separators Gas Dehydration Facilities Recovery Centers (Extraction) Upgraders Waste Water Pipelines Tailing Pipelines Lease Tanks

Unique Reasons

• Concrete coatings are used in downhole tubular to prevent collapse of pipeline.

• Insulators are used in in situ production pipeline to maintain higher temperature. • Insulators are used in offshore production pipelines to avoid hydrate formation. • Thermal spray coatings are used in offshore pipeline to provide cathodic protection. • Girthweld coatings are applied in the field after the line pipes are welded together.

9.2 Coatings

531

Table 9.1 External Coatings Used in Various Oil and Gas Sectors Continued Sector

Component

Transmissionpipelines

Transmission Pipelines (Midstream Pipelines) Compressor Stations Pump Stations Pipeline Accessories Ships LNG Tanks

TransportationTankers

Refining

Railcars Other modes Gas Storage Oil Storage Refineries

Distribution

Product Pipelines

Special

Terminals City Gates and Local Distribution CNG Tanks Diluent Pipelines

Storage

CO2 Pipelines Biofuel Infrastructure High Vapor Pressure Pipelines Hydrogen Pipelines

Type of External Coatings

Unique Reasons

Polymeric Girthweld Polymeric Polymeric Polymeric Polymeric Polymeric Insulators • Polymeric • Polymeric N/A • Polymeric • Polymeric • Insulators • Polymeric • Girthweld • Polymeric • Polymeric • Girthweld • Polymeric • Polymeric • Girthweld • Polymeric • Girthweld • Polymeric • Girthweld • Polymeric • Girthweld • Polymeric • Girthweld • • • • • • •

that time. They are now commonly used in North America. Since the 1980s, extruded three layer coatings have been in use in Europe and Japan. These consist of an inner layer of FBE and an adhesive layer followed by an outer polyolefin (polyethylene or polypropylene) layer. In the 1990s composite coatings were introduced. Composite coatings are a variation of three layer coating with inner FBE and outer polyolefin layers, but the adhesive is replaced with a graded layer of FBE and modified polyethylene.

9.2.1a Coal tar Coal tar enamels are thermoplastic in nature and are applied by pouring hot enamel on the structure to be protected.

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CHAPTER 9 Mitigation – External Corrosion

Composite 3-Layer Fusion Bonded Epoxy 2-Layer Polyethylene Tape Asphalt Wax & Vinyl Tape Coal Tar 1930

1940

1950

1960

1970

1980

1990

2000

2010

year

FIGURE 9.1 Coatings Applied in the Oil and Gas Industry Over the Years.5

i. Types A typical coal-tar enamel coating consists of liquid primers (adhesives), coal tar enamels, inner-wraps, outer-wraps, and finish coats (kraft paper, whitewash and/or water-emulsion latex paint). Liquid primers (adhesives) produce a bond between the metal and coal tar enamel. They are applied by brushing or spraying. The adhesives are prepared by dissolving coal tar pitch, coal tar oils, chlorinated rubber, and synthetic plasticizer in a suitable solvent. The coal tar enamels are prepared by dissolving processed coal tar pitch and inert mineral filler in a solvent (typically hydrocarbon oil). It is manufactured in three basic categories: unplasticized or regular enamel, semi-plasticized, and fully-plasticized.6 Regular enamel is a hard product. It has the higher resistance to moisture, petroleum oils, and soil stress but it has the narrowest temperature range of service and the least flexibility. Semi and fully plasticized coatings are produced by addition of small amounts of a special coal to the coal tar pitch. Semi-plasticized enamel has a wider service temperature range ( 18 to 60 C (0 to 140 F)) than the regular grade, and is somewhat more flexible. Fully plasticized enamel is produced in various grades for different service conditions. These are particularly suitable for pipeline applications. The inner wrap is a thin, flexible, uniform mat consisting of porous glass fibers bound together by a resin. It may be reinforced or non-reinforced. It is compatible with the coal tar enamel coating and its texture allows for it to be completely embedded within the coating material. There are three types of outer wraps: non-woven glass fiber, woven glass fiber, and laminated glass fiber. They are uniformly impregnated with coal tar enamel and are porous, so that the coal tar enamel bleeds through them and fuses into the finish coats. The finish coat may consist of one or more layers of kraft paper, whitewash, and/or latex paint. Kraft paper is a smooth and water-repellent material bonded onto the outer-wrap. The type of kraft paper, the name of the applicator, and the name of steel manufacturer are normally printed on it. Whitewash consists

9.2 Coatings

533

of linseed oil, quicklime, and salts all dissolved in water, and is applied on top of the outer-wrap. Latex paint consists of synthetic materials and pigments in water. After application the synthetic materials coalesce and dry, producing a white-colored, water-resistant layer that adheres onto the outer-wrap. Certain coal tar enamel coatings may also be applied at room temperature (cold-applied). Coldapplied coatings usually are used on structures exposed to mildly corrosive environments and not underground infrastructure.7

ii. Laboratory performance The properties of coal tar enamels vary widely because of the differences in ingredients, raw materials (especially coal), and manufacturing processes. Standard laboratory methodologies are used to establish minimum performance criteria. The performance requirements are described in the following standards: • • • •

ANSI/AWWA C202, ‘Coal Tar Protective Coatings and Linings for Steel Water Pipelines – Enamel and Tape – Hot Applied’ NACE RP399, ‘Plant-Applied, External Coal tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’ ANSI/AWWA C210, ‘Liquid Epoxy Coating Systems for the Interior and Exterior of Steel Water Pipelines’ NACE RP0602, ‘Field-Applied Coat Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’

iii. Field performance Coal tar coatings have a low permeability to moisture (water), high dielectric resistance, good antifouling properties and they are resistant to barnacles. All these properties contribute to their good corrosion resistance and performance in marine environment. Only small amounts of current are required to cathodically protect structures coated with coal tar. Coal tar coatings do not normally shield the current, but there have been a few reports of coal tar coatings disbonding in a manner that prevents the cathodic protection current from reaching the pipeline. In those instances, the pipeline is susceptible to corrosion. Excessive cathodic protection, on the other hand, may exfoliate coal tar coatings. Coal tar coatings have a tendency to alligator when exposed to sunlight; the outer-wrap of the coating hardens, contracts, and slips over the inner-wrap causing alligator marks. Coal tar coatings, therefore, should be protected from the sunlight. High operating temperature has resulted in cracks in coal tar coatings. Coal tar coatings are brittle at low ambient temperatures and have low adherence to steel at high ambient temperatures. Therefore temperature control during transportation and construction is important; otherwise these coatings may crack and disbond. The most frequent type of failure of coal tar enamel coatings during operation is associated with improper surface preparation. Studies have indicated that coal tar coatings applied to wire-brushed surfaces failed within one year, whereas the same coatings applied on sandblasted surfaces (surface profile is 1.5 to 3.5 mils (38 to 90 mm)) were in a satisfactory condition after five years exposure in the same environment. Many of the problems experienced with coal tar enamel coatings could have been minimized or even eliminated had there been a better understanding of surface preparation in the 1930s and 1940s, when these coatings were extensively applied.

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CHAPTER 9 Mitigation – External Corrosion

iv. State-of-the-art Until the 1960s, coal tar coatings were used extensively to protect steel pipelines in the oil and gas industry. However, since the 1970s, their usage declined progressively because of the variation in the properties of coal tar, limited supply of materials, environmental pollution during application (pouring of hot coal tar emits toxic fumes), and development of other superior materials. Currently, coal tar coatings are not extensively applied on new infrastructure but those which have already been coated with coal tar coatings do continue to operate.

9.2.1b Asphalt Asphalt is a dark colored cementatious material that is thermoplastic in nature. Its predominant constituent is bitumen. Asphalt is non-toxic and relatively tasteless. Chemically, it is a stable, polymeric, aliphatic hydrocarbon which has good resistance to water and chemicals. Asphalt varies in its chemical and physical characteristics, depending on the temperatures to which it is subjected during the distillation process. It has softening points ranging between 38 and 93 C (100 and 200 F). Asphalt is available as enamel, emulsion, or cutback. Asphalt enamel is a solid at ambient temperature and has a high softening point. Asphalt emulsion is a dispersion of asphalt particles in an aqueous phase. Small amounts of chemicals or clay are used as emulsifiers. The emulsion can be classified as anionic, cationic, or non-ionic depending on the electrical charge on the asphalt particle. Asphalt cutback is a liquid solution of asphalt in a volatile solvent.

i. Types There are two types of asphalt coatings: asphalt enamel and asphalt mastic. Asphalt enamel. An asphalt enamel coating consists of primer, enamel, and reinforcing and protective wrappers. Table 9.2 presents typical constituents of asphalt enamel.8,9 The primer is a blend of asphalt in a petroleum solvent which may be applied at room temperature (i.e., cold-applied) by brushing or spraying. Before application of the primer, any oil and grease on the surfaces of the steel pipe are removed with a petroleum solvent. The pipe surface is thoroughly cleaned by blasting, wire brushing or scraping. However, it should be noted that at the time when asphalt coatings were predominantly used, the conditions during the preparation of the steel surface were not tightly controlled. When the primer has dried, the hot asphalt enamel (typically at around 204 C (400 F)) is applied. The asphalt enamel consists of petroleum asphalt combined with appropriate inert mineral fillers. The wrapper is then applied simultaneously along with hot enamel. The wrapper may be single-wrap, double wrap, or multiple-wrap. Asphalt mastic. Mastic coating consists of a prime, mastic, and whitewash. Typical minimum thickness of the mastic coating is 0.64 cm (0.25in.). The primer is applied in the same manner as the primer for asphalt enamel coating. When the primer has dried, the hot mastic mixture is applied. The mastic is a mixture of binder, mineral aggregate and miner filler, and is applied onto primer at temperatures between 128 and 204 C (280 and 400 F). The finished mastic coating is painted with a whitewash prepared from quick lime in water.

ii. Laboratory performance Many laboratory experiments conducted between 1910 and 1950s recommended asphalt coating as the primary coating of choice for protecting the external surface of underground pipelines. Cathodic

Table 9.2 Constituents of Asphalt Enamel8,9 Asphalt Enamel Constituents (layers from steel pipe) First Second Third

Double Wrap

Single-Wrap

Single Coat

Double Coat

Multiple-Wrap

1 Coat of asphalt primer 1 Coat of hot asphalt enamel 3/32 inch  1/32 1 wrap of asphalt saturated feltA or asphalt saturated glass wrap completely bonded to the enamel

1 Coat primer 1 Coat of hot asphalt enamel 3/32 inch  1/32 1 wrap of glass mat (embedded in coating)

1 Coat primer 1 Coat of hot asphalt enamel 3/32 inch  1/32 1 wrap of asphalt saturated felt, asphalt saturated glass wrap or glass mat completely bonded to the enamel 1 Coat of hot asphalt enamel 2/32 inch minimum

For multi-wrap coatings additional coatings of hot asphalt enamel and wraps of asphalt saturated felt, glass mat, or asphalt saturated glass wrap are used. Kraft paper may be used for the outside wrap only, to prevent adhesion to adjacent pipes or other objects

Fourth

Fifth

the felt may be made of asbestos

1 wrap of asphalt saturated felt or asphalt saturated glass wrap completely bonded to the enamel

9.2 Coatings

A

1 wrap of asphalt saturated felt or asphalt saturated glass wrap completely bonded to the enamel

535

536

CHAPTER 9 Mitigation – External Corrosion

disbondment testing was extensively used to select the appropriate composition of asphalt coatings. Table 9.3 lists other tests used to evaluate asphalt coatings.10,11 Standards providing guidelines on performance tests include: • •

BS 3690, ‘Bitumens for building and civil engineering specifications for bitumens for road and other paved areas’ EN 10300, ‘Steel tubes and fittings for onshore and offshore pipelines - bituminous hot applied materials for external coatings’

iii. Field performance The field performance of asphalt coating was extensively investigated in the 1950s and 1960s. One study found that the coating resistance decreased to about 7% of the original value over a period of 10 years. In spite of this substantial decrease in coating resistance, the current requirement after ten years was relatively small, and the pipeline did not suffer any corrosion damage.12 In another study, a 539 km (335 mi.) 41 cm (16 in.) diameter pipeline constructed in the 1940s was surveyed twice at approximately ten year intervals.13 After ten years, the Pearson survey (see section 11.3.6) revealed 200 anomalies: 23% of which were characterized as weak, 57% as moderate, and 20% as strong. Forty anomalies (characterized as strong) were excavated and the performance of the asphalt coating examined (Table 9.4). Of over 278,700 m2 (3 million sq. ft.) of asphalt mastic coating, only 4.6 m2 (50 sq. ft.) was damaged. The coating discontinuity was measured as 1 per 6.4 km (4 mi.) of pipeline. The coating conductance was also low, indicating that the water absorption of the coating was limited (Table 9.5). After approximately 20 years, the follow-up coating conductance survey (see section 11.3.4) was conducted and the results were compared with the 10 year survey data. Progressive deterioration of the coating as a whole was not evident, and the coating conductance was still relatively low, indicating that the coating was still adequately protecting the surface. Two discontinuities, which had been classified as medium signal strength during the 10 year survey, were excavated.14 At both locations the discontinuities had enlarged in area, and the pipe surface had rusted to a considerable extent, although no pitting of the pipe was observed. The coating adhered to the soil lumps and had little or no bond to the pipe. The coating on the soil lump had softened to the extent that a hole could be dug in the mastic with a knife. In one location, the 20 year survey indicated that the coating discontinuity exceeded the length of the 122 cm (4 ft.) bell hole. This discontinuity should have been classified as a major discontinuity 10 years previously, but there was no indication of it in the 10-year survey. (It would appear the coating had progressively disintegrated at the holidays between the two surveys.) At another location in which the aboveground survey indicated no anomaly, 305 m (1,000 ft.) section of pipe was excavated. The inspection revealed two coating blisters of approximately 10 cm (4 in.) in diameter and of approximately 9.5 mm (3/8 in.) in height. The blistered coating was 12.7 mm (1/2 in.) thick and had no visible cracks or pinholes. The pipe surface under the blisters was dry, but had rusted considerably, indicating that cathodic protection had not reached the pipe surface below the blister. The coating in the remaining inspected portion of the pipe adhered onto the pipe well, including the areas adjacent to the blisters. It was not known whether these blisters were caused by some incident at the time of construction or resulted from cathodic protection current. One common problem observed with asphalt coating is the bleeding of the asphalt enamel through the outer wrap.15 When this happens, the asphalt coating softens on the side covering the steel and

Table 9.3 Methods for Testing Asphalt Coatings10,11 Standards Property

Primer for Enamel

Primer for Mastic

Enamel

Binder for Mastic

Flash point

Bureau of Explosives, AASHO Method of Test T79 ASTM D 88 ASTM D 402 ASTM D 5 ASTM D 36 ASTM D 4

Bureau of Explosives, AASHO Method of Test T79 ASTM D 88 ASTM D 402 ASTM D 5 ASTM D 36 ASTM D 4

ASTM D 92

ASTM D 92

ASTM D 5 ASTM D 36 ASTM D 4

ASTM D 5 ASTM D 36 ASTM D 4

ASTM D 6 ASTM D 271

ASTM D 6

NACE T-6A-19

ASTM D 113 ASTM D 546 NACE T-6A-19

9.2 Coatings

Viscosity Distillation Penetration Softening point Solubility in carbon tetrachloride (except that CCl4 is used instead of CS2) Bond strength Loss of heating at 325  F Ash Durability Sieve analysis Impact strength, bending test, depression test, and electrical resistance

537

538

CHAPTER 9 Mitigation – External Corrosion

Table 9.4 Conditions of Asphalt Coatings after about Ten Years in the Field13 Conditions of Asphalt Coating

Number of Locations

Total number of excavations Friable mastic) Tool abrasion (e.g., construction damage) Miscellaneous None found (Several discontinuities as indicated by Pearson survey upon excavation and visible inspection showed no obvious flaw or disintegration of the coating)

40 21 7 6 6

)

Loss of cohesion between the asphalt and mineral aggregate giving the coating a fried appearance

Table 9.5 Field Performance on Asphalt Coatings13 Miles Inspected

Approximate Age of Coating, Years

Pearson Survey Results

Average Coating Conductance, Micromhos per sq. foot

4e25 6.8 6.0 50

Less than 5 10 10 10

Not performed No discontinuities No discontinuities Discontinuities

1.21 1.01 1.54 6.6

disbonds from it. Another common problem with asphalt coating is cracking and moisture absorption. When an asphalt coating ages, it loses its flexibility; consequently it cracks and absorbs moisture. Soil stress on pipelines further contributes to the cracking. The cracks result from repeated shrinking and swelling of soils (especially clay) due to fluctuations in their moisture content. For these reasons, asphalt coatings, particularly enamel, have very low resistance to soil stress. Because of moisture absorption, porous asphalt coatings pass cathodic protection current. For this reason stress corrosion cracking (SCC) is less prevalent under asphalt coatings.16 Most field problems with asphalt coatings have been attributed to the quality of application. Asphalt coatings were predominantly applied in the field, and the extent of surface preparation, particularly in the early days of the pipeline industry, was minimal when compared to today’s standards. Had the external surfaces of the steel structure been better prepared prior to the application of the coating, their performance would have been even better.

iv. State-of-the-art Asphalt coatings are no longer in common use for onshore underground infrastructure, primarily because of the availability of better, mill-applied coatings. Some companies may still use them on concrete-coated offshore pipelines.

9.2 Coatings

539

9.2.1c Tape The use of tapes as a pipeline coating originated from their successful application for insulating electrical wires. Tapes may be applied in the mill or in the field.17–18 The development of procedures to wrap them onto the pipeline in the field made tape coatings popular in the 1970s. The tapes may be spirally wrapped by hand, or, more frequently, by machines.

i. Types Eight tape coatings are frequently used in the oil and gas industry.19–21 The following section describes the constituents of these coatings, and Table 9.6 compares their performance. Polyethylene (PE). Polyethylene (PE) is a linear or highly-branched polymer with a crystalline structure. The density of low density polyethylene (LDPE) is in the range 0.91 to 0.93 g/cm3 (0.0329 to 0.0336 lb/in.3) and that of high density polyethylene (HDPE) is in the range 0.94 and 0.97 g/cm3 (0.034 and 0.035 lb/in.3). When compared to LDPE, the HDPE has a larger crystalline structure, higher yield strength, higher creep resistance, and is less permeable to aqueous phase, but it has lower resistance to elongation. The PE used as tape coatings is mostly LDPE, or a blend of LDPE and HDPE. Over the years, the compositions and performance of the coatings have been continuously improved.22–24 Table 9.7, for example, compares the properties of PE pipeline tapes used in the 1960s with those used in the 1970s. Some constituents of polyethylene type degrade at temperatures above 54 C (130 F), therefore polyethylene tapes are typically used to protect infrastructure operating at temperatures below 50 C (122 F). A typical polyethylene tape consists of three layers: adhesive, inner anti-corrosion tape, and outer mechanical protection tape. The inner and outer layers are prefabricated as rolls. The adhesive is a mixture of rubber and synthetic compounds in a suitable solvent, which is applied in the liquid form to a properly prepared surface. It provides a bond between the surface and the inner tape layer. The inner tape layer consists of a polyethylene backing layer and a laminated butyl-adhesive layer. The inner layer is applied after the liquid-adhesive and before the outer layer tape. The outer layer is also a twolayer tape consisting of a polyolefin backing layer and a laminated butyl-adhesive layer. One common failure mode of polyethylene tape is disbondment, usually caused by soil stress. The outer layer also has good resistance to the adhesion of foreign material, but still certain soils, e.g., clay can attach onto polyethylene tape. When this occurs, the polyethylene tape is stretched by alternate wetting (expansion) and drying (contraction). This problem cannot be overcome even with proper application, because polyethylene tapes stretch easily. The disbonded tape coating normally shields the cathodic protection current, and if water enters the area beneath the disbonded tape, corrosion occurs. Polyvinyl chloride (PVC). Polyvinyl chloride (PVC) tapes have characteristics similar to polyethylene tapes. They resist ultraviolet (UV) rays, but are stiff and lack conformability, so they are primarily used on aboveground rather than underground structures. Plasticized PVC tapes, however, are flexible. Polymer alloy. Polymer alloy tapes also have characteristics similar to PVC tapes, but they are not as stiff. Therefore they can be used as coatings to protect both aboveground and below-ground infrastructures. Hot applied. Hot applied tapes consist of a bituminous material within a fabric. These tapes are pliable enough to unwind from the roll. The adhesive is first applied on the surface, and the pipe is heated to approximately 120 C (250 F) to facilitate the bonding of the adhesive onto the pipe surface and that of the tape onto the adhesive.

540

Wax

Woven Polyolefin Geotextile Fabric

Tapes with Integrated Primers

Co-Extruded

Properties

Polyethylene

Poly vinyl Chloride

Soil stress resistance Adhesion to steel CP Shielding Handling in Field Damage repair Compatable field joint material Bending Compatibility Ease of Application Resistance to Bacteria Cathodic Disbondment Surface Preparation

Poor Good Poor Good Good Better

Poor Good Poor Good Good Good

Poor Good Poor Good Good Better

Good Good Good Better Better Better

Poor Poor Good Poor Better Better

Good Good Better Good Good Poor

Poor Good Poor Good Good Better

Better Better Better Good Better Better

Better Better Better Good Good

Good Good Better Good Good

Good Good Better Good Good

Poor Poor Poor Better Better

Poor Better Poor Good Better

Poor Poor Poor Good Good

Good Good Better Good Good

Better Good Better Better Good

Polymer Alloy

Hot Applied

CHAPTER 9 Mitigation – External Corrosion

Table 9.6 Comparison of Pipeline Tape Coatings19e24

9.2 Coatings

541

Table 9.7 Comparison of Polyethylene Tape Pipeline Coating Properties20e24 Manufactured in Property

1960’s

1970’s

Backing composition

100% Low density polyethylene

Backing thicknessA Adhesive type Adhesive thicknessA Tensile strengthA Adhesion to primed steelA Dielectric strengthA Impact resistanceB Tear resistanceC

0.23 mm Pressure sensitive 0.1 mm 4.5 kg/cm width 1.1 kg/cm width 13,000 volts 4.5 kg/cm 3.6 kg

60e80% Low density polyethylene þ 20e40% High density polyethylene 0.30 mm Butyl rubber based 0.2 mm 5.8 kg/cm width 3.0 kg/cm width 20,000 volts 8 kg/cm 6.0 kg

A

ASTM D-1000 Test Method ASTM G8 Test Method ASTM G-1004 Test Method

B

C

Wax. Wax tapes are made from plastic fiber saturated with a blend of petrolatum waxes, plasticizers, and corrosion inhibitors. Wax tapes are easy to apply but are vulnerable to construction and physical damage, so they are often backed with PVC or PE tape to provide mechanical protection. Woven polyolefin geotextile fabric. Some coatings use woven polyolefin geotextile fabric (WGF) materials as their backbone. The woven fabric materials provide both mechanical and corrosion protection. WGF tapes stretch to a lesser extent. For example, typical polyethylene tape stretches by up to 600%, but WGF stretches by only 15%. For this reason, WGF resists soil stress better than polyethylene tapes. In addition due to their fabric backbone they are cathodic protection compatible. Tapes with integrated primers. Tapes with integrated primers are similar to the PE tapes when they have a solid-backing and are similar to WGF tapes when they have a mesh backing. The experience with this type of coating is limited. Co-extruded. Co-extruded tapes contain, in addition to the normal ingredients of PE, synthetic butyl rubber adhesive.

ii. Laboratory performance The performance requirements are described in the following standards: • •

ANSI/AWWA C214, ‘Tape Coating Systems for the Exterior of Steel Water Pipelines’ ANSI/AWWA C209, ‘Cold-Applied Tape Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines’

iii. Field performance Tape coating was first applied to a 19 km (12 mi) long, 20 cm (8 in.) diameter natural gas pipeline in 1954 in Texas. An evaluation in 1970 indicated that this line was still in operation and the polyethylene tape coating was in good condition.25

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CHAPTER 9 Mitigation – External Corrosion

Between 1954 and 1956, the use of plastic tapes on pipelines grew, mainly due to the development of power-driven equipment to apply the coating in the field on pipe sizes in the 15 to 25 cm (6 to 10 in.) range. Equipment for applying the tape coatings on larger diameter pipelines was developed by 1956. In 1958, polyethylene tape was applied to 2,414 km (1,500 mi.) of 15 to 61 cm (6 to 24 in.) diameter natural gas transmission pipeline. This was the first major pipeline to be externally protected with polyethylene tape. The first stationary wrapping equipment was fabricated in 1959. The combination of stationary wrapping equipment and polyethylene was well suited to field application, since it allowed polyethylene tape to be extensively and quickly applied in the field. In 1965, the ability to apply plastic tape in extremely cold weather conditions was demonstrated when 1.98 mm (78 mils) of 76 cm (30 in.) pipeline was coated with polyethylene tape in Northern Alberta, Canada. The temperature fell to as low as 35 C ( 31 F) during application. Daily application rates reached 3,658–3,962 m (12,000–13,000 ft), which was equivalent to the application rates at warmer temperatures. In 1967, a coating mill was built to apply a polyethylene tape coating. In this mill, the tape was applied automatically to full lengths of pipe, practically as the pipe was being made. By 1968, approximately 120,696 to 160,929 km (75,000 to 100,000 mi.) of pipelines of different sizes had been coated with polyethylene tape. In 1968 alone, polyethylene tape was applied to more than 9,656 km (6,000 mi.) of pipeline, of diameters between 13 and 132 cm (5 and 52 in.). In 1971, the length of pipeline applied with polyethylene tape coating increased to the equivalent of 11,265 km (7,000 mi.) of 76 cm (30 in.) diameter pipe. Most of the coatings were applied to pipelines of diameters between 41 cm (16 in.) and 122 cm (48 in.). Table 9.8 compares the coating conductance of a polyethylene pipeline coating over a period of about 20 years. The coating was applied to a 150 mm (6 in.) diameter pipeline of 48 km (30 mi.) Table 9.8 Coating Conductance of Polyethylene Tape and Coal Tar Coatings in Comparable Environments Coating Conductance, (mmhos/m3) Age of Coatings (Years)

Coal Tar Enamel

Polyethylene Tape

1 2 3 4 5 6 7 8 9 10 11 12 16 19

80.2 178.2 467.0 258.2 903.8 1248.2 1635.0 1108.3 1291.2 1527.9 2388.7 2238.1 e e

e 45.9 70 76.5 78.3 70 106.4 98.3 108.9 188.1 239.0 212.4 520 700

9.2 Coatings

543

Table 9.9 Current Requirements to apply Cathodic Protection on a Polyethylene Tape Coated Pipeline (48 Km length of w 200 mm Diameter Pipeline) Year

Current Requirements (mA/m2)

Pipe to Soil Potential (mV)

1958 1963 1964 1965 1968 1969 1970 1971 1972 1974

7.5 11.4 10.5 12.6 13.6 14.8 16.1 18.1 14.9 16.9

1270e2000 1275e1875 1350e1700 1200e1675 1175e1600 1125e1600 1050e1325 950Ae1650 950Ae1650 1000Ae1650

A

low P/S potential reading was measured at point of bond to a crossing pipeline

in length. The conductance of the tape coating was 700 mmhos/m2 (72 mmhos/ft2) indicating that it had retained its physical, chemical, dielectric, and moisture resistance properties even after 20 years of operation. The coating conductance of coal tar enamel coating in a similar operating environment was almost one order of magnitude higher than that of polyethylene tape.26–27 Table 9.9 compares the current requirements for a polyethylene tape coating on 48 km (30 mi.) of 200 mm (8 in.) pipeline. The current requirement increased from the initial 7.5 mA/m2 (0.7 mA/ft2) to 16.9 mA/m2 (1.6 mA/ft2) after 16 years of service. Several other studies have also indicated low current requirements for protecting different polyethylene coated pipelines (Table 9.10). Table 9.11 presents the CP current requirement data of more than 35,404 km (22,000 mi.) of pipelines in North America for a two year period. These pipelines were of various sizes and were

Table 9.10 Typical Current Requirements to Apply Cathodic Protection of Coated Pipelines Coating

Pipe Diameter, mm

Polyethylene tape 457 Polyethylene tape 203 Polyethylene tape 863 963 50 50 Polyethylene) Coal Tar Enamel) 50 )

on same pipeline

Pipe Length, km 140 148 1260 450 92 234 (of which 159 km coated with polyethylene tape) 234 (of which 76 km coated with coal tar enamel)

Construction Date

Current Density (mA/m2)

1969 1962 1963e69 1962e68 1967 1971

11.8 78.5 50.6 31.6 76.4 31.2

1971

132.3

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CHAPTER 9 Mitigation – External Corrosion

Table 9.11 Current Requirements to Apply Cathodic Protection on Pipelines Coated with Different Coatings26,27

Type of Coating

Length of Pipe (Miles)

Polyethylene Tape Asphalt Coal Tar Wax Other Total

3,648 6,552 10,744 1,056 395 22,395

Average Pipe Diameter (Inches) 12.5 18.0 20.4 19.5 8.3

Current Required (mA per Sq.ft.) Average

Range

9.6 6.5 10.5 11.0 0.9 9.4

0.2e95 0.5e550 0.1e260 0.2e684 0.1e10 0.1e684

coated with different coatings: coal tar, asphalt, wax, and polyethylene tape. The soil and service conditions of all pipelines were comparable. The cathodic protection current demand values were comparable, but the variation of CP current demand of tape coatings was relatively low. By the late 1980s and early 1990s, after 25 years of successful usage, the industry started experiencing problems with the polyethylene tape coatings. The main problems include: shielding of cathodic protection current; disbondment at welds and dents; damage due to rock impingement; soil stress problems; and tenting that occurs between the pipe surface and the tape along the ridge created by the longitudinal weld reinforcement (Figure 9.2). For polyethylene tape coatings, the cohesion (its ability to adhere to itself) exceeds the adhesion (its ability to adhere to the pipe). When ground water moves in the gap between coating and pipe surface, corrodes the pipe, and forms corrosion products under the tape. The volume of corrosion products exceeds that of the corroded steel, so the corrosion products mechanically force the polyethylene tape from the metal surface. Since the tape’s cohesion exceeds its adhesion, the tape disbonds from the metal surface. The wedge created by the corrosion products between the pipe and the polyethylene tape facilitates further disbonding. Polyethylene tape coatings are also prone to disbondment because of tenting, which occurs between the pipe surface and the coating along the ridge created by the longitudinal weld reinforcement.28 A second area of potential disbondment is the overlap between successive wraps of tape. When polyethylene tapes disbond, they allow moisture to penetrate under the coating. The high electrical insulating property and high cohesive strength of the polyethylene tape prevent the cathodic protection current – applied through the soil – from reaching the pipe surface beneath the disbonded polyethylene tape. Consequently, the environment beneath the disbonded polyethylene tape sustains corrosion and stress-corrosion cracking in spite of the fact that the pipeline is externally protected by CP. Polyethylene tape coating is a significant factor in the occurrence of near-neutral pH SCC experienced in Canada in early 1990s; nearly 75% of failures caused by near-neutral pH SCC have occurred on polyethylene tape coated pipe (see section 10.3.2 for more details). Single-wrapped polyethylene tape coated pipe had five times as many SCC colonies per meter as asphalt/coal tar coated pipe. Double-wrapped polyethylene tape-coated pipe had nine times as many colonies per meter as asphalt/ coal tar coated pipe. Near-neutral pH SCC typically occurs on the exterior surface of a pipe coated with polyethylene tape in the tenting region of the double submerged arc weld and adjacent to it. Cracks

9.2 Coatings

545

FIGURE 9.2 Tenting of Polyethylene Coating on Pipelines Leading to Stress-Corrosion Cracking.28 Reproduced with permission from Wiley.

also form in the body of the pipe in areas where the coating has been damaged, or where a disbondment has formed along the spiral tape overlap (see Fig. 9.2). Polyethylene tape also sustains bacterial growth. The organisms grow at the overlap between the polyethylene tape wrap, with the organic adhesive providing nutrients. A study found that a polyethylene coated pipeline submerged in a lake had large colonies of shell and organic matter on the surface.29 Polyethylene tape coatings in clay soil are also susceptible to wrinkles. The wrinkles form because the tangential force applied by the clay soil is greater than the tape adhesion and the polyethylene yield strength. This force causes damage to the coating, especially at the 3 and 9 o’clock positions. In some cases, the wrinkles formed on the outer layer penetrate to the inner layer of the coating. A study found that after about 10 years of service on a 41 cm (16 in.) diameter pipeline 111 km (69 mi.) long pipeline, the polyethylene tape in the sandy and rocky soils was in excellent condition, but in clay soil it had wrinkled.

iv. State-of-the-art The occurrence of near-neutral pH SCC in major North American gas transmission pipelines wrapped with disbonded polyethylene tape coating resulted in the industry stopping using tape coatings on larger diameter pipelines.30 A survey conducted in 1988 indicated that only 7% of the pipeline

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CHAPTER 9 Mitigation – External Corrosion

companies use polyethylene tape as their primary coating for large diameter pipelines (> 41 cm (16 in.)). Another survey indicated that at least five major gas transmission companies have discontinued or significantly restricted the use of polyethylene tape coatings even as repair coatings. The problems cited by these companies include: shielding of cathodic protection current, disbondment at welds and dents, damage due to rock impingement, high sensitivity to application techniques, soil stress problems and high susceptibility to SCC. As a result of these issues, polyethylene tape is currently not the primary coating of choice for new underground pipelines.

9.2.1d Extruded polyolefins Extruded plastic coatings have been available to the oil and gas industry since 1956. Thermoplastic coatings are applied on to pipelines by an extrusion process (Figure 9.3).31,32 High density polyethylene – commonly known as extruded polyethylene – is the most frequently used polymer. This coating is yellow in color and hence it can be known commercially as ’yellow jacket’. Polypropylene extruded coatings may also be used. Extruded polyethylene and polypropylene coatings are collectively known as extruded polyolefin coatings. The operating temperature range for an extruded polyethylene coating is 40 to 82 C ( 40 to 180 F) and for extruded polypropylene coating it is 21 to 88 C ( 5 to 190 F).

i. Types The extruded polyolefin coatings may be broadly classified into four types depending on the extrusion process and the type of adhesive used:33 The adhesive used in Type A is rubber modified asphalt. Type A coating is crosshead-extruded onto the pipeline. The Canadian Standards Association (CSA) standard CSA Z245.21 classifies the Type A as System A1. Type A coating is extensively used in North America and Australia. It is only applied to smaller diameter pipelines, i.e., up to 61 cm (24 in.). The adhesive used in Type B is butyl rubber. It is either side-extruded and spirally wrapped or spirally extruded around the pipeline. CSA Z245.21 classifies the Type B as System A2. The peel-adhesion requirement of Type A2 is 19.6 N/25 mm whereas that of Type A1 is 3.0 N/25 mm. Type B can be applied on pipelines of diameters between 6.35 and 262 cm (2.5 and 103 in.). Both Type A and B coatings can be used up to temperatures between 60 and 66 C (140 and 150 F).34

FIGURE 9.3 An Extrusion Process.31,32

9.2 Coatings

547

The adhesive used in Type C and D is ethylene copolymer or terpolymer. Type C coating is crosshead-extruded and Type D is helically extruded onto the pipeline. Types C and D are extensively used in Europe and the Middle East. An ethylene copolymer or terpolymer adhesive is used in these extruded polyethylene coatings.35 It should be noted that there is another process called fusion bonding which is used to apply polyethylene. This process of application is entirely different from the extrusion process. Commonly, low density polyethylene may be fusion bonded to the pipeline. Such fusion bonded low density polyethylene (FBPE) has been used since 1983 in Australia.36 During this type of application, the pipe surface is first grit blasted and preheated. The pipe is then clamped into the dipping beam, which is then lifted by overhead crane into the fluidized polyethylene bed. The pipe is slowly dropped into the polyethylene bath. The polyethylene bath consists of homopolymers or copolymers of ethylene, other olefinic materials, antioxidants, and carbon block. The lower edge of the heated pipe makes contact with the polyethylene, which fuses directly onto the pipe surface. The pipe is continuously rotated by the dipping beam at a constant circumferential speed. The first powder particles to touch the steel pipe surface are oxidized. This oxidation produces polar groups at the ends of the long chain polyethylene molecules which causes the adhesion of the coating to the steel pipe. As more powder is melted onto the steel pipe, the desired thickness is achieved. The coating thickness typically varies between 1.8 mm and 3 mm (0.07 and 0.12 in.), depending on diameter of the pipe. After coating, the pipe is removed from the polyethylene bath and it is heat-treated. This post-heat treatment ensures that the coating has properly been fused, and its surface porosity reduced. Post-heat treatment also provides characteristic smooth black finish. The coated pipe is then aircooled.

ii. Laboratory performance The performance requirements of extruded polyethylene and fusion-bonded polyethylene are described in the following standards: • • • • •

•

NACE RP0185, ‘Extruded Polyolefin Resin Coating Systems for Underground or Submerged Pipe’ CSA Z245.21, ‘External Polyethylene Coating for Pipe’ DIN 30670, ‘Polyethylene Coatings for Steel Pipes and Fittings – Requirements and Testing’ ANSI/AWWA C215, ‘Extruded Polyolefin Coatings for the Exterior of Steel Water Pipelines’ ISO 21809-Part 1: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 1: Polyolefin Coatings (3-Layer PE and 3-Layer PP) Australian Standard AS 2518, ‘Fusion Bonded Low Density Polyethylene Coating for Pipes and Fittings’

iii. Field performance Extruded polyethylene coatings have been the workhorse of the oil and gas industry for protecting the external surfaces of small diameter pipelines. They have excellent resistance to soil stress and most other forms of degradation. They are extensively used on pipelines in Arctic regions in Canada, USA, and Russia because of their high impact resistance at low temperatures. The impact resistance of extruded polyethylene coatings increases with decreasing temperature, reaching a maximum at approximately 30 C ( 20 F) and then decreases. The impact resistance at 60 C ( 75 F) and at

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CHAPTER 9 Mitigation – External Corrosion

Table 9.12 Mechanical Properties of the Extruded Polyethylene29 Duration in Service, Years

Impact Resistance (Lbf.in)

Elongation (%)

Tensile Strength (Lbf/in2)

Thickness (mils)

Hardness (Shore D)

Before installation 2 8

46

638 40

4422298

50

463

44 36

353133 10368

2460611 1990213

45 43

554 572

þ10 C (50 F) are comparable. Changes to the mechanical properties of extruded polyethylene coatings occur over a wide range of temperature, with no sharp temperature at which the coatings become brittle.37 Studies conducted on more than 8,000 km (w5,000 miles) of offshore pipelines in Italy and Venezuela indicated excellent performance of extruded polyethylene coatings for more than 25 years. Table 9.12 compares the mechanical properties of coatings over eight years of field service.29 The mechanical properties do diminish progressively over the years, but the extruded polyethylene coatings adequately protect the pipeline, and most failures have been due to improper quality control during transportation, application, and construction. These include the use of improperly sized wood support for the pipeline during transportation, use of an improper die-head size (e.g., use of a 76 cm (30 in.) diameter die-head for extruding a 66 cm (26 in.) diameter pipe), and inadequate protection against UV exposure of the coating before installation.

iv. State-of-the-art Extruded polyethylene coatings continue to be extensively used, especially on pipelines of diameter up to 61 cm (24 in.).

9.2.1e Epoxy The term ‘epoxy’ refers to a chemical group which is a three-membered ring containing two carbon atoms and an oxygen atom. The simplest epoxy material is ethylene oxide (Figure 9.4). An epoxy resin is a polymer that contains two or more epoxy groups.38 There are three prominent types of epoxy resins: •

Digylcidyl Ether of Bisphenol-A Resin (DGEBA): Bisphenol-A and epichlorohydrin react to form this resin (Figure 9.5). For this reason this resin is frequently referred to as bisphenol-A epichlorohydrin. This resin is widely used to produce protective coatings.

C

C

O FIGURE 9.4 Epoxy Group.

9.2 Coatings

CH3 C

HO

549

O OH + CH2 - CH - CH2 - CI

CH3 Epichlorohydrin

Bisphenol - A O

O

CH3

CH2 - CH-CH2 O

O - CH2- CH - CH2

C CH3 DGEBA

FIGURE 9.5 The Reaction Between Bisphenol-A and Epichlorohydrin to Produce DGEBA Resin.

•

•

Novolac epoxy resin: Phenol and formaldehyde react to form this resin (Figure 9.6). Novolac resin has better chemical resistance than DGEBA to organic acids, and exhibits very low shrinkage but has low adhesion depending on formulation. Cycloaliphatic epoxy resin: Cyclic oleins and peracetic acid react to form this resin (Figure 9.7). It is frequently used to manufacture solvent-less liquid epoxy and solvent containing liquid epoxy coatings.

The epoxy resin itself is not a suitable material for coating, but it polymerizes in the presence of curing agents to produce a protective coating.39 The process of polymerization is also known as curing, and

OH

OH

+

CH2OH and/or

heat acid

CH2O

OH

Formaldehyde

Phenol

CH2OH

CH2

CH2OH

+ H2O

heat

+

OH Phenol or oligomers

OH

OH

OH

OH

OH

OH CH2

OH CH2 HO

CH2 Novolac Resin

FIGURE 9.6 The Reaction Between Phenol and Formaldehyde to Produce Novolac Resin.

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CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.7 Cycloaliphatic Epoxy Resin.

the chemical that initiates the curing is called the curing agent. Epoxy resins polymerize by two main methods: homopolymerization and copolymerization. During homopolymerization, the epoxy resin molecules react directly with each other in the presence of a catalyst such as tertiary amine, whereas during copolymerization, the epoxy resin molecules react with each other and also with the curing agent, so that the curing agent actually becomes a part of the resultant coating. Amines (aliphatic, aromatic, and polyamide), phenolic resins, vegetable oil fatty acids, Lewis acids, and acid anhydrides are usually used as curing agents, with the type chosen determining the properties of the epoxy coating. Table 9.13 presents a general trend of how the curing agent influences the properties of the resultant coating. In addition to the resin and the curing agent, the epoxy coating contains other chemicals known as fillers. These are added to modify the flow of coating, to dilute it, to improve its barrier properties, or to adjust its flexibility. The epoxy coating will also contain pigments, which provide characteristic color to the coating.

i. Types The epoxy coatings can be broadly classified into: FBE, solvent-less liquid epoxy, and solventcontaining liquid epoxy. Table 9.14 presents application characteristics of the different epoxy coatings. Fusion bonded epoxy. FBE requires heat to cure and to adhere onto the metal substrate. The raw materials (Table 9.15) including curing agents are mixed at low temperatures and ground to powders and are sprayed onto a heated substrate. The epoxy cures in the presence of heat to produce a smooth coating of the steel surface. Table 9.16 presents typical surface preparation and coating processes during application of FBE. Table 9.17 presents characteristics of FBE coatings.40 Solvent-containing liquid epoxy. Solvent-containing liquid epoxy is primarily used as weld-joint and/ or repair coating (see section 9.2.2d for more details).

Table 9.13 Influence of Curing Agents on the Properties of Epoxy Coatings Curing Agent Property

Aliphatic Amine

Aromatic Amine

BF3

Anhydride

Strength Electrical Properties Heat Resistance Dimensional Stability Cure

Excellent Good Good Good Room temperature

Excellent Excellent Excellent Very good High temperature

Good Good Good Very good High temperature

Good Excellent Good Excellent High temperature

9.2 Coatings

551

Table 9.14 Application Characteristics of Epoxy Coatings

Nature Type Raw material state Solids content (Volume %) Number of components Pot life Flammability Shelf life Application equipment Capital expenditure Compatibility Side extrusion Cross head extrusion Powder sprayed adhesive Recycling of oversprayed material Effective amount of deposited material (allowing for recycling and solvent evaporation losses), % Application temperature,  C Cure temperature,  C FBE application after application of adhesive Pipe coating speed, meter/ min Delay before quality control, h

Fusion Bond Epoxy (FBE) Powder

Solvent-Less Liquid Epoxy

Solvent Containing Liquid Epoxy

Thermoset Solid 100 One Not applicable No 6 months at 5e25 C Electrostatic powder spray Moderate

Thermoset Liquid 100 Two 5 minutes at 80 C No 12 months at 5e35 C Twin component hot airless spray Moderate

Thermoset Liquid 71 Two 1 hour at 20 C Yes 12 months at 5e35 C Cold airless or pneumatic spray Less expensive

Good Excellent Excellent Yes

Excellent Fair Fair No

Excellent Fair Fair No

95

50e80

35e55

180e 245 180e230 5e30 sec

25e190 150e190 30 sec.e2 h

25e190 150e190 30 sec.e6 h

2e15

0e10

0e10

1

24

24

Table 9.15 Typical Compositions of FBE Coatings Component

Function

Composition (%)

Bisphenol-A Dicyandiamide 2,4,6-Tris (Dimethylaminomethyl) Phenol Calcium Silicate Titanium Dioxide Chrome Oxide Diopside CaMg(SiO3)2 Calcium Carbonate Prehnite [2CaO.Al2O3.3SiO2]

Epoxy Curing Agent Catalyst Filler Pigment Pigment Filler Filler Filler

65e70 1e3 0.1e1 25e30 2e4 0.1e1 0.2e2 0.1e1 1e3

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CHAPTER 9 Mitigation – External Corrosion

Table 9.16 Typical Surface Preparation and Coating Process during Application of FBE Coating Material/Process

Conditions

Steel Surface roughness Cleaning Surface oxidation, preheat before coating application Storage of epoxy resin Coating method, electrostatic spray Post cure

Hot Rolled Shot or grit blasted Phosphoric acid (H3PO4) wash and water wash At 220 to 245 C (450 F) in air for 2 minutes maximum Humidity controlled (very low humidity) room at 15 C Fluidized bed using air with 40 C dew point 3 minutes at 204 C (400 F)

Table 9.17 Advantages and Disadvantages of FBE Coatings41 Properties

Advantages

Disadvantages

Cost

Reduced cathodic protection (CP) cost

Application

Mill application provides a good quality control Good control of material usage

Relatively high material cost High capital cost for application equipment Requires near white (SSPC-SP-10)

Corrosion protection

Compatible with cathodic protection Does not creep or flow in service Low CP current requirement with low increase in demand over time High adhesion prevents major handling damage

Sensitive to contamination Sensitive to surface condition (e.g., slivers) Subject to small scale damage resulting in small holidays Field repair techniques are either cumbersome or low quality Field joints are not as high quality as main coatings

Solvent-less liquid epoxy. Certain epoxy resins may be sprayed onto the pipeline without any solvent at room temperature. Such resins are normally viscous and take longer to cure. Solvent-less liquid epoxy coating has not yet matured enough to have been applied extensively on infrastructure, but are used in the field as rehabilitation coatings.

ii. Laboratory performance The performance requirements of epoxy coatings are described in the following standards: • •

CSA Z245–20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’ ANSI/AWWA C213, ‘Fusion bonded Epoxy Coating for the Interior and Exterior of Steel Water Pipelines’

9.2 Coatings

• •

• • • •

553

AWWA Standard, ‘Liquid Epoxy Coating Systems for the Interior and Exterior of Steel Water Pipelines’, ANSI-AWWA C210 ISO 21809-Part 2: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 2: Fusion Bonded Epoxy Coatings NACE RP0394, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’ NACE T-6B-B Report, ‘Amine Cured Epoxy Resin Coatings for Resistance to Atmospheric Corrosion’, Materials Performance 9(5) (1970), p.37 NACE T-6H-7 Report, ‘Epoxy Ester Coatings for Atmospheric Service’, Materials Performance 24 (1) (1985), p.54 NACE T-6H-28 Report, ‘Epoxy-Polyamide Coatings for Resistance to Atmospheric Corrosion’, Materials Performance 21 (7) (1982), p.51

iii. Field performance In one study, 40 excavations were made to examine FBE coated pipe, fittings, and welds. The results consolidated in Table 9.18 indicate considerable variations in the performance of FBE with respect to adhesion and cathodic disbondment. The pH beneath the disbonded coating in all field examinations was between 7 and 14, indicating that the cathodic protection current had penetrated the coating to protect the steel below.41,42 In another study, FBE coating was evaluated after five years of operation.29 Although good performance was noticed in most areas, in some locations the coating came off easily from the surface. A detailed failure analysis indicated that almost all failures were due to poor surface preparation (mostly due to chloride contamination), and due to damage of the coating during the transportation and

Table 9.18 Field Performance of FBE Coatings),40 Property

Condition

No Phosphoric Acid Pretreatment, %

With Phosphoric Acid Pretreatment, %

Adhesion

Excellent Good Poor Extremely Poor 0 1e5 6e10 11e20 20 Slight None

10 48 32 10 21 5 16 25 32 58 42

38 62 0 0 38 8 31 8 15 54 46

Cathodic Disbondment (Accidental holidays)

Underfilm Corrosion

) Based on results obtained from 40 test sites. Approximately five areas were tested per site. Percentages refer to the number of areas tested that exhibited the properties indicated

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CHAPTER 9 Mitigation – External Corrosion

Table 9.19 Performance of FBE on a Pipeline Transporting Hot Crude Property Temperature at the inspection zone Color change Thickness (mils) Hardness, H Impact resistance (lbf.in) Corrosion detected Failure, if any

( C)

Pipeline 1

Pipeline 2

Pipeline 3

85 Dark green) 17.8  1.8 >4 40 Yes Localized

108 Dark green 14.8  1.2 2 20 No No

94 Black 15.9  1.4 3 20 Yes Localized

installation. Table 9.19 presents the properties of an FBE coating on an oil transmitting pipeline after one year of operation at 85 C (185 F). The impact resistance of the coating decreased drastically. In addition, the color of the coating changed from light green to dark green, sometimes to black. The localized failure observed in pipelines 1 and 3 was attributed to mechanical damage. It is important to mention that these pipelines operated without CP. In another field, the performance of FBE on a hot pipeline under cathodic protection was evaluated and was found to be satisfactory. For this pipeline, about 1 A of current was enough to protect the 100 km (62 mi.) of 25 cm (10 in.) pipeline. This low value of current demand indicates that the coating damage is about 0.1 to 0.2%. A similar value of cathodic protection current was estimated for another 20 km (12.4 mi.) length of 30 cm (12 in.) gas pipeline. For the latter, the cathodic protection current demand after three years indicated average coating damage between 0.4 and 1%.43 Good performance of FBE coatings have also been experienced in onshore gas pipelines operating at 95 C (203 F), and in offshore oil pipelines operating at 100 to 110 C (212 to 230 F). In both fields, a few incidences of coating disbondment caused by mechanical damage were observed. Several field inspections have indicated the formation of blisters on FBE coatings. In most instances, the blisters originated at some form of defect (coating holiday (see section 11.2 for definition of holiday)) and the pH beneath the blister was above 7 indicating that the cathodic protection current passed through the blistered coating.

iv. State-of-the-art Currently, FBE is the primary coating of choice for new pipeline in many parts of the world, either as the single coating or as a base coat for multilayer coating.44 Surface preparation of the pipe prior to application of FBE is the factor which has the greatest effect in determining the performance of the coating. FBE coating is now almost exclusively applied in the mill, where surface preparation is extremely well-controlled.

9.2.1f Multilayer From the late 1980s, multilayer coatings have been increasingly used in Europe and Japan. The underlying principle behind these coatings is to combine the chemical resistance and interfacial properties of epoxies and the mechanical strength of polyethylene.45–52 Multilayer coatings are not just distinct layers of different coatings, but synergic interaction between various layers. It is

9.2 Coatings

555

Table 9.20 Comparison of Properties of FBE, Extruded Polyethylene, and Multilayer Coatings Properties

FBE

Extruded Polyethylene

Multilayer

Flexibility Adhesion Cathodic disbondment Impact resistance Moisture penetration Abrasion Soil stress Burn back Weathering Application

Excellent Excellent Excellent Limited Limited Excellent Excellent Excellent Excellent Excellent

Excellent Limited Limited Excellent Excellent Excellent Excellent Excellent Excellent Excellent

Excellent Excellent Excellent Excellent Excellent Excellent Excellent Excellent Excellent Excellent

therefore important that strong chemical bonds form between the different coating layers. Table 9.20 presents the advantages of multilayer coatings in comparison to FBE and extruded polyethylene coatings.

i. Types Various coatings may be combined to produce multilayer coatings, but three layer and composite coatings predominate. For some special conditions, a four layer coating is used. Three layer coating. A three layer coating consists of an epoxy inner layer, an adhesive intermediate layer, and polyolefin outer layer (Figure 9.8). Epoxy inner layer. The first layer of the multilayer coating is the epoxy inner layer, which is applied directly onto the steel. This epoxy primer layer: provides a thin continuous film that bonds directly and firmly onto the steel surface. It provides effective bonds with intermediate layer; thus ensuring good adhesion of all layers onto the steel; is resistant to chemical attack; and has good cathodic disbondment resistance. The epoxy primer layer may be FBE, solvent-less liquid epoxy, or solvent-containing liquid epoxy. In the early development of three layer coatings, liquid epoxy was used as the inner layer, but recently FBE is used more often. Before application of the inner layer, the steel surface is gritor shot-blasted giving a surface profile of between 60 and 110 mm (2 and 4 mils). Therefore, the typical minimum thickness of the epoxy inner layer is 150 mm (6 mils) to ensure that the metal surface is completely covered. The epoxy inner layer is typically between 50 and 100 mm (2 and 4 mils) thick. Adhesive intermediate layer. The adhesive intermediate layer joins the polar epoxy inner layer and non-polar polyolefin outer layer. The intermediate layer typically consists of species such as maleic anhydride grafted polyethylene or copolymers of maleic anhydride and polyethylene which can react with the epoxy inner layer, along with a co- or ter-polymer compatible with the polyolefin outer layer. To ensure that strong interfacial bonds form between the inner and intermediate layers, it is important that the intermediate layer is applied before complete polymerization (curing) of the epoxy inner layer takes place. The thickness of the intermediate layer is typically between 100 and 400 mm (3.9 and 15.7 mils).

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CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.8 Typical Three Layer Constituents.

Polyolefin outer layer. The outer layer consists of an extruded polyolefin: polyethylene or polypropylene. This layer is typically between 1.5 and 3 mm (59 and 118 mils) thick. The role of this relatively thick polyolefin outer layer is to provide mechanical protection for the structure and to act as moisture barrier. Polyethylene has excellent mechanical properties, but it softens at higher temperatures. Polypropylene has higher resistance to softening at higher temperature, but does not bond well with steel. Therefore, the polyolefin outer layer for higher temperature application is typically manufactured from polypropylene co-polymerized with small amounts of polyethylene.53–55 Anitoxidants may further be added to increase its oxidation resistance at higher temperatures. The co-polymerization of polypropylene with polyethylene also overcomes the brittleness of polypropylene at lower temperatures (approximately 0 C (32 F)), and the copolymer also has higher impact strength at low temperatures (as low as 30 C ( 22 F)). Composite coating. A composite coating consists of a blend of both epoxy and polyolefin (polypropylene or polyethylene) without the intermediate layer. To create a homogeneous blend, both the non-polar polypropylene and polar epoxy are suitably modified. The blend is then applied by extrusion or spraying. Four layer coating. Three layer coatings used in special applications, such as in hot countries where coated pipes may be exposed for long periods to solar radiation, may have an additional white antisolar acrylic coating 30–40 mm (1.2–1.6 mils) applied over the polyolefin outer layer. Such a coating thus consists of four layers.

9.2 Coatings

557

ii. Laboratory performance The performance requirements of multilayer coatings are described in the following standards: • • •

CSA Z245.21, ‘External Polyethylene Coating for Pipe’; Type B1 provides guidelines on 3-layer coating and Type B2 provides guidelines for composite coating NACE RPO185, ‘Extruded Polyolefin Resin Coating Systems for Underground or Submerged Pipe’ ISO 21809, ‘External coatings for buried or submerged pipelines used in pipeline transportation systems, Part 1: Polyolefin coatings (three layer PE and three layer PP)’

iii. Field performance Three layer coatings are widely used in Europe, and years of good performance have been experienced. Composite coatings have been in use for over 20 years. They are mostly used in Canada when the service temperatures is above 65 C (150 F). They are applied on pipelines of diameter up to 48"(1.2 meter) in diameter and of length over 500 km (310 mile) – however, examination of a section of composite coatings after exposure for 11 years underground indicated good performance.56

iv. State-of-the-art Three layer coatings are widely used in Europe, China, India, Middle East, and Japan. Composite coatings are increasingly being used as external coatings for pipelines in frontier areas.57–59

9.2.2 Girth weld coatings In the early stages of the oil and gas industry, coatings were applied in the field. Currently, mainline coating is applied onto linepipe as it is produced. The linepipe sections, with their coating, are then shipped to the field where they are welded together to produce pipeline. The coatings applied to protect weld-joints are known as girth weld coatings or joint coatings. Girth weld coatings are applied in the field where the conditions are not as good as in the mill where the mainline coatings are applied. Their performance depends on the bonds to the substrate and to the mainline coating, the moisture seal at the joints, and water absorption. Theoretically any mainline coatings (discussed in section 9.2.1) could be used as a girth weld coating. If a different girth weld coating is used, then it must be compatible with the mainline coating. Also, the process of applying the girth weld coating should not alter the properties of the mainline coating; mild processes are economical in the field; (for example, heating to a temperature of 200 C (392 F) to apply FBE may not be an optimum process in the field); and the process should not alter the strength of the girth welds (for example heating the pipeline to apply FBE may increase the strength of steel to a level that might make it unacceptable for certain services).60 Figure 9.9 presents various types of girth coatings used over the years,61 and the following section describes them.62

9.2.2a Tape coating Section 9.2.1c discusses the general characteristics of tape coatings and Table 9.21 provides specific characteristics of girth weld tape coatings.

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CHAPTER 9 Mitigation – External Corrosion

Poly propylene

Shrink sleeve Liquid Epoxy and urethane Fusion Bonded Epoxy Wax Tape Coal Tar and asphalt

1930

1940

1950

1960

1970

1980

1990

2000

2010

year

FIGURE 9.9 Girth-Weld Coatings Applied on Oil and Gas Industry Over the Years.61

Table 9.21 Characteristics of Girth Weld Tape Coatings

Tape

Application

Typical Maximum Operating Temperature,  C

Bituminous

Hot applied

30

1A

Petrolatum

Hot applied

30

1B

Wax

Hot applied

30

1C

Polymeric

Cold applied

50 to 80)

1D

ISO 21809e3 Type

Remarks • Single layer or multi-layers • May be applied with or without primer • Single layer or multi-layers • With primer • Single layer or multi-layers • With primer • Single layer or multi-layers • With primer

)

Specific coatings for higher temperature may also be available

i. Type In general, any type of tape coating discussed in section 9.2.1c may be used as girth weld coating, but the following four are frequently used: bituminous tape, petrolatum tape, wax tape, and polymeric (mostly olefin based) tape.

ii. Laboratory performance The performance characteristics of girth weld tape coatings are described in the following standards: •

ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 1: Tape coating)

9.2 Coatings

• • •

559

NACE RP 190, ‘External Protective Coatings for Joints, Fittings, and Valves on Metallic Underground or Submerged Pipelines and Piping Systems’ NACE Technical Committee Report 59–7, ‘Application Techniques, Properties and Chemical Resistance of Polyethylene Coatings’, Corrosion 15 (3) (1959), p.33 (117t) CSA Z245.22.10, Plant-Applied External Polyurethane Foam Insulation Coating for Steel Pipe – Annex A: Polymer Tape coatings

iii. Field performance Although formal studies on girth weld coatings are lacking, their field performance is similar to that of mainline tape coating (see section 9.2.1c)

iv. State-of-the-art Tape coatings are used as girth weld coatings because of the ease with which they can be applied in the field. A survey conducted in 1988 indicated that tape coating was the first choice for about 30% of the responders.

9.2.2b Heat shrinkable coating Heat shrinkable coatings are thermoplastic coatings consisting of an adhesive and an extruded polyolefin outer layer. Section 9.2.1d describes the characteristics of extruded polyolefins. The circumferential compression exerted by the shrinking polyolefin is the unique characteristic of this type of coating. This compression reinforces the bonding of the coating onto the steel surface. Heat shrinkable coatings are available as tubular sleeves, wrap-around sleeves, and tapes. They may also be applied on complex structures.

i. Type Heat shrinkable coatings may be broadly divided into two categories: those with primer and those without primer. Table 9.22 provides some characteristics of different types of heat shrinkable coatings.

Table 9.22 Characteristics of Heat Shrinkable Girth Weld Coatings

Tape

Primer

Adhesive

Polyethylene Polyethylene

No No

Polyethylene

No

Polyethylene Polypropylene

Liquid epoxy or FBE Liquid epoxy or FBE

Mastic High shear strength mastic High shear strength hybrid or hot-melt N/A N/A

Typical Maximum Operating Temperature,  C

ISO 21809e3 Type

50 90

2A-1 2A-2

120

2A-3

120 130

2B 2C

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CHAPTER 9 Mitigation – External Corrosion

ii. Laboratory performance The performance requirements for girth weld heat shrinkable coating are described in the following standard: •

21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 2: Heat Shrinkable Coatings)

iii. Field performance One study analyzed the compatibility of mainline and girth weld coatings, based on experience of more than 100,000 field joints. In the network, FBE mainline coating had FBE joint coating; three layer polyethylene mainline coating had heat-shrink sleeves, polyurethane, and polyethylene joint coatings; three layer polypropylene mainline coating had shrink sleeve, polypropylene, and polyurethane joint coatings; and tape mainline coatings had tape joint coating. Based on experience, the company continues to use shrink sleeve on three layer polyethylene and polypropylene mainline coatings.61

iv. State-of-the-art Heat shrinkable coatings are extensively used as girth weld coatings because of the ease with which they can be applied in the field.

9.2.2c Powder epoxy The fusion bonded coating (FBE) described in section 9.2.1e may also be used as a girth weld coating; girth weld FBE coating is commonly known as powder epoxy. In their use, care is taken so that the application temperature does not change the properties of the steel (application of FBE requires heating the steel substrate to higher temperatures, which may change the properties of the steel). Therefore, the application temperature is restricted to less than 275 C (527 F). The temperature limit is lower for higher strength steels (e.g., X70 and higher). The application process is also controlled so that the FBE adheres well onto both the steel and the mill-applied coating.

i. Type Two types of powdered epoxy coating exist: single and double layer.

ii. Laboratory performance In general, the standards used to evaluate mainline FBE can be used to evaluate girth weld FBE. Specific tests used to evaluate FBE girth weld coatings are described in the following standards: •

•

ISO 21809 Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 3: FBE Powder Coatings) NACE RP0402, ‘Field-Applied Fusion Bonded Epoxy (FBE) Pipe Coating Systems for Girth weld Joints: Application, Performance, and Quality Control’, NACE, Houston, TX

iii. Field performance The field performance of girth weld FBE coatings is similar to mainline FBE coatings.

9.2 Coatings

561

iv. State-of-the-art Fusion bonded epoxy powder coating is used as a girth weld coating with FBE mainline coating.

9.2.2d Liquid epoxy A solvent-containing epoxy coating (discussed in section 9.2.1e) may also be used as a girth weld coating. They are also known as two-part epoxy coatings. The epoxy resin and curing agent are separately dissolved in suitable solvents, and the two parts are mixed just before application. Increasingly, solvent-free two-part liquid epoxy field-girth weld coatings are used. The mixed liquid is then either sprayed or brushed on the infrastructure.63 The epoxy resin undergoes its polymerization reaction (curing) with or in the presence of curing agents to produce protective coatings. This reaction normally takes place at ambient or at slightly elevated temperatures (typically up to 65 C (149 F)). Several precautions must be taken to avoid the hazards associated with solvents. Considerable efforts are being made to reduce and/or replace the organic materials in the solvents.64 Formulations have also been developed with water as solvent; such coatings are known as water-borne epoxy coatings. However, water-borne epoxy coatings do not cure properly under moist conditions, or when the temperature is below 15 C (59 F).

i. Type There are two types of liquid epoxy coatings: • •

Traditional liquid epoxy girth weld coatings may be applied by brush, spray, roller, or trowel. ISO 21809-Part 3 classifies this liquid epoxy coating type as liquid epoxy 4A. Liquid epoxy coatings are further reinforced with glass flakes, glass mats, or glass fibers. ISO 21809-Part 3 classifies this liquid epoxy coating type as fiber reinforced Epoxy 4C.

ii. Laboratory performance The performance requirements of liquid epoxy are provided in the following standards: •

21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 4A: FBE Powder Coatings and Type 4C: Fiber Reinforced Epoxy)

iii. Field performance Liquid epoxy girth weld coatings are normally used with FBE mainline coatings. Experience with using liquid epoxy girth weld coatings and other mainline coatings has been mixed. One pipeline in which liquid epoxy girth weld coating was used with a three layer mainline coating has not been successful. The real reason for this incompatibility has not been properly established.

iv. State-of-the-art Their ease of application make the liquid epoxy coatings popular – especially with FBE mainline coatings.

9.2.2e Urethane Polyurethanes have been primarily used as thermal barrier coatings, and to some extent also as anticorrosion coatings. The polyurea coating is a variation of polyurethane coating and was introduced in the 1990s.65–68

562

CHAPTER 9 Mitigation – External Corrosion

Urethane coatings are also known as isocyanate coatings, because isocyanate is one of the starting materials for making urethane. Isocyanate reacts with another chemical containing a hydrogen atom attached to either an oxygen, sulfur, or nitrogen atom. Equation 9.1 shows the typical chemical reaction: RNCO þ R’XH / RNðHÞCðXÞOR’

(9.1)

If X in Eqn. 9.1 is oxygen, (i.e., R’XH ¼ R’OH), the product formed is known as urethane (Eqn. 9.2). RNCO þ HOH / RNðHÞCOOH’

(9.2)

In Eqn. 9.2, water reacts with isocyanate; i.e., R’ is H. Polyurethane coatings are generally formed by reacting polyisocyanate with polyols.

i. Types Polyurethane coatings may be classified as brushed, sprayed, or cast urethanes, on the basis of the way that they are applied.

ii. Laboratory performance The performance characteristics of polyurethane coatings are presented in the following standards: •

• • •

ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 4B: Liquid Polyurethane and Type 4E: Cast Polyurethane) NACE Task Group T-6H-30 Report, ‘Urethane Topcoats for Atmospheric Applications’, Materials Performance 23 (11) (1984), p.51 NACE Task Group T-6B-16 Report, ‘Urethane Protective Coatings for Atmospheric Exposures’, Materials Performance 1 (9) (1962), p.95 NACE Task Group T-6A-17 Report, ‘Urethane Protective Coatings’, Materials Performance 1 (6) (1962), p.105

iii. Field performance The field performance of polyurethane is similar to that of liquid epoxy coatings.

iv. State-of-the-art Polyurethane coatings are commonly used as girth weld coatings with FBE mainline coatings. Polyurethane coatings, in general, do not perform well above 60 C (140 F).

9.2.2f Vinylester This coating consists of a vinylester, reinforced with glass flakes, glass fibers, or glass mat. Vinylester girth weld coatings may be applied by brush, spray, roller, or trowel.

9.2 Coatings

563

i. Type There is only one type of vinylester used in pipeline application.

ii. Laboratory performance The performance characteristics of vinylester coatings are presented in the following standard: •

21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 4D: Reinforced Vinylester)

iii. Field performance Only limited information is available on the field performance of vinylester coatings.

iv. State-of-the-art Vinylester coatings may sometimes be used as girth weld coatings, but their use is limited.

9.2.2g Polyolefins The polyolefin coatings discussed in section 9.2.1d can also be used as girth weld coatings. Polyolefin girth weld coatings have an inner epoxy primary layer and an outer polyolefin layer.

i. Type Depending on the type of polyolefin and the manner in which the polyolefin layer is applied, polyolefin field joint coatings may be classified into five different types: flame spray polypropylene, hot applied polypropylene tape or sheet, injection molded polypropylene, flame spray polyethylene, and hot applied polyethylene tape or sheet. Table 9.23 provides general characteristics of these coatings.

ii. Laboratory performance Performance characteristics of polyolefin girth weld coatings are described in the following standards: •

ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Polyolefin based coatings) • Type 5A: flame spray polypropylene, • Type 5B: Hot applied polypropylene tape or sheet, • Type 5C: Injection molded polypropylene, • Type 5D: Flam spray polyethylene, and • Type 5E: Hot applied polyethylene tape or sheet).

iii. Field performance The field performance of polyolefin coatings is similar to heat shrinkable girth weld coatings, but the studies of their field performance are limited.

iv. State-of-the-art Polyolefin girth weld coatings are used with polyolefin mainline coatings, but they are not used as widely as heat shrinkable coatings.

564

CHAPTER 9 Mitigation – External Corrosion

Table 9.23 Characteristics of Polyolefin Girth Weld Coatings

Tape (Outer Layer) Flame spray polypropylene Hot applied polypropylene tape or sheet Injection molded polypropylene Flame sprayed polyethylene Hot applied polyethylene tap or sheet

Intermediate Layer

Typical Maximum Operating Temperature,  C

ISO 21809e3 Type

Epoxy

Optional

110

5A

Epoxy

Modified polypropylene powder

110

5B

Epoxy

Modified polypropylene powder Modified polyethylene powder Modified polyethylene powder

110

5C

70

5D

80

5E

Inner Layer

Epoxy Epoxy

9.2.2h Wax A wax coating consists of a microcrystalline wax (inner layer), wrap (intermediate layer), and hot applied wax (outer layer). They are normally used up to 50 C (122 F) and are flexible, semi-solid, adhere well onto material, do not brittle, and permeate through pores of the structure. They do not require a specific surface pattern in order to adhere so they can be applied onto poorly prepared surfaces. These properties make them attractive as girth weld coatings.69,70

i. Type There is only one generic wax coating.

ii. Laboratory performance The performance characteristics of wax girth weld coatings are described in the following standards: •

•

ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 7: Hot Applied Microcrystalline Wax Coatings) NACE RP0375, ‘Wax Coating Systems for Underground Piping Systems’

iii. Field performance Microcrystalline wax girth weld coatings have been used satisfactorily for a long time in the oil and gas industry for certain applications.

iv. State-of-the-art Wax coatings continue to be used as girth weld coatings in the oil and gas industry.

9.2 Coatings

565

9.2.2i Elastomeric An elastomeric coating consists of a primer, a bonding agent and an elastomer. The elastomer coating may either applied by in situ vulcanization or an adhesive method. In the former, the primer, bonding agent and unvulcanized rubber are first applied and are then bound together by applying polyamide tape. A portable autoclave is then used to cure the rubber. Once the rubber has cured the autoclave and polyamide tape are removed. In the adhesive method, the cured rubber sleeve is applied and is secured by an adhesive that cures at ambient temperature.

i. Type These coatings used may be classified into two types, depending on the type of elastomer used: polychloroprene and ethylene propylene diene monomer (EPDM) based. Polychloroprene is a solid rubber and is normally used on structures operating at ambient temperatures. EPDM based coatings have better temperature resistance than polychloroprene, so these are used on structures operating at elevated temperatures.

ii. Laboratory performance Performance characteristics of elastomeric coatings are described in the following standards: •

21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 8A: Polychloreprene and Type 8B: Ethylene Propylene Diene Monomer)

iii. Field performance No systematic field performance of elastomeric coatings is available.

iv. State-of-the-art Elastomeric girth weld coatings are used only when the mainline coating is also an elastomeric coating.

9.2.2j Visco-elastic coatings Visco-elastic coatings combine the properties of solid and liquid. They have good ratio between elasticity and viscosity. They are non-polar, hydrophobic, and highly adhesive coatings.

i. Type There are several types of visco-elastic coating.

ii. Laboratory performance The performance characteristics of visco-elastic coating are described in the following standard: •

ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 8A and 8B)

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CHAPTER 9 Mitigation – External Corrosion

iii. Field performance The field performance of visco-elastic coatings has not been systematically evaluated, but this coating has been widely promoted as a coating having good and flexible adhesion.

iv. State-of-the art Viscoelastic coatings are used on pipelines in hot-dessert regions.

9.2.3 Repair coatings When the primary coatings (mainline coating or girth weld coating) do not provide sufficient protection, they must be repaired. The coatings used for this purpose are known as repair or rehabilitation coatings. There are several reasons for using repair coatings, such as in situations when the mainline or girth weld coatings are accidentally damaged (which normally happens during construction); when inspection indicates presence of breaks in or disbondment of the mainline or girth weld coatings; when the mainline or girth weld coatings are intentionally removed to inspect the steel surface beneath; when operation requires tapping or welding new facility (e.g., additional pipe) into the existing infrastructure; or when the cathodic protection current demand increases to a point where it is not economical to effectively apply it. One field study reported that a steel pipeline transporting oil was initially coated with an asphalt enamel coating. After about 40 years of service the CP current demand increased to such an extent that it was not possible to apply sufficient current adequately. Therefore, the asphalt coating was removed from about 600 m (1,975 feet) length of the pipeline, and the exposed surface coated with a 100% solid epoxy-urethane repair coating. Initially only 465 m (1,525 feet) of repair was planned, but the longer length had to be recoated to achieve the CP application criteria ( 1.00 volt pipe to soil potential – see section 9.3.4). In general, any girth weld coating can be used or is used as a repair coating. The repair coating should meet the environmental and safety regulations, be economical, be compatible with the field application (e.g., surface preparation) and operating conditions, be effective in protecting infrastructure from corrosion, and be compatible with any adjacent pre-existing coating. Table 9.24 presents environmental and safety considerations in using field coatings.71 Table 9.25 and Table 9.26 present general and performance characteristics of field coatings.

9.2.4 Insulators Insulators are used to prevent the exchange of heat between the infrastructure and the environment. Insulators are primarily used in the offshore sector to minimize heat transfer between the pipeline and the ocean water. Insulating offshore pipelines prevents the formation of hydrates, wax, and asphaltenes (thereby, enhances flow), and increases the duration of cooling period after the system is shut off. Insulation is also used in oilsands pipelines, which transport heavy oil (see section 2.9.3 for more details) operating at elevated temperatures (typically up to 150 C (302 F)), and in refineries to retain higher temperatures (typically above 100 C (212 F)). The materials used as insulators should have good thermal insulation properties. The thermal insulation of a material is a measure of the transfer of heat, Q, across it, as given by (Eqn. 9.3): Q ¼ Uo ADT

(9.3)

Table 9.24 Environmental and Safety Considerations in Using Field Coatings71 Powdered Coating type

Tape

Heat shrinkable

Coating type

Tape

Heat shrinkable

Epoxy Powdered

Liquid Epoxy Liquid epoxy

Urethane

Urethane

Elastomeric

Polyolefin

Urethane

Urethane

Elastomeric

Polyolefin

Cast

Coal tar or

Copolymer

epoxy Sub-type

Several

Mastic, hot melt,

FBE

with epoxy primer Primer

Yes/no

100% solid

Coal-tar

Rigid (Aromatic

(polyamine

(polyamide

polyurethane)

polyurethane

cured)

cured)

No

Self or use others

No

No

No

No

FBE

100

100

100

74

100

100

100

100

No for mastic and yes for all others

Solids

Depends

content, %

on primer

Mix ratio

NA

NA

1:1

2:1

4:1

1:1

1:1

4:5:1

NA

Volatile organic

Present

0

0

0

1.9

0

0

0

0

content (VOC), lbs/ gallon Contains amines

Yes

Contains coal tar

Yes (in primer)

No

Yes

No

No

No

No

Yes

No

No

No

Yes

No

No

Yes (coal tar

No

based) or No (polyurethane based) Contains flammable

No

No

No

Yes

No

No

No

No

• Wrap

• Torch or electrical

• Electrostatic

• Brush

• Brush

• Spray

• Cast in

• Spray

• Wrap

• Spray

• Spray

18

24

12

12

solvents Application methods

resistance

spray

mold

• Fluidized bed • Heat cured Shelf life, months

6

6

6

9.2 Coatings

Yes

567

568

Table 9.25 General Application Characteristics of Some Field Coatings71 Powdered Epoxy

Sub-type

FBE

Optimal coating thickness, mil Surface preparation, SSPC standard (SSPC-SP) Blast profile, mils Ambient temperature,  F Substrate surface temperature,  F Materials temperature,  F Airless spray pump Spray pressure, psi Dry film thickness, mils (per coat) Number of coats required After coating, time to lapse before the coating is dry to touch, duration at temperature,  F

Liquid Epoxy

Urethane

Urethane

Elastomeric

Coal tar (polyamide cured) 16

Rigid (Aromatic polyurethane)

Cast

Coal tar or polyurethane

16

100% solid (polyamine cured) 25

25

40

40 to 80

10

10

10

10

10

10

2.0 Not applicable

2.0 Above 41

2 to 3 50 to 110

2.5 40 to 150

2.5 40 to 150

2 to 3 50 to 140

425 to 488

Not applicable

Above 41 and 5 F above dew point 120 to 150

50 to 110 and 5 F above dew point. 50 to 90

40 to 150 and 5 F above dew point 32 to 150

40 to 120 and 5 F above dew point 32 to 80

50 to 140 and 5 F above dew point 120 to 140

Not applicable

Plural

Single

Plural

Not applicable

Plural

Not applicable

2,200

2,100 to 2,500

1,800 to 2,500

Not applicable

4,260

25 (max)

45 (max)

24 (max)

Unlimited

40 to 100

Unlimited

1

1

1 to 2

1

1

1

90 secs at 450 F

2 hours at 75 F

4 hours at 75 F

1 to 10 min 75 F

15 min at 75 F

Less than 10 min at 75 F

CHAPTER 9 Mitigation – External Corrosion

Coating Type

Upon completion of coating

3 hours at 75 F

12 to 24 hours at 75 F

5 to 60 min at 75 F

45 min at 75 F

6 to 8 hours at 75 F

Upon completion of coating

3 hours at 75 F

24 to 48 hours at 75 F

5 to 60 min at 75 F

2 hours at 75 F

6 to 8 hours at 75 F

After holiday detection

3 hours at 75 F

24 to 48 at 75 F

30 to 180 min at 75 F

2 hours at 75 F

6 to 8 hours at 75 F

Not applicable

7 days at 75 F

7 days at 75 F

7 days at 75 F

5 days at 75 F

7 days at 75 F

No recoating allowed

Within 3 hours at 75 F

6 hours (minimum) and 24 hours maximum at 75 F

0.5 to 1.5 hours at 75 F

30 mins at 75 F

2 to 6 hours at 75 F

Patch component or liquid epoxy

Brash grade or patch component

Brush grade

Self or brush grade

Self or brush grade

Self or brush grade

9.2 Coatings

After coating, time to lapse before the coating is dry to handle, hours at temperature,  F After coating, time to lapse before holiday testing, hours at temperature  F After coating, time to lapse before backfilling, hours at temperature,  F Ultimate curing time, hours at temperature,  F After coating, time to lapse before recoating (i.e., application of subsequent layer) can be performed Material for repairing the coating

569

570

Table 9.26 General Performance Characteristics of Some Field Coatings71 Powdered Epoxy

Sub-type

FBE

100% solid (polyamine cured)

Average coating thickness, mils Adhesion to steel (ASTM D4541); mils Abrasion resistance (ASTM D4060, C517, 1 kg, 1000 cycles); mg loss Flexibility (ASTM D522); at 180 1’ mondrel Elongation (ASTM D638); Percentage Cathodic disbondment (CSA Z245.20; -3.5 V 48 hours); mm radius Dielectric strength (ASTM G149); kV Hardness (ASTM D2240); Shore D

18

Liquid Epoxy

Urethane

Urethane

Elastomeric

Rigid (Aromatic polyurethane)

Cast

Coal tar or polyurethane

27

Coal tar (polyamide cured) 20

30

40

53

1,650

1,850

750

2,000

1,750

1,000

120

135

160

80 (30 for ceramic containing coating)

52

40

Failed

Failed

Failed

Pass

Pass

Pass

4.8

2.8

3.2

4.8

4.5

59

8.0

6.0

17.5

4.0

3.0

10

29.7 (18 mils with 1,150 V/mil) 85

7.1 (27 mils with 263 V/mil) 82

5.1 (20 mils with 255 V/mil) 65

22.4 (40 mils with 568 V/mil) 72

24.2 (40 mils with 604 V/mil) 75

31 (53 mils with 585 V/mil) 68

CHAPTER 9 Mitigation – External Corrosion

Coating Type

160

29

28

50

120

76

Nil

Nil

13

5

3.1

6.6

100 to 230

30 to 120

30 to 120

40 to 150

40 to 195

30 to 120

0.83

2.0

1.2

1.4

1.0

2.0

7.5

3.8

12

12

10

37

13

8.6

3.5

58

60

2.6

Pass

Less than 3/80 undercut

Less than 3/80 undercut

Pass

Pass

Pass

Pass

Pass

Pass

Pass

Pass

Pass

9.2 Coatings

Impact resistance (ASTM G14); inlbs Penetration resistance (ASTM G17); Percentage Stability (wet) (ASTM D870);  F Water absorption (ASTM D570); Percentage Water vapor permeability (ASTM D1653); g/ m2/24 hours Volume resistivity (ASTM D257); 1014 ohm.cm Salt spray (ASTM B117); 2,000 hours Chemical resistance (CSA Z245.20); 10% HCl, 10% NaOH, 5% NaCl

571

572

CHAPTER 9 Mitigation – External Corrosion

Table 9.27 Thermal Insulation Properties of Some Materials72 Overall Heat Transfer Coefficient 2 

Insulation Material

BTU/hr-ft - F • BTU/hr-ft- F) • BTU-in/hr-ft2. F))

Polyethylene) Solid polypropylene Polypropylene foam Polypropylene) Polypropylene (PP)-solid)) Synthetic PP)) Synthetic polyurethane Synthetic polyurethane foam Polyurethane Polyurethane (PU)-solid)) Glass synthetic polyurethane Synthetic PU)) Polystyrene Mineral Wool)) Fiberglass)) Composite Synthetic epoxy)) Synthetic Phenolic)) Pipe-in-pipe synthetic polyurethane foam Pipe-in-pipe

0.20 0.50 0.28 0.13 0.04 0.02e0.04 0.32 0.30 0.07 0.04 0.03 0.02e0.03 0.26 0.25 0.24 0.12 0.02 0.01 0.17 0.05

W/m2-Kn (W/m-K)) 0.35 2.84 1.59 0.22

1.81 1.70 0.12 0.17

0.68

0.96 0.28

where Q is the heat transfer rate; Uo is the overall heat transfer coefficient; A is the surface area of the material; and DT is the difference in temperature between two sides of the insulating material. Table 9.27 presents the overall heat transfer coefficients of some materials.72

9.2.4a Types Polyurethanes are widely used as insulating materials.73–77 Polyurethane foams are formed by the encapsulation of gases during the polymerization reaction (Eqn. 9.1). These gases may be produced by the intentional addition of gas-producing substances (for example hydrocarbons or fluorocarbons), or they may be produced as a byproduct of the polymerization reaction (for example CO2 gas is formed when the reaction in Eqn.9.2 proceeds further (Eqn. 9.4)). ½RNðHÞCOOHŠ / RNH2 þ CO2

(9.4)

The amine produced in this reaction (Eqn. 9.4) may further react with an isocyanate to produce a polymer with a urea-type linkage (Eqn. 9.5): RNH2 þ RNCO / RNH

CO

NHR

(9.5)

9.2 Coatings

573

Table 9.28 Properties of Polyurethane Foams72 Nominal Density kg/m3

ASTM Test Method

Foam Property

160

224

320

500

D1622

Compressive strength at 20 C, MPa

2.035 1.999 3.300 3.494 0.0292

4.563 3.819 7.485 7.540 0.0345

8.144 9.144 15.829 17.107 0.0407

22.998 21.217 48.394 47.408 0.0425

D1621, perpendicular D1621, parallel D1621, perpendicular D1621, parallel C518

0.0253

0.0316

0.0346

0.0390

C177

95 < 20 10 2.412

95 < 20 10 3.517

95 < 20 10 6.649

96 < 20 10 12.582

D2856 D871 D1692 D1623

3.204

4.854

8.305

15.055

D1623

11.8 0.17

19.4 0.15

24.0 0.12

29.5 0.10

D1624 D2842

Compressive strength at 196 C, MPa Thermal conductivity at 20 C, W/mK Thermal conductivity at 160 C, W/mK Closed cell content % Leachable halides, ppm Flammability, /10 S.E Tensile strength at 22 C, MPa Tensile strength at 196 C, MPa Tensile modulus, MPa Water absorption, %Vol

The reactions presented in Eqns. 9.1, 9.2, 9.4, and 9.5 are adjusted to produce polyurethane foams of desired properties. Table 9.28 presents some typical properties of polyurethane foams. Typically, they have low thermal conductivity (i.e., the overall heat transfer coefficient is low) so they are used as thermal insulators. To protect the polyurethane from mechanical damage, an additional extruded polyethylene layer is applied. In some designs, an external metallic pipe physically protects the carrier internal pipe. This design is commonly known as pipe-in-pipe (PIP) or dry insulation, because the outer pipe prevents water ingress into the insulator. In PIP designs, the pipes are metallic and the annulus between them may be filled with insulation materials (foam, granular, gel, and inert gas), or it may be left as vacuum. Alternatively, several pipes are bundled together with insulating material. In a way, such bundled pipelines are a special configuration of PIP. PIP insulation is commonly used in offshore production to transmit fluids from high-pressure and high temperature (above 150 C (302 F)) reservoirs.

9.2.4b Laboratory performance The performance requirements of polyurethane thermal insulators are described in the following standards: • • •

CSA Z245.22, ‘Plant-Applied External Polyurethane Foam Insulation Coating for Steel Pipe’ ASTM G189, ‘Standard Guide for Laboratory Simulation of Corrosion Under Insulation’ ISO/TC 67/SC 2/WG 19, Petroleum and Natural Gas Industries – Wet Thermal Insulation Coatings for Pipelines, Flow Lines, Equipment, and Subsea Structures

574

• • • •

CHAPTER 9 Mitigation – External Corrosion

NACE SP 0198, ‘Control of Corrosion under Thermal Insulation and Fireproofing – A Systems Approach’ NACE Task Group T-6A-17 Report ‘Urethane Protective Coatings’, Materials Performance 1 (6) (1962), p.105 NACE Task Group T-6H-30 Report ‘Urethane Topcoats for Atmospheric Applications’, Materials Performance 23 (11) (1984), p.51 NACE Task Group T-6B-16 Report ‘Urethane Protective Coatings for Atmospheric Exposures’, Materials Performance 1 (9) (1962), p.95

9.2.4c Field performance A pipeline was designed for transporting dry bitumen from a production facility to a transmission pipeline. This 35 km (22 mi) long pipeline was designed for 30 years of service at an operating temperature between 120 C (248 F) and 130 C (266 F). A three layer system was selected to control corrosion and to thermally insulate this pipeline. It consists of an FBE anti-corrosion coating (350 mm (14 mil)), polyurethane foam insulation (50 mm (1.97 in.)) and extruded polyethylene (2.5 mm (100 mil)) or (3.8 mm (150 mil)). This pipeline has been operating for more than 10 years without any major issues. Depending on the formulation, polyurethane foams absorb and retain water. In one study, it was found that most water was retained superficially on the surface in one formulation, whereas water had penetrated the foam in another formulation.73 In another study, it was found that the polyurethane foams have low water absorption properties, but they absorb sufficient water to become electrically conductive and allow the passage of cathodic protection current.74

9.2.4d State-of-the-art A three layer system, consisting of an internal anti-corrosion layer, an intermediate insulation layer, and an external polyethylene layer, is widely used to prevent or reduce heat loss from systems operating at higher temperatures (e.g., refinery pipes and oilsands pipelines) or in systems exposed to colder environments (e.g., offshore pipelines).

9.2.5 Metallic (thermal spray) coatings Metallic (Thermal spray) coatings are used in submerged marine structures, especially offshore pipelines. Thermal spray coatings protect steel, either by acting as a barrier coating or as a sacrificial anode. Zinc (Zn) provides better galvanic protection and aluminum (Al) provides better barrier protection; hence Zn-Al alloys combine the protective properties of both Zn and Al. Among various combinations, 85% Zn–15% Al alloy is widely used. The history of the development of thermal spray metallic coatings can be summarized as follows: • • •

In 1742, a French chemist, Malouin, described a method for protecting steel by immersion in molten zinc (hot-dip galvanization). In 1837, a British patent for flexing steel with ammonium chloride prior to galvanizing was granted. During World War 1, the flame spraying of plastic coatings was commercialised.78

9.2 Coatings

•

• •

• •

•

• • •

575

In the 1940s, a ten year study of various coatings concluded that:79 • Metallized zinc had outperformed all other coatings studied; • Metallized zinc provided secondary (galvanic) protection when the organic top-coating deteriorated or damaged; • Zinc metallization was not economical if the length of the service period was less than 4–5 years; and • The minimum thickness of metallized zinc required was about 4–5 mm. Until the 1950s, thermal sprayed aluminum (TSA) was not widely used due to the formation of rust stains. The development of sealants in the 1950s solved this issue. In 1950, the American Welding Society (AWS) Committee on Thermal Spraying (then known as the Committee on Metallizing) began an extensive study of the corrosion protection of thermally sprayed zinc and aluminum coatings on low carbon steel. More than 4,000 panels were tested over a 20 year period in eight test sites across the United States. Panels were exposed to seawater at tide and below tide levels at two different locations, and in the remaining six locations the panels were exposed to a range of atmospheric conditions, including industrial, salt air, and salt spray environments. The conclusions obtained from this study can be summarized as follows: • Aluminum coatings 75–150 mm (0.003–0.006 in.) both sealed and unsealed provided protection of carbon steel over the 20 year period in seawater as well as in severe marine and industrial environments. • Over the same time period, unsealed zinc coatings required 12 mil (0.3 mm) of thickness in seawater and 9 mil ( 0.2 mm) in marine and industrial atmospheres, whereas 3 to 6 mil (0.07 to 0.15 mm) of sealed zinc was sufficient to provide same extent of protection. • The application of one coat-of-wash primer and one or two coats of aluminum vinyl enhanced the appearance and extended the life of aluminum and zinc coatings. • Overall, aluminum coatings performed better than all the other coatings tested, and they had a lower tendency to develop pits and blisters. In the 1960s, the oxidation of thermal spray coating during application (spraying) was a major problem, but the development of high speed spray pumps overcame this problem. In 1984, the tethers, risers, and flare boom of a tension leg platform (TLP) installed in water 480 feet (146 m) deep in Hutton, North Sea was protected by TSA. The TSA coating was a 99.5% Al flame-sprayed coating with a 1,000 psi (6.9 MPa) adhesion. The coating was sealed with two coats of vinyl sealer on the tethers and a silicone sealer on the risers. Based on the success of this project, operators started specifying TSA as corrosion protection for several North Sea and Gulf of Mexico projects. Between 1987 and 1988, TSA was used for splash zone protection in nine platforms installed in the North Sea. The 8 mil (0.2 mm) thick TSA was further protected with 2 mil (0.05 mm) of polyurethane sealer. In 1989, TSA was used to protect the risers on the Joillet platform installed in the Gulf of Mexico. The largest offshore application of TSA in the 1990s was on the Heidrum TLP, which had a 50 year design life. Metallized coatings have now been used to provide protection in many industries, especially offshore and marine structures. Currently there are three thermal spraying processes: combustion, electric arc, and plasma.

576

CHAPTER 9 Mitigation – External Corrosion

9.2.5a Type Thermal spray coatings are normally either Zn, Al, or 85% Zn–15% Al. Zinc is electronegative in the galvanic series and hence thermally sprayed zinc coating is used as a sacrificial coating; i.e., it provides galvanic protection. On the other hand, thermally sprayed aluminum is a barrier coating. The Al2O3 layer on its surface is tight, adherent, and has good mechanical strength. A zinc and aluminum alloy coating combines the advantages of both sacrificial zinc and protective aluminum. Zinc and aluminum are not miscible in the solid state, but are in the liquid state. Due to its lower atomic weight, a smaller weight-percentage of aluminum produces a larger volume fraction of the aluminum phase. For example, a mixture of 28% by weight of aluminum and 72% by weight of zinc produces an alloy which is 50% aluminum and 50% zinc by volume. The properties of Zn-Al alloy coatings depend on the size, distribution and volume fraction of the zinc and aluminum phases: • • •

•

At above 95% by weight of zinc, the coatings behave much like pure zinc. Coatings containing 5–22% by weight of aluminum (with 78–95% by weight of zinc) combine the best properties of both materials. The optimum performance is found at 85% by weight of zinc and 15% by weight of aluminum. At this weight ratio, the metallized coating contains 30% of volume of aluminum and 70% by volume of zinc. Its microstructure consists of a continuous network of elongated aluminum particles separated by pores filled with a finely divided zinc-rich phase. The improved corrosion resistance, relative to either pure zinc or aluminum, is due to the combination of both the formation of aluminum oxide (self-healing corrosion product) and the presence of zinc-rich phase (sacrificial cathodic protection). This composition is widely used to produce thermal spray coatings. Thermal spray coatings with a composition that is 55% aluminum and 45% of zinc by volume are also used. This alloy mostly consists of an alpha-aluminum phase with an inter-dendritic zinc-rich phase.

TSA coatings of thickness less than 200 mil (5 mm) are porous in nature and are susceptible to water ingress and corrosion. Increasing the thickness (typically to 350 mil (9 mm)) plugs the pores, but thicker coatings have poor adhesion due to differential thermal expansion of substrate and coating. Therefore, typically TSA layers of about 200 to 300 mil (5 to 7.5 mm) mm of thickness are used. To plug the pores, sealants and paints are thermally sprayed on immediately after the TSA. Polyvinyl chloride, polyphenolic resins, polyester resins, polyurethanes, and polyamide epoxies are commonly used as sealants. Thermally sprayed zinc coatings are also sealed and painted to extend their life.

9.2.5b Laboratory performance Standards providing guidelines for evaluating thermally sprayed coatings include: • • •

AWS C2.2, ‘Recommended Practice for Metallizing with Aluminum and Zinc for Protection of Iron and Steel’ AWS C2.25/C2.25M, ‘Specification for Thermal Spray Feedstock Solid and Composite Wire and Ceramic Rods’ CSA G189. ‘Sprayed Metal Coatings for Atmospheric Corrosion Protection’

9.2 Coatings

•

• • •

577

NACE 12/AWS C2.23M/SSPC-CS 23.00. ‘Specification for the Application of Thermal Spray Coatings (Metalizing) of Aluminum, Zinc, and their Alloys and Composites for the Corrosion Protection of Steel’ BS 5493, ‘Code of practice for protective coating of iron and steel structures against corrosion’ SSPC CS 23.00. ‘Specification for the application of thermal spray coatings (metalizing) of aluminum, zinc and their alloys and composites for the corrosion protection of steel’ ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 6: Thermal Spray Aluminum). This standard addresses TSA used as girth weld coatings

9.2.5c Field performance Several investigators have evaluated the performance of thermal spray coating in various environments. Results from some long-term field experiments and experience are summarized in this section. The US Navy exposed two TSA coatings in Port Hueneme Harbor, California and the study found that 3 mil (0.1 mm) unsealed TSA coating performed well, even after 18 years of exposure. The LaQue Center exposed several samples of TSA coatings on steel panels in Kure Beach, North Carolina. The coatings were of different compositions, and of thicknesses between 3 mil (0.08 mm) and 6 mil (0.15 mm). After 34 years of exposure, the TSA coatings performed extremely well in the marine atmosphere, with individual performance of Al-Zn and Al-Mg coatings depending on the application procedure, especially the gun size. The 100% Al coating was least affected by the nature of its application. Another study conducted in marine atmospheres using TSA of various compositions (with Al content between 45 and 70%) determined the time for the first rust to form was 15 years on panels exposed in a severe marine atmosphere, i.e., 80 feet (25 meters) from the ocean, and 25 years on panels exposed in a moderate marine atmosphere, i.e., 820 feet (250 meters) from the ocean. The US Army exposed various metallic coatings with and without polymeric top layers over a period of 20 years at Buzzard’s Bay, Massachusetts and at La Costa Island, Florida. Based on this study, the US Navy approved the use of TSA coatings for naval ships with the following recommendations: a minimum adhesion strength of 13.8 MPa (2,000 psi), a minimum coating thickness of between 10 mil and 15 mil (w0.25 and 0.38 mm), and two coats of a heat-resistant Al sealer for high temperature service (780 C (1436 F)). Studies in Norway found that visible damage had occurred in TSA coatings of 6 mil (0.16 mm) thickness after 15 years, and concluded that a 8 mil (0.2 mm) thick TSA coating would be required for 60 years service. Studies in Russia and Germany also came to similar conclusions. Several inspections of the Hutton platform have been carried out. The potentials of the tether in year one ranged between 980 and 1,000mV (Ag/AgCl), and between 880 and 910 mV (Ag/AgCl) in year eight, indicating continued protection by TSA. One tendon and a production riser were removed for inspection after three years of service. The tendon exhibited blistering while the riser did not. Despite the blisters, the TSA coating was in excellent condition with no measurable reduction in coating thickness or evidence of corrosion damage to the substrate. Visual inspection by video cameras of the splash zone after three years of service revealed no deterioration in coating quality or performance, or any corrosion damage. High-pressure water jetting (4,000 psi (27.6 MPa)) was used to

578

CHAPTER 9 Mitigation – External Corrosion

remove fouling, in order to enable better inspection. This strong mechanical impact did not cause any coating deterioration. After eight years of service, the riser strings were visually surveyed and photographed. No corrosion was detected in the splash zone. One riser string was retrieved due to a work-over of a well after eight years. Coating thickness surveys, around the circumference and along the length of the riser joint measured at or above specified thickness (8 mil (0.2 mm)), indicated no degradation since installation. Adhesion strength was determined by a pull-off method. The adhesion strength between the dolly and the TSA coating was 500 psi (3.5MPa), but the TSA coating adhesion to the steel was better than this value. The typical adhesion strength of the coating during manufacture was of the order of 1,500 to 2,000 psi (10 to 14 MPa). Coating adhesion was also tested using the scribe test, which indicated that it was excellent on this riser. In a few cases, flaking did occur. The steel substrate was examined after the coating was removed by chemical means. The substrate was in pristine condition with the original blast profile still intact. This indicated that the underlying steel was never exposed to the corrosive environment.

9.2.5d State-of-the-art Thermal spray coatings are used with polymeric top-coatings in offshore oil and gas infrastructure to provide external corrosion control. They are popular in such applications due to the difficulty in repairing the infrastructure, and the difficulty of applying traditional external CP. Preliminary studies have also confirmed that the metallic coatings/polymeric coating/cathodic protection combination may be used as three layer protection system (Table 9.29 through 9.31).59

9.2.6 Concrete coatings Concrete coatings are primarily used in offshore pipelines as weight coatings for buoyancy protection. They are also used in onshore pipelines for backfill protection at river crossings, in rocky locations, and Table 9.29 Comparison of Cathodic Disbondment of Polymeric Coatings with and without Thermal Sprayed (48% Zn-52% Al) Metallic Underlayer Coating59 Area of Disbondment (%) Coating

Constant Temperature

Fluctuating Temperature

Potential, V

L0.78

L0.93

L0.78

L0.78

L0.93

L0.78

Break

Yes

Yes

No

Yes

Yes

No

Composite Me/Composite FBE Me/FBE Coal tar Me/Coal tar Urethane Me/Urethane

0.00 0.00 2.25 8.76 60.00 52.50 80.00 8.13

17.00 9.00 75.00 5.63 100.00 40.00 70.00 10.63

n/a 1.50 n/a 33.75 n/a 67.50 n/a 68.75

0.00 5.00 60.00 14.69 50.00 39.81 0.00 9.69

0.00 9.00 40.00 10.94 37.50 14.38 0.00 3.13

0.00 8.00 71.00 24.69 78.75 53.75 0.00 75.63

Me ¼ 48% Zn-52%Al as underlayer

9.2 Coatings

579

Table 9.30 Comparison of Cathodic Protection Current Demand in the Presence and Absence of 48% Zn-52%Al Underlayer Coating59 Cathodic Current Demand, mA Coating

Constant Temperature

Fluctuating Temperature

Potential, V

L0.78

L0.93

L0.78

L0.78

L0.93

L0.78

Break

Yes

Yes

No

Yes

Yes

No

Composite Me/Composite FBE Me/FBE CTE Me/CTE Urethane (Spray) Me/Urethane (Spray)

3.66 0.04 30.83 0.40 13.62 5.40 38.80 4.09

11.48 0.10 13.17 21.16 41.74 0.50 16.48 7.98

0.01 3.33 4.37 0.90 n/a 0.40 0.83 1.28

3.24 0.84 102.52 1.43 1.77 3.30 179.00 1.03

4.19 0.84 165.24 0.96 6.17 2.30 206.50 15.12

n/a 1.95 n/a 3.60 0.64 0.20 n/a 0.35

Me ¼ 48% Zn-52%Al as underlayer

Table 9.31 Comparison of Cathodic Disbondment in the Presence of Various Metallic Under-Layers with Urethane Top-Layer Coating59 Area of Disbondment (%) Coating

Constant Temperature

Fluctuating Temperature

Potential, V

L0.78

L0.93

L0.78

L0.78

L0.93

L0.78

Break

Yes

Yes

No

Yes

Yes

No

No metallic underlayer Zn 85%Zne15%Al 48%Zne52%Al Al

80.00 90.00 83.75 8.13 1.25

70.00 90.00 16.25 10.63 3.13

N/A 3.75 16.25 68.75 40.00

0.00 90.00 80.00 9.69 13.75

0.00 3.75 5.00 3.13 5.00

0.00 90.00 5.00 75.63 76.25

in locations where pipelines are prone to soil movement. Typically the concrete weight coating is applied over an anti-corrosion polymeric coating, and the system is further backed up by cathodic protection. Concrete coatings are not used to a great extent in onshore pipelines; however, combinations of steel, polymeric coatings, and concrete are extensively used in structures such as bridges and buildings in conjunction with cathodic protection. The performance of the concrete coating depends on several factors, including the reliability of the concrete and polymeric coatings; the compatibility between the two (for example proper aggregate size of the concrete coating should be selected so that it does not

580

CHAPTER 9 Mitigation – External Corrosion

damage the polymeric coating); and compatibility between the coatings and CP (when polymeric coating fails the CP current should reach the metal surface, thus protecting it from corrosion). The reliability of the concrete coating depends on two factors: the durability of the concrete itself, and the permeation of water and other species (e.g., chloride ions) through it to reach the polymeric coating. Figure 9.10 describes factors which affect the durability of concrete. These include the temperature cycle, alkali-aggregate reaction, presence of sulfates, flow, and carbonation.80 In cold northern regions, concrete deteriorates more rapidly due to cyclic freezing and thawing, which are not encountered in warmer regions. The silica and carbonates from concrete react chemically with alkalis (e.g., sodium hydroxide and potassium hydroxide) to form alkali gel. The gel has higher affinity towards water, and consequently its volume increases. The increased volume cracks the concrete. The alkali-silica reaction is more common than alkali-carbonate. The calcium hydroxides (hydrated lime), calcium aluminate, and calcium silicate present in concrete chemically react with sulfates (e.g., sodium sulfate, calcium sulfate, and magnesium sulfate) to form calcium sulfates and calcium sulfoaluminates. The products of these reactions expand the volume and consequently deteriorate the concrete. Flow causes erosion of concrete by bringing abrasive materials, e.g., sand,

FIGURE 9.10 Factors Affecting the Durability of Concrete.80 Reproduced with permission from Wiley.

9.2 Coatings

581

gravel, and ice. In marine environments, the effect of flow is significant in the tidal zone due to the erosion caused by high and low tides (Figure 9.10). When CO2 permeates into the concrete it reacts with calcium hydroxide to produce calcium carbonate. Carbon dioxide may also react with silica, alumina, and ferric oxide present in concrete to produce the respective carbonates. This process is known as carbonation, and it reduces the pH of concrete from 13 to as low as 8. Some approaches undertaken to increase the durability of concrete include controlling the water/ cement ratio, controlling the composition, use of sealers, and use of corrosion inhibitors. Reduction of the water content of concrete decreases its permeability. Certain regulations require the water-tocement ratio in concrete to be equal or less than 0.4.81 The composition of concrete may be adjusted by using nonreactive aggregate, low alkali cement, limiting the alkali content of the concrete mixture, and using supplementary cementing materials (e.g., fly ash and silica fume). Sealers are applied or sprayed on top of concrete to prevent or reduce entry of extraneous materials into it. Some commonly used sealers include silane, siloxane, and linseed oil. Corrosion inhibitors (e.g., calcium nitrite) are added to control the penetration of chloride into the coating, and to protect the steel surface.82 Epoxy coatings may be used to control the corrosion of steel inside concrete.

9.2.6a Type Concrete weight coatings are typically composed of ASTM C150 Type II Portland cement with a maximum tricalcium aluminate (C3A) content of 8%. The reason for specifying this low C3A content is to minimize sulfate attack on the concrete weight coating. However, ASTM Type I or EN 197 Type CEM I Portland cements having a C3A content greater than 8% may also be used. In addition, they may be composed of supplementary materials, such as fly ash, ground granulated blast-furnace slag, and silica fume.83

9.2.6b Laboratory performance The performance requirements of polymeric coating, concrete coating, and CP are provided in the following paragraphs: • •

•

ISO 21809, External coatings for buried or submerged pipelines used in pipeline transportation systems, Part 5: External concrete coating ASTM A775: Standard Specification for Epoxy-Coated Steel Reinforcing Bars. (This standard provides criteria to protect rebar steel inside concrete, and may also be useful for evaluating polymeric coatings between pipes, and concrete coatings used in the oil and gas industry) NACE Standard RP0290: Standard Recommended Practice: Impressed Current Cathodic Protection of Reinforcing Steel in Atmospherically Exposed Concrete Structures

9.2.6c Field performance Field experience with concrete coatings in the oil and gas industry is limited, but the infrastructure industry (building and bridges) has long experience in controlling the corrosion of rebar steel in concrete structures, by using polymeric coating and cathodic protection. The sequence of materials in both cases is the same; i.e., steel/polymeric coating/concrete/cathodic protection. Before using knowledge transferred from other industries, one important aspect should be noted. The use of polymeric (anticorrosion) coating has been controversial in the infrastructure industry, with some recommending its use and others recommending against using it; i.e., the use of polymeric coating is an option in the

582

CHAPTER 9 Mitigation – External Corrosion

infrastructure industry. In contrast, the use of polymeric coating is almost mandatory in the oil and gas industry. Some experiences of the infrastructure industry are described in the following paragraphs. Eighty one bridges in Iowa were surveyed after being in service for 20 years.84 The survey found that the loss of adhesion of epoxy coatings on concrete was higher in locations where concrete had cracked than in locations where it had not cracked. Moisture and higher chloride concentrations at the cracked locations decreased the bond between the epoxy coating and the steel. However, the survey found little corrosion in the cracked locations. Another survey on a bridge in Virginia found that the epoxy coating disbonded from concrete within four years and the rebar beneath it had corroded. The corrosion products so formed distressed the concrete. Yet another survey conducted in 1990s indicated that the substructures of several bridges in Florida experienced severe corrosion.84 The steel rebars of the structures were protected by epoxy coatings. These were defective and had disbonded from the concrete, mainly due to poor coating quality, poor concrete quality, and poor construction practices during construction. Another survey conducted on a bridge in Georgia found a loss of adhesion of epoxy coatings from concrete and from steel, but no steel corrosion beneath the disbonded coating. Many failures were attributed to improper quality control during construction, especially the pouring of concrete on top of the polymeric coating. This survey recommended improvements to this procedure, and quality control measures to be taken during constructing infrastructure. Yet another survey on a bridge in North Carolina found rebar corrosion in locations where the epoxy coating had defects (breaks and pin holes). The following conclusions may be drawn from the experience from infrastructure industry, with respect to using concrete coatings in the oil and gas industry. The products of steel corrosion may distress concrete coatings. When the concrete coating is properly formulated and applied on polymeric coating, no disbonding of the polymeric coating from either steel or concrete occurs. A properly applied epoxy coating can protect the steel from corrosive environments containing chloride ions at up to 0.08 weight percentage. Loss of adhesion of coating adhesion may not necessarily lead to corrosion, as long as the CP current reaches the steel surface through the concrete and polymeric coatings.

9.2.6d State-of-the-art Concrete coatings are used as weight coatings in offshore oil and gas pipelines to overcome buoyancy and to onshore pipelines to reduce pipe movement. Concrete coatings that are fully bonded on to pipeline are also used as mechanical protection in rough terrain.

9.3 Cathodic protection The primary objective of the various coatings discussed in section 9.2 is to prevent the environment or electrolyte that causes corrosion from contacting the metal surface. In order for a coating to meet this objective, it should: remain bonded onto the surface; electrically isolate the external surface of the infrastructure from the environment; have sufficient adhesion to effectively resist under film migration of moisture; be sufficiently ductile to resist cracking; have sufficient strength or otherwise be protected to resist damage due to handling, storage (e.g., UV radiation), and installation during construction; resist deterioration due to the environment (e.g., soil stress, chemicals, and microbial species) and to the temperature variation during operation (i.e., it should not break or disbond); and maintain constant electrical resistivity over time.

9.3 Cathodic protection

583

Table 9.32 Typical Range of Current Required to Effectively Apply Cathodic Protection Coating Resistance, Ohms/Square foot

Cathodic Protection Current, Amperes)

Perfect coating)) 5,000,000 1,000,000 500,000 100,000 50,000 25,000 10,000 No coating

0.000058 0.0298 0.1491 0.2982 1.491 2.982 5.964 14.91 500

) To apply 1 mA/ft2 of current to protect a 36-in. diameter pipeline of 10 miles in length in a soil with average resistivity of 1 x 103 ohm-cm )) A break-free coating with resistivity of 1 x 1013 ohm-cm

No coating is available which can meet all of the above performance criteria for the entire duration of its life. In practice, coatings undergo different forms of deterioration (see section 10.2.1) at different rates (sections 10.2.3 and 10.2.4). If the locations where coating has failed become anodic (see section 5.2 for the concept of ASME), corrosion occurs. To prevent this, cathodic protection (CP) is applied. CP controls the corrosion of a metal by converting its surface into a cathode. This is achieved by moving the potential of the metal surface in the negative direction by using an external current source. Both coating and CP work together; i.e., one cannot be effective without the other in controlling external corrosion of underground oil and gas infrastructures. Using only the coating without CP increases the probability that localized corrosion will occur in those locations where the coating fails. Using only CP without a coating increases the amount of current required to move the potential of metal surface in the negative direction. Table 9.32 illustrates how coating and CP can be effective and economical in protecting a metal from corrosion.85

9.3.1 Principle As discussed in section 5.2, four elements (anode, cathode, metallic conductor, and electrolytic conductor) are required for corrosion to take place. Of these, the anode, cathode, and metallic conductor are present in the metal itself. Therefore when a metal comes in contact with an electrolyte, corrosion takes place. The basic principle of cathodic protection is to remove all anodic areas of the metal or structure of interest so that it does not corrode. At the anodic sites (ref. Eqn. 5.1), metal ions leave the metal surface and dissolve in the electrolyte; i.e., at the anodic sites the current flows from the metal surface to the electrolyte. This process is corrosion. At the cathodic sites, the metal ions (ref. Eqn. 5.2) or some other ions (e.g., hydrogen (Eqn. 5.3) or oxygen (Eqn. 5.4)) leave the electrolyte and return to the metal; i.e., at the cathodic sites the current flows from the electrolyte to metal. This process accompanies the corrosion reaction.

584

CHAPTER 9 Mitigation – External Corrosion

Cathodic protection forces all surfaces of the metal of interest to become cathodic, and another metal becomes the anode; i.e., another metal is sacrificed. The metal that is sacrificed undergoes corrosion, hence this metal is often known as the sacrificial anode. Thus, application of cathodic protection does not eliminate corrosion, but transfers it from the structure of importance to another less important metal. Figure 9.11 illustrates the principle of cathodic protection using a section of a pipeline as the structure to be protected.86 Before implementing cathodic protection, both anodic and cathodic reactions take place on the surface of the pipeline. By installing an anode (also known as ground bed) and connecting it to the pipeline through a source of current, all anodic reactions are forced to take place on the ground bed and all cathodic reactions are forced to take place on the pipeline. The amount of current required to convert a large structure such as a pipeline is huge, hence a large anodic surface is required. Such an approach is not economical. For this reason, most of the surface of the structure is covered with non-conducting coatings to decrease the area to be converted into a cathode. The larger the area protected by the coating, the smaller the amount of current needed to supply cathodic protection; consequently smaller the amount of anode needed. Figure 9.11 illustrates this concept. To apply CP in practice the following questions should be answered. What is the amount of current required to properly protect a given area of the structure? What is the source of that current? What materials are required, and how will it be ensured that the entire structure is completely protected?

9.3.2 Amount of current The amount of current required to protect the entire surface of a structure is huge, that this is uneconomical; as a result, the surface is protected with non-conducting (high-resistance) coatings. These coatings however are not perfect and they do not cover 100% of the surface for its entire service life. In general, it is assumed that the coatings cover about 95% of the surface when they are installed, and that this area progressively decreases during service life. The extent of this decrease depends on several factors, including the type of coating, environment, and service history. Section 10.2.4 provides a method for estimating the coating deterioration rate. The next question is to determine the amount of current required to protect those areas of the structure not protected by coatings. Recollect Figure 5.3 which explains how the system moves from the redox potentials of zinc and hydrogen towards the corrosion potential. Figure 9.12 presents the same concept using iron as its example.87,88 When an iron electrode is coupled with an oxygen electrode, the redox potential (Eequal) of iron moves to the corrosion potential, so that: • • • • •

the the the the the

corrosion potential is more positive than the redox potential of iron corrosion potential is more negative than the redox potential of oxygen current at the redox potential of oxygen is IC current at the redox potential of iron is IA current at the corrosion potential is Icorr.

From this illustration, the amount of current (Ireq) ideally required to cathodically protect iron can be calculated: Ireq ¼ IC

IA

(9.5)

9.3 Cathodic protection

585

FIGURE 9.11 The Principle of Applying Cathodic Protection.86 (A) A freely corroding structure before applying cathodic protection. Note: both anodic and cathodic reactions take place on its surface. (B) the structure after applying cathodic protection. note: only the cathodic reaction takes place on its surface and the anodic reaction takes place on the surface of anode. (C) the structure after applying coating and cathodic protection. note: the area of the pipeline where cathodic reaction takes place has decreased. Reproduced with permission from NACE International.

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CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.12 Determination of the Amount of Current Required to Apply Cathodic Protection.87 Reproduced with permission from NACE International.

When current is forced onto the iron surface, its potential moves from Ecorr to a potential that is more negative; i.e., it moves in the active direction. In other words, the amount of current (Ireq) required to cathodically protect a metal is the amount of current required to force a metal to move from its corrosion potential to its redox potential. Normally, current density (ireq), rather than current is used; current density being the amount of current per unit area. Thus: ireq ¼ iC

iA

(9.6)

where ic, and ia are current densities at the redox potential of cathode (e.g., hydrogen), and at the redox potential of anode (e.g., iron) respectively. The total current (Ireq) required to cathodically protect the surfaces of a structure which is not protected by coatings is then (Eqn. 9.7): Ireq ¼ A:UA :ireq

(9.7)

9.3 Cathodic protection

587

Table 9.33 Typical Current Requirements for Cathodic Protection of Bare Steel Environment

Current Requirement (mA/m2)

Neutral soil Well aerate natural soil High acid soil Soil supporting sulfate reducing bacteria Heated soil Stationary fresh water Moving oxygenated fresh water Seawater Cold and Arctic seawater

5 to 16 22 to 32 32 to 160 65 to 450 32 to 270 11 to 65 54 to 160 32 to 110 160 to 430

where Ireq is the total current required to cathodically protect the uncoated structure (in mA), A is the surface area of the structure (in m2), UA is the percentage area not protected by coatings (%), and ireq is the current required per unit area to cathodically protect the uncoated structure (in mA/m2). In reality CP may not be applied to move the potential all the way to the redox potential of iron, but to a potential sufficiently negative (as indicated as Ecp). Consequently the current required is also reduced to Icp. In the absence of any other method for determining current requirements, the values presented in Table 9.33 may be used.

9.3.3 Current source The current required to apply cathodic protection comes from several sources including sacrificial anodes, impressed current, batteries, engine generators, thermoelectric generators, thermo-generators, wind-powered generators, gas turbines, fuel cells, and solar cells. Of these, sacrificial anode and impressed current are most popular and best established.

9.3.3a Sacrificial anode Section 5.2 discusses galvanic series and electromotive force series. If a metal that is towards the active (i.e., negative) end of the series is connected with another metal which is towards the noble (i.e., positive) end of the series, then the more active metal undergoes anodic oxidation (i.e., corrosion) preferentially, and the other electrode undergoes cathodic reduction. The active metal sacrifices itself to protect the other metal. In order for a sacrificial anode to protect the structure, both should be electrically connected to one another and also be in contact with the same electrically conducting environment. Cathodic protection is applied using sacrificial anodes when the protective current required is less than 4 to 5A and the resistivity of the electrolyte (or environment) is typically below 10,000 ohm-cm. Magnesium, zinc, and aluminum are active metals and are frequently used as sacrificial anodes. Typically, zinc anodes are used when the soil resistivity is below 1,500 ohm-cm, magnesium anodes are used when the soil resistivity is between 1,500 to 10,000 ohm-cm, and aluminum anodes are used for offshore applications. The properties used to characterize sacrificial anodes are: driving potential, current output, cathodic protection circuit resistance, theoretical energy output, actual energy output, current efficiency, utilization factor, and anode life. Table 9.34 presents typical values for some of these properties.

588

Material Zinc, Type 1 Zinc, Type 2 Magnesium H-1 alloy Magnesium high potential Aluminum-ZincMercury alloy Aluminum-ZincIndium alloy a

Specification of Materials Used as Anodes ASTM B418, Type I ASTM B418, Type II

Driving potentiala,b

Theoretical Energy Output (A-h/kg)

Actual Energy Output (A-h/kg)

Current Efficiency, %

Rate of Consumption (kg/A-year)

0.20

860

781

90

11

1.06

0.25

816

730

90

12

1.10

0.60c

2,205

25 to 58

6.8 to 16

0.85c

2,205

45 to 54

7.3 to 8.3

0.20

2,977

551 to 1,279 992 to 1,191 2,822

95

3.1

1.40 to 1.60 1.70 to 1.80 1.06

0.25

2,977

2,591

87

3.3

1.11

To polarize carbon steel to 0.85 V vs, CCS When calculating the anode output the absolute values of potential are used (mathematically the values should be negative) Due to anodic polarization anode output is not exactly as calculated by Eqn. 9.6

b c

Corrosion Potential, V vs CCS

CHAPTER 9 Mitigation – External Corrosion

Table 9.34 Characteristics of Materials Typically used as Sacrificial Anodes for Applying Cathodic Protection

9.3 Cathodic protection

589

i. Driving potential (DVDP) This is the potential between the anode (VA) and the potential to which the cathodically protected metal is shifted (VCPS) (Eqn. 9.8): DVDP ¼ VA

VCPS

(9.8)

From Table 9.34 it is obvious that the driving force of magnesium anodes is higher than those of zinc anodes.

ii. Current output (Iout.a) The current output of the anodic material depends on the driving potential and the resistance between the anode and the structure to be protected (cathode) (Eqn. 9.9): Iout:a ¼

DVDP :1; 000 RT

(9.9)

where Iout.aA is the current in milliamperes, DVDP is the driving potential, and RT is the resistance between anode and cathode, commonly known as the cathodic protection circuit resistance.

iii. Cathodic protection circuit resistance (RT) There is a resistance to current flow between the anode and the cathode. This resistance is known as the cathodic protection circuit resistance, RT and it is the sum of several resistances, as defined in Eqn. 9.10: RT ¼ Ra þ Rc þ Rw

(9.10)

where Ra is the resistance between the anode and environment (ground or seawater or electrolyte), Rc is the resistance between the cathode and the environment, and Rw is the resistance of the metal wire connecting the cathode and anode. The resistance between the anode and the environment depends on the position of the anode (vertical or horizontal), and on whether single or multiple anodes are used (Eqn. 9.11).90,91 R a ¼ Rv ¼ R h ¼ RN

(9.11)

where Rv is the resistance between a vertical anode and ground (Eqn. 9.12), Rh is the resistance between a horizontal anode and ground (Eqn. 9.13), and RN is the resistance between group anodes and ground (Eqn. 9.14). For a single anode that is vertically placed in the ground, the resistance between it and the ground is given by Eqn. 9.12:
 rsoil 8LA ln 1 (9.12) Rv ¼ 2pLA dA where rsoil is the soil resistivity in ohm centimeters (U.com), LA is the length of anode in centimeters (cm), and dA is the diameter of the anode in centimeters.

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CHAPTER 9 Mitigation – External Corrosion

For a single anode that is horizontally placed in the ground, the resistance between it and the ground is given by Eqn. 9.13: qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 0 2 31 2 2 2 ð2hA Þ2 þ L2A rsoil @ 44LA þ 4L ð2hA Þ þ LA 2hA ln (9.13) 15 A þ Rh ¼ dA 2pLA LA 2dA hA where hA is the distance between the surface and the center of the anode, in centimeters. When more than one anode is used, the current outputs of individual anodes reduce due to mutual interference resistance; this resistance decreases as the spacing between the anodes increases. For a group of anodes that are vertically placed in the ground, the resistance between them and the ground is given by Eqn. 9.14:
 rsoil 8LA 2LA ln (9.14) 1þ :ln 0:656NA RN ¼ 2pNA LA dA SAC:CP where NA is the number of anodes and SAC.CP is the center to center spacing between anodes in centimeters. To reduce the resistance between the anode and the environment, anodes are often placed in backfill materials. Table 9.35 presents the chemical composition of a typical backfill material.92,93 These materials absorb and retain water, thereby reducing the resistance between the anode and the environment. In addition, backfill materials ensure uniform current distribution from the anode, and hence prolong its life. Similarly to the resistance between anode and the earth, there is a resistance between cathode (i.e., the structure to be protected) and the earth in the current path (Rc). In many instances this resistance is small when compared to Ra and is therefore ignored. In addition to the resistances (Ra and Rc) between electrodes (anode and cathode) and the earth, the resistance of the metallic connector (Rw) joining the anode and cathode is also important. This resistance depends on its length and diameter. Table 9.36 presents typical resistances (Rw) of copper cables that are often used to connect anodes and cathodes.

iv. Theoretical energy output The energy output is a measure of the electrochemical equivalent of the energy stored in a metal. It is a measure of the current discharged per hour per unit mass of metal. One ampere-hour means that one Table 9.35 Typical Backfill Material to Cover Sacrificial Zinc and Magnesium Anodes Composition of Backfill, % Typically Used with Zinc Magnesium in soil with high resistivity

Hydrated Gypsum (CaSO4)

Bentonite Clay

Sodium Sulfate

Resistivity, ohm-cm

50 75

50 20

5

250 50

9.3 Cathodic protection

591

Table 9.36 Typical Resistances Metallic Cables used in the Cathodic Protection System93 Size of Copper Wire AWG)

Diameter (mil)

Diameter (mm)

Resistance at 20oC, ohm/ meter

14 12 10 8 6 4 3 2 1 1/0 2/0 3/0 4/0

64 80 102 129 162 204 230 258 289 325 365 410 460

1.6 2.1 2.6 3.3 4.1 5.2 5.8 6.5 7.3 8.3 9.3 10.4 11.7

8.4650 5.3152 3.3466 2.0998 1.3222 0.8334 0.6595 0.5217 0.4134 0.3281 0.2608 0.2070 0.1641

) American Wire Gauge (AWG) is a standardized wire gauge predominantly used in USA and Canada for electrically conducting wire

ampere of current flows for one hour and is equivalent to 0.5 ampere of current flowing for two hours, or to two ampere of current flowing for 30 minutes. The theoretical energy output of pure zinc is 372 ampere-hours per pound. This means that one pound of zinc will discharge one ampere of current continuously for 372 hours. If the amount of current discharged increases, the duration decreases, and vice versa. For example, one pound of zinc discharging 10 amperes of current will be consumed within 37.2 hours. On the other hand, one pound of zinc discharging 0.1 ampere of current will last for 3,720 hours.

v. Actual energy output In order for the anode material to be 100% efficient, all its surfaces should function as an anode, and all cathodic sites should reside on the structure being protected. This seldom occurs. A small portion of the anodic material itself undergoes reduction reaction, i.e., acts as cathode. Consequently the actual energy output from an anode material is less than the theoretical energy output.

vi. Current efficiency The current efficiency is the ratio of the actual energy output that can be used for cathodic protection to the theoretical energy output.

vii. Utilization factor The utilization factor is a measure of the percentage of the anodic material which can be used for cathodic protection purposes. For example, a utilization factor of 90% means that once 90% of the material is consumed, it can no longer be used as anode. The resistance to earth of the remaining 10% of the material is so high that there is very little or no current output from it.

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CHAPTER 9 Mitigation – External Corrosion

viii. Anode life The life of anode is the length of time for which a material can be used as sacrificial anode (Eqn. 9.15): tanode ¼

Ith:a ::ma :Ieff :a :UFa tfunc Iout:a

(9.15)

where tanode is the anode life in years, Ith.a is the theoretical output in A-h/kg, ma is the anode mass in kilograms, Ieff.a is the current efficiency, UFa is the utilization factor, tfunc. is hours per year (8,766), and Iout.a is the anode output in amperes.

9.3.3b Impressed current – power source94–96 The maximum driving potential (DVDP, Eqn. 9.8) from using a sacrificial anode is 1V. Further, the current output of sacrificial anodes is typically up to 5 mA. For these reasons sacrificial anodes cannot be used to apply CP on a large structure. When the current required to apply CP exceeds 5 mA, the impressed current method is typically used. Table 9.37 compares CP using the sacrificial anode and impressed current methods.97 Figure 9.13 presents a typical system used to apply cathodic protection by the impressed current method. All the basic elements (anode, groundbed, and cathode, i.e., structure) used in the sacrificial anode method are also required to apply CP by the impressed current method. The main difference is the source of electrical current. An external power source (commonly the electric utility system) is used for this. The positive terminal of the external power source is connected to the anode, and the negative terminal to the structure to be protected (the cathode). Another device, known as a rectifier, regulates the current flow between the power source and the cathodic protection system. The rectifier

Table 9.37 Comparison of Cathodic Protection with Sacrificial Anode and with Impressed Current97 Characteristics

Sacrificial Anode Cathodic Protection

Impressed Current Cathodic Protection

Power source

Anode

Maintenance Installation

Relatively little Relatively easy

Inspection Record keeping Adjustment of amount of current Current output Cost of replacing spent anodes Nature of coating

Relatively less Relatively less Not possible without resistors in the circuit Limited (typically less than 5 mA) High Need good coating

External; but constant power is required. Relatively high Relatively sophisticated; experienced and certified electrical personnel required. Relatively more Relatively more Yes

Electrical isolation of structure

Needed

Cathodic interference

Low

High Relatively low Can be used with poor coating or without coating Can be used without electrical isolation of structure Possible

9.3 Cathodic protection

593

FIGURE 9.13 Schematic Diagram to Apply Cathodic Protection by Impressed Current.89,98 Reproduced with permission from Wiley.

does two things: it converts (rectifies) the alternating current from the power source into direct current, and it adjusts (normally lowers) the voltage of the direct current to a value that is appropriate for applying CP. The current from the external source is alternating current (AC). In an AC system the current flow changes direction at regular intervals. For example, for a 60 cycle AC power source, the direction of current changes 120 times per second. Figure 9.14 presents a basic rectifier unit and shows how the AC current flows through it. The current can enter the bridge from the transformer through connections 1 or 2. When the current enters through: •

•

Connection (1) of the transformer it passes through leg (c) of the bridge. The current then passes through the external circuit (i.e., ground bed and structure being protected) before returning to connection (2) through leg (b). Connection (2) of the transformer it passes through leg (d) of the bridge. The current then passes through the external circuit before returning to connection (1) through leg (a).

For 60 cycle AC current passing through a rectifier, the above two processes repeat 120 times every second. Irrespective of the direction of the AC current entering the rectifier, it flows out of the rectifier in only one direction; i.e., the current output of the rectifier is direct current (DC). When a rectifier converts an AC to DC some power is lost. The extent of this loss determines its efficiency (Eqn. 9.16): Receff ¼

Vdc :Idc :100 Wac

(9.16)

where Receff is the efficiency of the rectifier, Wac AC power in Watts, Vdc is the DC potential in volts and Idc is the DC current in amperes. The power lost in the rectifier appears as heat; therefore rectifier units are equipped with coolers.

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CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.14 Rectifier Unit for Impressed Current Cathodic Protection System.86,99 (A, B, and C are transformer units, D is a bridge to direct the flow of current, E is an ammeter, F is the voltmeter, G is the ground bed, H is the structure to be protected, a, b, c, and d are the legs of bridge D, and 1 and 2 are connectors). Reproduced with permission from NACE International.

Any metallic material can be used as an anode in the impressed current method, even one that is cathodic to the structure to be protected. The impressed current forces the anodic material to corrode or to undergo other anodic reactions (see Eqns. 9.17 and 9.18) irrespective of its natural tendency. For this reason, the connections to the rectifier must be properly made. The positive terminal of the rectifier must be connected to the anode and the negative terminal to the structure; otherwise the impressed current will corrode the structure instead of protecting it.

9.3 Cathodic protection

595

Anodic materials corrode and hence should be replaced periodically. The rate at which they disappear is known as the dissipation rate. The dissipation rate of a material decreases if it undergoes other oxidation (anodic) reaction, rather than the corrosion reaction. Such common reactions are oxygen evolution (Eqn. 9.17) and chloride evolution (Eqn. 9.18): 4OH / O2 þ 2H2 O þ 4e

(9.17)

4CI / CI2 þ 2H2 O þ 4e

(9.18)

Commonly used anode materials include cast iron (with 14.5% silicon and chromium), carbon, graphite, sintered iron oxide, lead-silver alloys, platinum, platinized titanium, and niobium. Their dissipation rate is 0.5 kg/A-year.96 On the other hand, the dissipation rate of iron is 9.1 kg/A-year. Therefore, when scrap steel pipe, rail, rod, or other similar iron or steel materials are used as anode materials, large volumes are required. The amount of anode required to apply an impressed current is calculated as follows (Eqn. 9.19):97 ma ¼ Dt :Ireq :tlife

(9.19)

where Dt is the dissipation rate in kg/A-year (normally assumed to be 1 kg/A-year in the design stage), Ireq is calculated using Eqn. 9.7 or using Table 9.33, and tlife is the anticipated life of the infrastructure to be protected, in years. The rectifier voltage (Vrectifier) depends on required current and total resistance (Eqn. 9.20): Vrectifier ¼

Ireq Rt

(9.20)

where Rt is the total resistance and is calculated using Eqn. 9.10. But calculation of Rw for impressed current method involves three resistances (Eqn. 9.21): Rw ¼ Rð

Þ

þ RðþÞ þ Rgb

(9.21)

where R( ) is the resistance of the cable connected to the negative terminal, R(þ) is the resistance of cable connected to the positive terminal, and Rgb is the resistance of half the length of the anode portion of the groundbed. Normally distributed anodes (see Figure 9.15) are used in the groundbed and current flowing through the cable connecting the anodes drops at each anode encountered. Therefore the effective resistance of the cable in the groundbed is normally taken as half the resistance of the total length. Table 9.36 presents values of typical cables.

9.3.3c Impressed current – engine generator An engine generator may be used to produce electricity required for the impressed current cathodic protection system when an AC power line is not available, or when a sacrificial anode system will not produce a current adequate to apply cathodic protection. An engine generator can produce DC directly, but it is normally used to energize an AC generator (commonly known as alternator) and then a rectifier is used to convert the AC to DC. This two-step process is more efficient and economic for the controlled production of a wide range of DC than producing it directly from an engine generator. The cost of installing and operating this large block of engine generators is relatively high. The natural gas or oil required to operate the engine generator may be drawn directly from the oil and gas pipelines or may be transported to it periodically.

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CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.15 Schematic Diagram of Distributed Anodes.100 Reproduced with permission from Wiley.

9.3.3d Impressed current – thermo-generator In remote locations, the DC for the cathodic protection system may be produced by a closed cycle vapor thermo-generator (CCVTG). Commercial thermo-generators which generate up to 5,000 W and 100 V of power are available. The thermo-generator powers an alternator using a turbine. The turbine wheel is rotated by the vaporization of an organic liquid and subsequent expansion of the gas. The organic liquid is vaporized in a burner using hydrocarbon fuels. The organic vapor is cooled, condensed, and pumped back to the burner. These processes are repeated to power the alternator. The alternator produces AC which is then converted into DC by a rectifier, and this is used to apply cathodic protection.

9.3.3e Impressed current – thermoelectric generator A thermoelectric generator produces DC. Commercial thermoelectric generators producing up to 600 W and 48 V of power are available. Higher power outputs can be achieved by stacking several of them. In practice, the power required for cathodic protection is calculated, and the number of thermoelectric generators is then derived. The principle of a thermoelectric generator is same as that of a thermocouple, which is commonly used to monitor temperature. In both a thermocouple and a thermoelectric generator, the electricity is produced by heating the junction between certain dissimilar metals. In a thermocouple, the electricity so produced is read by a calibrated voltmeter to display the temperature. Each thermocouple generates up to 90 mV of potential. In a thermoelectric generator,

9.3 Cathodic protection

597

several thermocouples are connected in series to provide the required voltage output for the CP system. To generate the electricity, two dissimilar metal junctions are maintained at 1000 F (538 C) (hot) and 325 F (163 C) (cold). The heat required for this purpose is produced by burning hydrocarbons. The junctions are immersed in a special fluid in sealed container.

9.3.3f Impressed current – solar electric power generator Solar power systems are available to produce power up to 1000 W, 20 V, and 50 A. Certain materials generate an electric charge when sunlight is incident on them. This principle is used to produce power. Solar power systems only function in the presence of sunlight, so they are combined with storage batteries to produce continuous power. The system can normally provide 10 A of current to a rectifier for two weeks without recharging.

9.3.3g Impressed current – battery Batteries may be used to power cathodic protection systems in isolated locations with no electricity facilities, or where the sacrificial anode method is not adequate to provide the required current. Batteries are frequently used to apply cathodic protection to a well-coated pipeline crossing a river. This method is not effective if current drain is high, i.e., on a bare or poorly coated structure.

9.3.3h Impressed current – wind Similar to solar energy, wind power can also be used to operate a cathodic protection system. They may be used in remote locations where there is no other source of power, and where the wind velocity is high and steady. The power output from a wind generator is not constant; hence, such a system is coupled with a storage battery to provide continuous power to the cathodic protection system.

9.3.3i Impressed current – gas turbine The operation of a gas turbine is only efficient and economical if there is a large pressure drop. Examples where such large pressure drop occurs include gas transmission pipelines, gas production fields, and wellheads. In these situations, gas flows through a bypass loop to operate the turbine and returns back to the mainline. The turbine in turn energizes a DC generator which provides the current to apply cathodic protection. Systems where large pressure drop occur are not common. For this reason this mode of impressed current system is not common.

9.3.3j Impressed current – fuel cell In its simplest form, a fuel cell produces DC current and water when two gases are forced through a sandwich of two porous electrodes. The gases normally used are oxygen and hydrogen, but attempts are also being made to use natural gas. However, fuel cell technology is not yet mature enough to provide a reliable impressed current source for cathodic protection.

9.3.4 Potential criteria101 As discussed in section 9.3.1, the basic principle of CP is to move the potential of the structure to the open circuit potential of its anode, so that all anodic sites of the structure become cathodic (i.e., sufficient current should be applied to move the potential from corrosion potential (Ecorr) to Ecp in Figure 9.12). Although simple in theory, when applied in real life several issues need to be addressed. In fact, one of the most debated issues in the oil and gas industry is the criteria used to determine

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CHAPTER 9 Mitigation – External Corrosion

whether the structure is adequately protected by cathodic protection. Some widely used criteria are discussed in the following paragraphs.

9.3.4a

850 mV ON

This criterion applies only to carbon steel and cast iron. A carbon steel or cast iron structure is cathodically protected when its potential is at least 850 mV vs. a copper-copper sulfate (CCS) reference electrode. This criterion was originally established in the 1920s, and was based on extensive study of the corrosion potentials of carbon steel and cast iron. Table 9.38 presents typical corrosion potentials of cast iron and mild steel as measured in various soils at ambient temperature throughout North America.102 From the data it is obvious that maintaining the potential of carbon steel and cast iron at 850 mV vs. CCS would considerably reduce the corrosion rate (by decreasing the anodic areas on the metal). The table shows that when the potential of steel is 850 mV, the surface would be at least 50 mV cathodic (negative) to the corrosion potential. This criterion was adopted by the oil and gas industry, several standards developing organizations, and several companies. The advantages of this criterion include: only one potential needs to be measured to ensure that CP is properly applied; the potential is measured with the CP current turned on (therefore the current can be adjusted until the potential is reached); the procedure is relatively easy for the field technician to carry out; and historical data is not required. It is important to ensure that the potential measured is free from solution resistance (IR drop). The potential measurement is based on Ohm’s law (Eqn. 9.22): E ¼ IR

(9.22)

where E is the potential, I is the current, and R is the resistance. For the 850 mV vs. CCS cathodic protection criterion to be valid, the potential measured should only be due to the potential between the structure and the environment. However, there may be many elements present in between the structure and the reference electrode whose resistance will affect the measured potential. These elements could include the structure-coating interface (as long as this interface is intact, cathodic protection is not necessary); coating resistance (this resistance is important if there is structure-environment exists beneath coating, i.e., when the coating disbonds); soil resistance; and soil-reference electrode interface.

Table 9.38 Typical Corrosion Potentials of Iron and Steel in Natural Soils and Water102

Metal

Condition

Mild steel Mild steel Cast iron Cast iron Steel

Clean and shiny Rusted Not graphitized High silicon content Presence of mill scale

Corrosion Potential, mV Vs. Copper-copper Sulphate (CCS) Reference Electrode 500 to 200 to 500 200 200

800 500

9.3 Cathodic protection

599

Thus the measured potential (Vmeasured) is (Eqn. 9.23): Vmeasured ¼ VSE þ VSC þ ICoat RCoat þ IS RS þ VSR

(9.23)

where: • • •

• •

•

• •

Vmeasured is the measured potential between the structure and reference electrode. VSE is the potential between the structure and the environment. (This is the only potential of interest with respect to CP and this potential should be 850 mV vs. CCS). VSC is the potential between the structure and the coating: • if there is no coating, this potential does not exist. • if the coating is intact there is no such potential, i.e., this parameter can be ignored, and • if the coating has disbonded and the coating is in between the structure and the reference electrode, this potential is of great significance. In this situation the value of RCoating is important. ICoat is the current flowing across the coating; ICoatRCoat is commonly known as the IRcoat drop across the coating. RCoat is the resistance of the coating: • if there is no coating, this value is ignored. • if the coating is intact with high RCoat value (see Table 9.32), CP and hence potential measurement are not needed at all, and • if the coating has disbonded with high RCoat value it may electrically shield the structure from cathodic protection. Under this condition: • Vmeasured has no relationship with VSE. • VSE ¼ VSC; depending on the value of VSC corrosion and SCC may take place, no matter how much of CP current is applied and what is measured as Vmeasured. RS is the resistance of environment (soil) or solution resistance. The influence of RS may be avoided by moving the reference electrode as close as possible to the structure. By this procedure reasonable estimate of VSE can be obtained from Vmeasured. IS is the current flowing across soil; IRSoil is commonly known as IR drop across the soil. VSR is the potential between the soil and the reference electrode. Normally this potential is low and is ignored, as there is no current flow through the reference electrode.

Use of this criterion should be avoided at river or road crossings, where the reference electrode cannot be placed closer to the structure. For poorly coated structures, i.e., coating with several breaks providing current paths, use of this criterion may lead to the application of prohibitively large amounts of current. The use of cathodic protection and potential measurement should be questioned when applied to structures with disbonded coatings with high RCoat (see Table 9.33). Stray current interferes with the potential measurement (section 9.3.7 discusses details of stray current and its control). The stray current source may be constant or dynamic. A constant stray current source should be switched off while making the potential measurement. To overcome dynamic stray current (e.g., from a railway transit system), potential measurements should be taken for a duration of 24 hours, i.e., covering the period when the dynamic current source is both active and inactive. For example, a stable potential can be recorded in the early hours of the day or late in the night when transit system is not operating. Telluric current (see section 9.3.7c for more details) interferes with the potential measurement.

600

CHAPTER 9 Mitigation – External Corrosion

Repeated measurement at the same location over a long period of time (at least two consecutive days) may help to delineate its effect.

9.3.4b

950 mV ON

Under certain conditions, the corrosion potential of cast iron and carbon steel is more negative than 850 mV vs. CCS. In these situations, the CP current is applied until the potential of the structure reaches 950 mV vs. CCS. This criterion is commonly used when the infrastructure is in microbiologically active soil (microbes can depolarize the electrode potential in the negative direction) or when the operating temperature increases (typically above 50 C (122 F)). In general, reaction rates increase with temperature (under ideal conditions, the reaction rate doubles for every 10 C increase in temperature). Consequently, the corrosion potential shifts in the negative direction as the temperature increases. Before this criterion is used, the structure is thoroughly surveyed to ensure that the corrosion potential is indeed more negative than 850 mV vs. CCS. (Section 11.3 discusses several survey techniques.) When using the 950 mV ON criterion, it should be noted that the current consumption is higher than that required to meet the 850 mV ON criterion, so an adequate power supply should be designed and implemented. On the other hand, overprotection, i.e., application of potential beyond that which is required, should be avoided. Normal industry practice is to avoid potentials more negative than 1050 to 1100 mV cs. CCS since steel may be susceptible to hydrogen damage under such conditions (section 5.18 presents more information on the hydrogen effect).

9.3.4c

850 mV OFF

Vmeasured measured with CP current on (i.e., as per 850 mV ON criterion) includes several other parameters as defined by Eqn. 9.23. When the CP is turned off, the potential contributions due to the IR components disappear immediately; consequently Eqn.9.23 reduces to Eqn. 9.24: Vmeasured ¼ VSE þ VSC þ VSR

(9.24)

The disappearance of the IR components is rather quick once the CP current is turned off, hence Vmeasured is approximately equal to VSE, and the potential slowly drifts to the corrosion potential. During the 850 mV OFF measurement, the cathodic current is switched off and the potential is measured instantaneously. For this reason, this potential is sometimes known as the instant OFF potential measurement. If the measurements are continued for longer, the potential slowly drifts to the corrosion potential. Figure 9.16 presents a typical potential response of a structure as a function of time after the cathodic protection current source has been switched off. The difference between the potential with current ON and immediately after the current is turned OFF is a measure of the IR drop, and the difference between the OFF potential and the corrosion potential is a measure of the polarization of the structure. The main advantage of this criterion is the removal of errors due to IR drop from the measured potential. In order for this measurement to be accurate, all current sources to the structure must be simultaneously interrupted. Interrupting the current may be impossible or difficult in conditions where a large structure (e.g., an oil or gas transmission pipeline) is protected by several current sources, and where sacrificial anodes are electrically bonded to it. It should further be noted that most factors affecting the 850 mV ON criterion also affect the 850 mV OFF criterion, including access to the structure, seasonal fluctuation of corrosion potential, disbonded coating, stray current, and telluric current.

9.3 Cathodic protection

601

Potential

Spike due to inductive ef fect

Cathodic protection current switched of f

Corrosion potential

On potential Off potential

Duration

FIGURE 9.16 Variation of Potential After Switching off Cathodic Protection Current. (Indicating potential spike due to inductive effect, ON potential, OFF potential, and corrosion potential).

9.3.4d 100 mV polarization101 According to this criterion, the corrosion potential of the structure is moved 100 mV in the cathodic (negative) direction, no matter what it was before applying CP. Thus the potential profile of the surface before and after the application of cathodic protection is the same, except for a shift in potential by 100 mV in the negative direction after the application of cathodic protection. This is contrast to the 850 mV criteria (ON and OFF), in which cathodic protection shifts the potential of the entire surface to 850 mV vs. CCS, no matter what the corrosion potential was beforehand. From this it is clear that these criteria are the same when the corrosion potential is around 750 mV, and different when the corrosion potential is at a value that is very diiferent from this. Table 9.39 illustrates this concept numerically. Two methods are used to determine the shift in potential: formation and decay methods; with the decay method being the more common and efficient. In the formation method, the corrosion potential of the structure is measured before applying CP, and then again after applying CP. The difference between the two measurements should be more than 100 mV, with the potential measured after applying CP being more negative than the corrosion potential. The applying CP current generally decreases with time, and this observation is used to confirm that the criterion is properly implemented. In the decay method, the potential is continuously monitored with the CP current applied. The CP is then temporarily interrupted, and the decay in the potential is monitored. From the decay, the instant off

602

Criteria 850 mV ON 850 mV OFF

Corrosion Potential before Application of Cathodic Protection, mV vs. CCS 100 100

)

Potential after Application of Cathodic Protection, mV vs. CCS )

Degree of Polarization (Potential after CP e Potential before CP), mV))

850 850

750 750

100 mV polarization

100

200

100

850 mV ON 850 mV OFF 100 mV polarization 850 mV ON 850 mV OFF

750) 750 750

850) 850 850

100 100 100

900) 900

850) 850

100 mV polarization

900

1,000

)

þ50 þ50

100

Remarks Large amounts of current is necessary to apply cathodic protection. Smaller amounts of current is necessary to apply cathodic protection. Amount of current to apply cathodic protection is the same irrespective of criteria used. The structure is not cathodically protected. In this case 950 mV Vs. CCS criterion should be used. The structure is cathodically protected.

IR free Negative sign indicates that the potential moves in the cathodic (less corrosive) direction, and positive sign indicates that the potential moves in the anodic (more corrosive) direction

))

CHAPTER 9 Mitigation – External Corrosion

Table 9.39 Comparison of Various Cathodic Protection Application Criteria

9.3 Cathodic protection

603

potential and corrosion potential are noted. The instant off potential point is reached quickly due to the disappearance of IR effects (Figure 9.16). It should be noted that when the CP current is interrupted, the potential may exhibit a spike due to inductive effects which may last a few milliseconds. Therefore the instant off-potential is typically measured between 200 and 500 milliseconds after the interruption of current. After the instant off-potential, the potential shifts exponentially with time in the positive direction – due to the depolarization of the structure – until the corrosion potential is reached. The duration of this period may be measured in minutes, hours, days, or weeks depending on soil condition, type of cathodic application technique, coating status, and other interferences. The instant off-potential is then compared with the corrosion potential; the difference between these two potentials should exceed 100 mV (with the instant off-potential being more negative than the corrosion potential). The 100 mV polarization criterion is used to apply CP not only to carbon steel, but also to other metals including copper, aluminum, and metals for which a specific cathodic protection potential has not been established. The main disadvantage of using the 100 mV polarization criteria is the time required to implement the criteria, with depolarization taking from a few days to several weeks in some cases – as a consequence the structure is not protected for an extended period of time. To overcome this issue one approach is not to wait for full depolarization but to monitor the decay only for a few hours in which time structure should depolarize by more than 50 mV. If a 50 mV depolarization has not occurred within a few hours, the 100 mV polarization is not an appropriate criterion for the structure under the conditions. The 100 mV polarization criterion is not applicable in situations in which stray current is present, because polarizing the structure to 100 mV in the negative direction will not control corrosion. In addition, if all sources of stray current cannot be interrupted then it will not be possible to carry out an inspection to ensure that the 100 mV polarization criterion is met. The 100 mV polarization criterion is also not applicable on structures consisting of dissimilar metals, because a 100 mV polarization potential may not be adequate to polarize all the anodic areas of the structure. As discussed in section 10.3.2, high pH SCC may occur at potentials between the corrosion potential and 850 mV vs. CCS. Applying the 100 mV polarization criterion may polarize the structure to potentials which are more susceptible to SCC.

i. Aluminum The 100 mV criterion is used to cathodically protect aluminum pipes. However it should be noted that aluminum, in a similar way to titanium and zirconium, is amphoteric in nature; i.e., it undergoes accelerated corrosion at low and high pH. Polarizing aluminum to potentials more negative than 1,200 mV vs. CCS increases the pH. At higher pH values the oxides of aluminum dissolve rapidly, accelerating its corrosion. In addition, all precautions used to apply 100 mV polarization criteria for carbon steel also apply to aluminum.

ii. Copper The 100 mV criterion is also used to cathodically protect copper pipes. Copper is noble (more positive) than many metals, including cast iron, carbon steel, and aluminum. As a result many metals undergo corrosion when they are in contact with copper. It is therefore important to isolate these metals before applying CP to copper.

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CHAPTER 9 Mitigation – External Corrosion

9.3.4e 300 mV potential shift The 300 mV potential shift criterion is similar to the 100 mV polarization criterion, but in this criterion the CP is applied to shift the potential by 300 mV from the corrosion potential in the cathodic (negative) direction and the potential is measured with CP on. For this reason, the 300 mV potential shift criterion suffers from the influence of IR drop. All limitations discussed for 100 mV polarization criterion are also applicable to 300 mV potential shift criterion. This criterion was developed empirically for steel structures in concrete in which the corrosion potential is between 200 mV and 500 mV vs. CCS. In such situations, the steel is in the passive state, and areas which are not in this state are protected by shifting the potential by 300 mV in the negative direction.

9.3.4f Net protective current The premise of this method is that corrosion does not take place in locations of the structure which receive current from the environment (soil or electrolyte), i.e., where reduction reactions take place. To implement this criterion, the CP current is first interrupted and a survey is conducted to locate corrosive spots (i.e., anodic regions) of the structure. Section 11.3 describes various survey methods – the close-interval structure-to-soil potential survey is commonly used. The CP current is then turned on, and another survey, commonly known as side-drain method, is used to determine whether the anodic regions of the structure are receiving CP current, i.e., current from the electrolyte. Three identical electrodes are used; one is placed directly over the structure, and the other two on either side. The potential differences between the electrode over the structure and the ones placed on the side of the structure are measured. If the electrode placed over the structure is negative with respect to the ones placed on the side, then it is taken that that location of the structure is receiving cathodic current. This criterion is normally used on structure with long-line current activity (e.g., uncoated or poorly coated structure) and in situations where other criteria cannot be easily or economically implemented. When using this criterion, it should be noted that anodic reactions, can take place at any location where the potential is more positive than the Eequil (Figure 9.12). Corrosion cannot take place only when the potential is more negative than Eequil. Nevertheless, it is assumed in practice that locations receiving any amount of current from the environment are not susceptible to corrosion. Further, the identification of anodic sites may be difficult in areas of stray current activity, which contain several infrastructures (e.g., pipeline corridors), or on structures in high resistivity soil, with long-line current activity, or in which the distance between the anodic and cathodic areas is small.

9.3.4g E-log I curve Section 9.3.2 discusses the basic principle of this criterion. It is frequently used to establish the minimum current required to implement effective CP. To establish this criterion, the structure-to-soil potential is measured as a function of CP current. Typically the potential measurements are made by interrupting the cathodic current and measuring the instant off potential using a remote reference electrode. The E-log I plot is constructed from the measurements. Figure 9.17 presents theoretical background to the plot (see section 9.3.2). The plot is used to derive the negative potential and the minimum current needed to achieve effective CP, and these values are used to design and operate the cathodic protection system. Subsequent surveys are conducted to ensure that the current output of

9.3 Cathodic protection

605

+

EC Iappl=IC -IA

-

IA

IC

FIGURE 9.17 Typical E-Log I Curve to Establish a Minimum Cathodic Protection Current Requirement.

the cathodic protection system and the potential of the structure with respect to the remote reference electrode are close to the established value. Implementation of this criterion requires elaborate arrangements and repeat measurements. It is also important to place remote reference electrode in the same location every time the potential is measured. For these reasons, this criterion is normally used in situations where other criteria cannot be easily implemented. Such situations include pipelines in river crossing, in well casings, and in populated industrial areas. Furthermore it should be noted that it may be difficult to reproduce the original E-log I plot used to establish this criterion.

9.3.5 Applicability of cathodic protection There are situations in which cathodic protection is ineffective or not applicable at all. Cathodic protection cannot protect features above conducting media such as the aboveground portions of tanks, valves, and offshore structures in splash zones. The CP implemented to protect the external surface of a structure cannot protect its internal surface because the current is interrupted by the external surface and returned back to its source. This is true even though the pipe material is a good electrical conductor. The CP will only protect the external layers of multilayered structures or features, e.g., power or communication cables. Most current flows only to the outer layer, and little current flows to the inner layers. This phenomenon is commonly known as electrical shielding (Figure 9.18). CP is ineffective for protecting surfaces beneath non-conducting materials, e.g., disbonded coatings and insulators. Very high potential drive is required to allow the current to penetrate through these nonconducting materials. Implementation of such a system may not be economically possible.

9.3.6 Factors influencing the effectiveness of cathodic protection The effectiveness of cathodic protection depends on several factors; some of which are discussed in this section.

606

CHAPTER 9 Mitigation – External Corrosion

A

+ –

B C

E

FIGURE 9.18 Electrical Shielding Effect During Cathodic Protection.103 Reproduced with permission from NACE International.

9.3.6a Protective coatings A protective coating is the single most important factor influencing the application of cathodic protection. As discussed in section 9.2, as long as the coating is intact, it is the first line of defense, giving little or no need for CP. As the coating deteriorates the amount of CP current needed increases. It is important that the protective coating does not disbond in such a manner to prevent the CP current from reaching the metal surface.

9.3.6b Maintenance capacity Controlling corrosion of a structure with CP is not a one-time operation, but is a continuous one. Therefore the capacity to operate and maintain the system should be established upfront and should be implemented during service. Chapter 13 discusses general maintenance issues in corrosion control.

9.3.6c Environment The ease with which CP is applied depends on the type of environment. In general, factors which increase the corrosion rate make the application of CP relatively difficult. Such factors include oxygen content, acidity, microbial species, and flow of water. Increases in any of these factors generally increases the current required to apply effective CP.

9.3.6d Temperature The effect of temperature on CP manifests through the effect of conductivity (or resistivity). In general, the conductivity of water decreases with decreases in temperature. The conductivity of frozen soil is

9.3 Cathodic protection

607

low when compared to unfrozen soil. It is for this reason that an anode ground bed is installed in deep soil in permafrost regions (approximately 80 m (262 feet) from the surface). In these regions, the soil surface is permanently frozen but areas deep below ground are unfrozen.

9.3.7 Stray currents Stray current is an unwanted current from external sources which interferes with that of the infrastructure of interest. There are three types: DC stray current, AC stray current, and telluric current.

9.3.7a DC stray current DC current flowing from any source (other than the anode bed of the given infrastructure) and entering the infrastructure of interest is considered as stray current. The stray current from an external source flows to the earth, enters into the infrastructure from the earth, leaves the infrastructure, re-enters the earth, and finally returns to its original source. The point of the infrastructure at which the stray current leaves and returns back to earth becomes anodic and undergoes corrosion. Common sources of stray current include cathodic protection current from other pipelines or infrastructure, railway transit systems, mining operations, welding operations, and DC transmission systems. The stray current may be steady or random. For example, the stray current from a neighboring CP system or DC transmission system is mostly steady (static stray current), and that from a railway transit system, mining operation, and welding operation is random (dynamic stray current).

i. Static stray current Figure 9.19 illustrates a situation in which the CP current from one pipeline interferes with and causes corrosion in a neighboring pipeline.104 Figure 9.20 illustrates a test system to determine whether the CP of a given pipeline of interest is interfering with and causing corrosion in neighboring pipelines.105 In addition to other gadgets for applying CP, an automatic interrupter is installed in the pipeline of interest and test leads are installed both in the pipeline of interest and in the neighboring pipeline at appropriate locations. With the automatic interrupter operating in a cyclic fashion (e.g., 20 seconds ON and 10 seconds OFF), the potentials of both the pipeline of interest and neighboring pipelines are measured.106 For this purpose the CCS reference electrode is placed at the points of crossing. Table 9.40 presents some survey results illustrating different scenarios in which the CP systems of neighboring pipelines may influence one another. From the examples presented in Table 9.40 and Figure 9.20 we can conclude that: • • • •

the CP system of pipeline of interest (pipeline E) interferes with pipelines A and B the CP system of neighboring pipeline C interferes with pipeline E corrective measures to overcome stray current are required for pipeline A (to overcome stray current from pipeline E) and pipeline E (to overcome stray current from pipeline C) and no corrective measures are required for pipeline B (to overcome stray current from pipeline E), as the influence is minimal.

In many situations, the proper installation, operation, and maintenance of a CP system may be sufficient and effective to overcome the effect of stray current. Additional measures include the use of a drainage bond, protective coating, galvanic anode, and electrical shields, and relocation of rectifier or the infrastructure itself. Electrically connecting interfering infrastructure by resistance bonds is a common method of overcoming stray current. The resistance of the bond is adjusted so that sufficient

608

CHAPTER 9 Mitigation – External Corrosion

AREA OF INFLUENCE SURROUNDING THE GROUND BED

FOREIGN PIPELINE NOT CROSSING PROTECTED LINE

ENDWISE CURRENT FLOW

CURRENT GROUND BED

DISCHARGE FROM FOREIGN PIPELINE IN

REMOTE RECTIFIER AREAS

PROTECTED PIPELINE

FIGURE 9.19 Stray Current from the Cathodic Protection of an Infrastructure Causing Corrosion in the Neighboring Infrastructure.104 Reproduced with permission from NACE International.

current is drawn to overcome the effect of the stray current. Figure 9.21 presents a bond between two interfering pipelines installedto overcome the stray current.107 Stray current affects areas of the infrastructure that are bare, e.g., those that have poor coating. Under such conditions, bonding may not be economically feasible because the amount of current required to overcome the stray current is very high. In this situation, repairing the coating or recoating the infrastructure may decrease the effect of stray current. The use of sacrificial anodes may sometimes be beneficial. With this arrangement, the stray current from the neighboring structure is discharged at the anode rather than on the infrastructure of interest. Stray current may also be mitigated by using an electrical shield. For example, the effect of stray current on a pipeline of interest may be mitigated by placing bare pipes around it and connecting the bare pipe to the negative terminal of a neighboring pipeline. The bare pipe will pick up the stray current from the neighboring pipeline thereby protecting the pipeline of interest. The bare pipe drains large amounts of current from the neighboring pipeline. Therefore the diameter and length of the pipe should be kept to a minimum. In extreme conditions when none of the mitigation strategies discussed so far work, the possibility of relocating the rectifier of the neighboring infrastructure or relocating the infrastructure of interest (e.g., rerouting of the pipeline) should be considered.

ii. Dynamic stray current The operating potential of a rail transit system is around 750 volts. If the running rails are not completely insulated from the earth, the stray current will affect infrastructures present on its return

9.3 Cathodic protection

609

PICKUP FOREIGN LINE B

FOREIGN LINE A

FOREIGN FOREIGN LINE D LINE C RECTIFIER GROUND BED INSTALLATION

STATION 900 + 00

PROTECTED LINE UNDER TEST

STATION 1765 + 00 PIPELINE E (OWN PIPELINE)

STATION 10 + 00

DISCHARGE STATION 915 + 00

STATION 1815 + 00

CURRENT INTERRUPTER INSERTED FOR TESTS

RECTIFIER AND GROUND BED ON FOREIGN LINE

+

V

–

2 BLACK LEADS FOREIGN LINE 2 WHITE LEADS PROTECTED LINE

FIGURE 9.20 Typical Testing System to Determine the Influence of Stray Current.105 Reproduced with permission from NACE International.

path. The severity of this effect depends on the effectiveness of the insulation of the rail transit system and traffic in the line. The frequency at which the infrastructure is exposed to higher voltages is directly proportional to the frequency of the trains on the track. The infrastructure is affected by stray current only when the train runs. Thus the stray current is dynamic in nature.

610

Potential, Vs CCS (V) Own Pipeline, V (Identified as E in Foreign Pipeline

Fig. 9.19)

Foreign Pipeline, V

With Cathodic

With Cathodic

Protection

Protection

Effect of the Cathodic

Distance

Current of

Current of

Protection System of

Protection System of

Correction Required to

from

Pipeline E

Pipeline E

Pipeline E

Neighbouring Pipeline

Overcome Stray Current from

Effect of the Cathodic

Pipeline E Rectifier,

On

Feet (see Designation

Fig. 9.20)

A

10

ON 0.88

OFF 0.85

DV 0.03

ON 0.87

OFF 0.89

DV þ0.02

On

Neighbouring

Pipeline E on

On

Neighbouring

On

Neighbouring

Pipeline on

Neighbouring

Pipeline E

Pipeline

Pipeline E

Pipeline

Pipeline E

Pipeline

Fully

Interferes

No

Fully protects

No (no

No (DV value

protects

(DV positive),

interference

(ON and Off

interference)

small)

(ON and Off

but the effect

(ON and Off

potentials more

potentials

minimum

potentials

negative than

more

more

negative

negative

than

than

0.85

V)

0.85 V) 0.85

V; addition testing may be required to confirm)

B

900

1.98

1.02

0.96

0.32

0.68

þ0.36

Fully

Interferes

No

Not adequately

No (no

Yes (DV value

protects

(DV positive)

interference

protects (ON

interrence)

positive and

(ON and Off

(ON and Off

and Off

potentials

potentials

potentials more

more

more

positive than

negative

negative

than

than

0.85 V)

0.85

V; addition testing may

0.85 V)

high)

CHAPTER 9 Mitigation – External Corrosion

Table 9.40 Typical Survey Results on Stray Current Interference106

be required to confirm) C

1765

0.68

0.64

0.04

0.78

0.78

0

Not

No interference

Interferes

Not adequately

adequately

(DV zero)

(ON and Off

protects

protects

potentials

(ON and Off

(ON and Off

more

potentials more

potentials

positive than

positive than

less

0.85 V and

negative

in other

than

locations of

0.85 V)

Yes

No

No

No

0.85 V)

the pipeline it is more negative than 0.85 V)

D

1815

0.95

0.91

0.04

0.68

0.68

0

Fully

No interference

No

Not adequately

protects

(DV zero)

interference

protects

(ON and Off

(ON and Off

(ON and Off

potentials

potentials

potentials more

more

more

positive than

negative

negative

than

than

0.85 V)

0.85 V)

0.85 V)

9.3 Cathodic protection 611

612

CHAPTER 9 Mitigation – External Corrosion

TYPICAL FOREIGN LINE CROSSING TEST POINT INSTALLATION. TERMINAL BOX MAY BE BURIED, IF NECESSARY, RATHER THAN POST-MOUNTED

BOND TYPICALLY AN ADJUSTABLE SLIDE RESISTER CONNECTED BETWEEN THE HEAVY LEAD TERMINALS FOR WIRES FROM FOREIGN AND PROTECTED LINES

HIGH RESISTANCE

TEST VOLTMETER COPPER SULPHATE ELECTRODE DIRECTLY OVER FOREIGN LINE AT POINT OF MAXIMUM EXPOSURE

(TYPICAL) NO 8 & NO 12 BLACK INSULATED WIRES FROM FOREIGN LINE FOREIGN LINE BEING AFFECTED BY STRAY CURRENT INTERFERENCE

NO 8 & NO 12 WHITE INSULATED WIRES FROM PROTECTED LINE

PROTECTED PIPELINE WITH RECTIFIER (INTERRUPTED) CAUSING INTERFERENCE ON FOREIGN PIPELINE

FIGURE 9.21 Bond to Overcome Stray Current Between Two Pipelines.107 Reproduced with permission from NACE International.

Several of the methods used to mitigate static stray current are also effective in mitigating dynamic stray current. Ideally, a rail electrical system should be isolated from the earth. All inadvertent contact between the rail electrical system and the earth should be eliminated. Further, insulating joints should be installed in the infrastructure in susceptible areas. After the insulating joints have been installed, the CP system should be suitably adjusted to ensure that the relevant section is properly protected. Sacrificial anodes may be installed, along with diodes. This arrangement ensures that the anodes discharge the stray current rather than receiving it. Installation of a controller that automatically adjusts the rectifier may be effective in providng additional current when the stray current is active. This strategy is effective only if the area affected by the stray current is small. Installation of bonds between the pipeline and the transit system may be considered in special situations in which all other strategies are ineffective. The voltage of the transit system is very high; therefore implementation of this strategy requires sophisticated analysis and extreme care.

9.3 Cathodic protection

613

9.3.7b AC stray current This is discussed in section 5.21.

9.3.7c Telluric current This is discussed in section 5.22.

9.3.8 Side effects of cathodic protection Cathodic protection is very effective in controlling the corrosion of materials, but in some situations it can lead to undesired side effects. Some of these are described in this section. Cathodic protection controls the corrosion of a material by making it a cathode. Consequently cathodic reactions take place on the surface; however, the products of certain cathodic reactions may be harmful to the structure. The primary example of this is the hydrogen effect (see section 5.18). To avoid this, the application of potentials at which hydrogen reduction occurs is avoided. The corrosion rates of amphoteric materials (aluminum, titanium, and zirconium) may increase due to cathodic protection. Cathodic protection may increase the pH; at high pH the surface layers on amphoteric materials dissolve, resulting in higher corrosion. Foreign structures, especially those near the anode ground bed may suffer accelerated corrosion if the current enters and discharges through it. Figure 9.19 illustrates this situation. To overcome this issue, the foreign structure should be electrically connected to the structure being protected by bonding. This, however, increases the area of the surface being protected by the CP system.

9.3.9 Materials and accessories The application of cathodic protection requires several materials and accessories, some of which are described in this section.

9.3.9a Backfill material Backfill materials are used in the anode bed to reduce the resistance between the anode and the ground. These materials are commonly known as ’breeze’ – a term used to indicate their finely divided nature. Typical materials include petroleum coke, calcined petroleum coke, coal coke, natural graphite particles, crushed graphite particles, and metallurgical coke. Deep-anodes are typically placed in a coke column and are installed at 60 to 90 m (196 to 295 feet) from the surface.

9.3.9b Test station The test station is the key to ensure that CP is working properly. There are several configurations of test stations (Figure 9.22). They provide locations for connecting wires to measure structure to environment potential, to measure current flow (line current measurements), to connect galvanic anodes to the structure, to insert resistance across the wires, and to insert bond across insulation joints.

9.3.9c Current interrupter Interrupting the current is necessary and is used frequently to test the CP system. A current interrupter relies on a quartz crystal to precisely time the current interrupt and to synchronize with other devices.

614

CHAPTER 9 Mitigation – External Corrosion

FIGURE 9.22 Typical Configurations of Test Stations for Cathodic Protection.108 Reproduced with permission from NACE International.

9.3.9d Pulse generator A pulse generator is required to conduct ON and OFF potential surveys. It may either produce its one pulse current or suitably interrupt the current from the CP power supply.

9.3.9e Ammeter clamp access To measure the current flowing through the pipeline (line current), a portable ammeter is clamped onto the pipeline. Access to clamp the device should be installed.

References

615

9.3.9f Wires and cables Wires and cables between the anode bed and the structure carry the current. They should be perfectly insulated, otherwise they discharge current at points where they contact the environment. Insulation materials are rated to withstand at least 600 V and are normally made from polyethylene. They should be inspected during installation to ensure that they do not have any scars, cuts, or other damage. An insulator-checker is used to inspect the integrity of the insulators. The wires and cables are connected to the anodes and the structures using low electrical resistance welds, brazes, and solders, otherwise the connection resistance and cable and wire resistance decrease the current output from the CP system.

9.3.9g Casing pipes Casing pipes used are at road and railway crossings to protect oil and gas pipelines. They are electrically insulated from the oil and gas pipeline, otherwise the casing pipes would carry current from the CP system that are intended for the oil and gas pipeline. Typically, insulating spacers are placed at several locations (typically 10 feet (w3 meter) apart) between the mainline and casing pipes. The spacers may be made of rubber or plastic.

9.3.9h Insulated joints Insulating joints are used to separate the infrastructure into various electrically separate sections so that the CP is applied effectively. Insulated joints are typically used every 25 to 60 miles (40 to 100 km) of pipeline. They are also used to isolate the infrastructure in locations that are susceptible to stray current from other structures.

References 1. NACE RP 169 ‘Control of external corrosion on underground or submerged metallic piping systems.’ NACE International, 1440, South Creek Drive, Houston, TX, USA. 2. ISO 15589, ‘Petroleum and natural gas industries – cathodic protection of pipeline transportation systems.’, International Organization for StandardizationISO Central Secretariat1, ch. de la Voie-CreuseCP 56 - CH1211 Geneva 20Switzerland. 3. CSA Z662, ‘Oil and gas pipeline systems (Annex L: Test methods for coating property evaluation)’ Canadian Standards Association, 178 Rexdale Blvd.Toronto, Ontario, Canada M9W 1R3. 4. Mike J. Mitchell, ‘Progress in offshore coatings’ NACE CORROSION Conference 2004, Paper #4001, NACE International, Houston, TX (2004). 5. Papavinasam S, Revie RW. Pipeline coatings, White Paper, Proceedings, International Workshop on Advanced Research & Development of Coatings for Corrosion Protection. Biloxi, Mississippi April 14–16, 2004. 6. Wood LJ. The protection of steel pipes with coal-tar enamel systems: importance of specification and design. Anticorrosion 1984;31:4. 7. Johnson JR, Henegar S, Roder B, ‘A new higher temperature coal-tar enamel pipeline coating system’, NACE CORROSION CONFERENCE 1996, Paper # 196, NACE International, Houston, TX (1996). 8. First Interim Report, Tentative recommended specifications for ‘asphalt type protective coatings for underground pipe lines – wrapped systems’, NACE Publication 57–11, Corrosion13(4), 1957, p. 283t. 9. Second Interim Report, Tentative recommended specifications for ‘asphalt type protective coatings for underground pipe lines – mastic systems’, NACE Publication 57–14, Corrosion13(5), 1957, p. 347t.

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10. Tentative recommended specifications for asphalt-type protective coatings for underground pipelines (minimum recommended protection)’, NACE Publication (58–12), Corrosion 14, 1958, p. 373t. 11. Report of NACE Technical Unit Committee T-6A on Coatings and Lining Materials for Immersion Service. Prepared by Task Group T-6A-19 on Asphalts, ‘Chemical resistance of asphalt coatings’, Materials Performance 5(1), 1966, p. 81. 12. Davidson RR, Stauffacher ER. Field tests of exterior coatings for a pipe line conveying fuel oil heated to 200 degree F. Corrosion 1953;9:377. 13. Milter DE. Examination of 335 miles of asphalt mastic coated pipe. Corrosion 1953;9(7):210. 14. Paisley GJ. Leakage conductance coating surveys on asphalt mastic coated pipe. Corrosion 1961;17(11):101. 15. Roche M, and Samaran JP, ‘Pipeline coatings performance field experience of an operating petroleum company’, NACE CORROSION CONFERENCE 1987, Paper #28, NACE International, Houston, TX, USA (1987). 16. Delanty B, O’Beirne J. Major field study compares pipeline SCC with coatings. Oil & Gas Journal 1992; 90:39. 17. Benedict RL, ‘Evaluation of tape coats for large diameter water transmission lines’, NACE CORROSION CONFERENCE 1994, Paper # 563 18. Appleman BR. Tape systems for pipeline protection. Journal of Protective Coatings and Linings 1987; 4(7):52. 19. Norsworthy R. Rating underground pipeline tape and shrink sleeve coating systems. Materials Performance 1999;38(11):40. 20. Geary RW. Evaluating Pipeline tape coatings – how do they compare? Materials Performance 2000; 39(1):43. 21. Application techniques, properties and chemical resistance of polyethylene coatings’, NACE Technical Committee Report 59–7, Corrosion 15(3) (1959), p. 33 (117t). 22. Roebuck AH, ‘Coatings for Arctic pipelines’, NACE CORROSION CONFERENCE 1981, Paper # 160, NACE International, Houston, TX, USA (1981). 23. Harris GM. A review of recent developments and the performance of tape coatings for underground pipelines. Materials Performance 1979;18(9):17. 24. Harris GM. Polyethylene protective coating tapes. Materials Performance 1973;12(12):19. 25. Harris GM. Plastic tapes: 20 years of underground corrosion control. Materials Performance 1970;9(7):26. 26. Hewes FW. A survey of requirements and cost for cathodic protection on 22,000 miles of coated pipelines. Materials Protection 1966;5(9):41. 27. Harris GM. Polyethylene tape for pipeline coatings. Materials Performance 1972;11(6):45. 28. National Energy Board (NEB), Canada, Report, ‘Stress-corrosion cracking on Canadian oil and gas pipelines’, Figure 3.9, p. 25, December 1996, MH-2–95. 29. Rodriguez V, Paiva A, and Castaneda L, ‘External coating failures in Venezuelan pipelines’, NACE CORROSION CONFERENCE 1994, Paper # 571, NACE International, Houston, TX, USA (1994). 30. Nunez S, Coulson KEW, Choate LC, Banach JL. A review of gas industry pipeline coating practices. American Gas Association, A.G.A July 1988. Catalog # L51586. 31. Kellner JD, Doheny AJ, Patil BB. A new three layer polyethylene coating for plant application, CORROSION 97, Paper # 557, NACE International, Houston, TX,USA (1997) 32. McDaniel M. Methods of testing characteristics of polyethylene jackets for steel pipe. Corrosion 1959; 15(6):100. 33. Extruded polyolefin resin coating systems for underground or submerged pipe. NACE Standard RP-01–85, Item No.53053. Materials Performance 1985;24(8):51.

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34. Lukezich SJ, Hancock JR, Yen BC. State-of-the-art for the use of anti-corrosion coatings on buried pipelines in the natural gas industry. GRI-92/0004 April 1992:29. 35. Pranghu NS, Baeckmann WV. Polyethylene extrusion coatings for steel pipe. Materials Performance 1978; 17(8):22. 36. Vemer E, Fletcher A. An introduction to fusion bonded low density polyethylene coatings for large bore steel pipe. Corrosion and Coatings SA 1995;22(1):6. 37. Szklarz KE, and Baron JJ, ‘Considerations for cold weather construction using high density polyethylene for corrosion control systems’, NACE CORROSION CONFERENCE 1995, Paper # 556, NACE International, Houston, TX, USA (1995). 38. Williams JF. Thermal bonded epoxy coatings meet economic requirements and pollution standards. Materials Performance 1971;10(9):15. 39. Burge RE, Brown BC. Performance of three typical room temperature cured epoxy formulations in warm corrosives. Materials Performance 1962;1(6):30. 40. McConkey SE. Application and quality control of fusion bonded epoxy coatings. Journal of Protective Coatings and Linings 1988;5(5):26. 41. Norman D, Gray D. Fusion bonded epoxy pipe coatings – 10 years experience. Material Performance 1993; 32(3):36. 42. Didas J. Fusion bonded epoxy coatings for underground pipelines. Materials Performance 2000;39(6):38. 43. Corrosion prevention by protective coatings. C.C. Munger, Published by NACE; 1984. 333. 44. Kehr JA, ‘Fusion bonded epoxy (FBE): A foundation for pipeline corrosion protection’, ISBN: 157590148X, NACE International, Houston, TX. 45. Gaillard G, Connelly G, and Llorens J, ‘Three-layer epoxy-polyolefin pipe coatings’, NACE CORROSION CONFERENCE 1988, Paper #309, NACE International, Houston, TX, USA (1988). 46. Cox JW, Fogh F. Dual coating system for pipelines in high temperature service. Materials Performance 1990;29(10):18. 47. Blome P, Friberg G. Multilayer coatings systems for buried pipelines. Materials Performance 1991;30(3):20. 48. Alexander M. High temperature performance of three layer epoxy/polyethylene coatings. Materials Performance 1992;31(6):41. 49. Aalund LR. Polypropylene system scores high as pipeline anti-corrosion coating. Oil and Gas Journal December 1992:42. 50. Dempster WA, and Doheny AJ, ‘Heat fused polyolefin system for fusion bonded epoxy coated pipe’, NACE CORROSION CONFERENCE 1994, Paper #564, NACE International, Houston, TX, USA (1994). 51. Kellner JD, Doheny AJ, Patil BB. A three layer polyethylene coating for plant application. Materials Performance 1998;37(6):28. 52. Miyajima Y, Funatsu S, Endoh E, Kariyazono Y, and Ishida M, ‘Durability of polyethylene coated steel pipe at elevated temperatures’, Nippon Steel Technical Report No.63, October 1994, p. 48. 53. Kishikawa H, Kamimura T, Soga Y. Development of polypropylene coated steel pipe for high temperature service. The Sumitomo Search 1996;58(9):1. 54. Fennema TS. Versatile polypropylene. Materials Performance 1963;3(1):59. 55. Tsuri S, Takao K, and Mochizuki K, ‘Effect of primer composition on cathodic disbonding resistance and adhesion durability of three layer polyethylene coated steel pipe’, NACE CORROSION CONFERENCE 1998, Paper #497, NACE International, Houston, TX, USA (1998). 56. King F, Been J, Worthingham R, and Rubie G, ‘Laboratory and field investigations of the performance of HPCC coatings’ International Pipeline Conference IPC04–0082, October 4–8, 2004, Calgary, AB, Canada. 57. Papavinasam S, Attard M, Revie RW. Evaluation of external pipeline coatings for corrosion protection – a review. Corrosion Reviews 2008;26(5–6):371–438.

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58. Papavinasam S, Revie RW. ‘Pipeline protective coating’, ‘Advanced Coatings R&D for Pipelines and Related Facilities’. National Institute of Standards and Technology (NIST), NIST Special Publication 1044; June 9–10, 2005. September 2005. 59. Papavinasam S, Arsenault B, Attard M, and Revie RW, “Metallic Under-Layer Coating as Third Line of Protection of Underground Oil and Gas Pipelines from External Corrosion” Corrosion, Vol. 68 (12), pp. 1146-1153 (2012). 60. Papavinasam S, Doiron A, and Panneerselvam T, ‘External corrosion control of northern pipelines’, Proceedings of International Pipeline Conference (IPC 2008), IPC2008–64069, ASME International, Two Park AvenueNew York, NY 10016-5990. 61. Buchanan R, ‘Innovations in field joint coatings to meet rigorous specifications for offshore pipelines’, NACE CORROSION CONFERENCE 2004, Paper #4020, NACE International, Houston, Texas, USA (2004). 62. Papavinasam S, Zaver N, and Pollock J, “Comparison of International Standards to Evaluate Field-Applied Pipeline Girth-Weld Coatings”, Corrosion Reviews, 30 (5-6), 2012, p. 171–197. 63. NACE Technical Publication 56–5, ‘Report on epoxy resins’, Unit Committee T-6A on Organic Coatings and Linings for Resistance to Chemical Corrosion. Corrosion 1(4), 1956, p. 49 (187t). 64. Schneider W. Ambient temperature curing waterborne epoxy systems. Materials Performance 1991; 30(1):28. 65. Cushing JW, Montle JF, Byrd JD. Resistance properties of urethane coatings. Corrosion 1961;17(12):28. 66. Winter CH, Sillers R, Glowach AM. High temperature, insulated coating aids construction of Alberta bitumen pipeline. Oil and Gas Journal 2003:56. January 27. 67. Paulette PPT, Lambrakos SG, Jones HN. Properties of rigid polyurethane foams related to their use for corrosion control inside confined spaces. Corrosion 2000;56(7):757. 68. Werner DP, Barlo TJ, Coulson KEW. Shielding effect of concrete and urethane foam external pipeline barrier coatings. Materials Performance 1992;31(2):24. 69. Brouwer AA, ‘Ten Years Underground-microcrystalline wax pipe coating overwrapped with a vinylidene chloride copolymer plastic wrapper’, NACE 17th Annual Conference, Buffalo, NY-1961 NACE International, Houston, Texas, USA (2004). 70. Weber TJ, ‘A cost effective pipeline recoating solution using hot applied microcrystalline wax’, NACE CORROSION CONFERENCE 2003, Paper # 3041, NACE International, Houston, Texas, USA (2003). 71. Guan SW, ‘Advanced 100% solid rigid polyurethane coatings technology for pipeline field joints and rehabilitation’, NACE CORROSION CONFERENCE 2003, Paper #3043, NACE International, Houston, Texas, USA (2003). 72. Guo B, Song S, Chacko J, and Ghalambor A, ‘Offshore pipelines’, Chapter 9: Pipeline Insulation, p. 107, ISBN: 978-0-7506-7847-6, Gulf Professional Publications, 30 Corporate Drive, Suite 400, Burlington, MA 01803, USA (2005). 73. Cushing JW, Montle JF, Byrd JD. Resistance properties of urethane coatings. Corrosion 1961;17(12):28. 74. Winter CH, Sillers R, Glowach AM. High temperature, insulated coating aids construction of Alberta bitumen pipeline. Oil and Gas Journal 2003:56. January 27. 75. Paulette PPT, Lambrakos SG, Jones HN. Properties of rigid polyurethane foams related to their use for corrosion control inside confined spaces. Corrosion 2000;56(7):757. 76. Werner DP, Barlo TJ, Coulson KEW. Shielding effect of concrete and urethane foam external pipeline barrier coatings. Materials Performance 1992;31(2):24. 77. Singh P, Haberer S, Gritis N, Worthingham R, Cetiner M. Coating transmission pipeline for Arctic conditions: trial shows promise. journal of coatings and protective liners (SSPC) February 2006:24. 78. Goldberg B. Flame sprayed plastic coatings. Corrosion 1951;7(5):48.

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79. Mundt MLJ, and Stacy SJ, ‘Report of protective coatings investigation underwater exposure tests’, 1941–1949, Corrosion 1951;7(5):1951. 80. Malhotra VM. Chapter 31, Durability of concrete, Figure 31.6, page 447. In: Revie RW, editor. Uhlig’s Corrosion Handbook. New Jersey: J. Wiley and Sons, Hoboken; 2011. ISBN: 978-0-470-08032-0. 81. Berke NS, and Hicks MC, ‘Long-term corrosion performance of epoxy-coated steel and calcium nitrite’, NACE CORROSION CONFERENCE 1998, Paper # 652, Houston, TX (1998) NACE International, Houston, Texas, USA (1998). 82. Kessler RJ, Powers RG, and Paredes MA, ‘Performance of corrosion prevention methods – 18 year study’, NACE CORROSION CONFERENCE 2009, Paper # 9219, NACE International, Houston, Texas, USA (2009). 83. Broomfield JP. “A Case History of Cathodic Protection of a Highway Structure in the UK” CORROSION 2004, Paper #4344, NACE International, Houston, TX, USA (2004). 84. Cui F, Lawler J, Krauss P. Corrosion performance of epoxy-coated reinforcing bars in a bridge substructure in marine environment. CORROSION 2007, Paper # 7286. NACE International, Houston, Texas, USA (2007). 85. Beavers JA. ‘Chapter 3: Cathodic protection – how it works’ in Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Table 3.1, p. 27, ISBN: 1-57590-092-0. 86. Corrosion basics: an introduction, Chapter 9: Cathodic Protection. Houston, TX: NACE; 1984. p. 179, ISBN: 0-915567-02-4. 87. Beavers JA. ‘Chapter 16: Fundamentals of corrosion’ in Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Figure 16.13, p.16, ISBN: 1-57590-092-0. 88. Papavinasam S, Panneerselvam T, Doiron A. “Applicability of Cathodic Protection for Underground Infrastructures Operating at Sub-Zero Temperatures, NACE Northern Area Eastern Conference, Toronto, Ontario, Canada Oct. 28-31, 2012, NACE International, Houston, TX, USA. 89. Revie RW, Uhlig HH. Corrosion and corrosion control’ Figure13.1. J. Wiley; 2008. p. 253, ISBN: 978–0471–73279–2. 90. Bianchetti RL. ‘Chapter 9: Cathodic protection with galvanic anodes’ in Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 177, ISBN: 1-57590-092-0. 91. Ashworth V. Chapter 4.18, Principles of cathodic protection. In: Cottis B, Graham M, Lindsay R, Lyon S, Richardson T, Scantlebury D, Stott H, editors. Shreir’s Corrosion: Volume 4, Management and Control of Corrosion. The Netherlands: Elsevier, Raderweg 29, 1043 NX Amsterdam; 2010. p. 2747. ISBN 978-0444-52788-2. 92. Bianchetti RL. Chapter 9: Cathodic protection with galvanic anodes’ in Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Table 9.5, p. 186, ISBN: 1-57590-092-0. 93. Fitzgerald JH. Chapter 69: Engineering of cathodic protection systems. In: Revie RW, editor. Uhlig’s Corrosion Handbook. New Jersey (: Wiley and Sons, Hoboken; 2011. p. 1001. ISBN: 978-0-470-08032-0. 94. Holtsbaum WB. Well casing external corrosion and cathodic protection. In: ASM Handbook, Volume 13C: Corrosion: Environments and Industries. ASM International, Materials Park, OH 44073–0002; 2006. p. 97. ISBN: 978-0-87170-709-3. 95. Parker ME, Peattie EG. Pipe line corrosion and cathodic protection. 3rd ed. Houston, TX: Gulf Publishing Company; 1984. 96. Kumar A, Bushman JB, Fitzgerald JH, Brown AE, Kelly TM. Impressed current cathodic protection systems utilizing ceramic anodes. Champaign, IL: US Army Corps of Engineers Construction Engineering Research Laboratories; 1990. 97. Advanced Course, Text, Appalachian Underground Corrosion Short Course. Morgatown, WV: West Virginia University; 2008.

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98. Baeckmann WV, Schwenk W, Prinz W. Handbook of cathodic protection. Houston, TX: Gulf Publishing Company; 1997. 99. Ashworth V, and Booker CJL, Ed., ‘Cathodic protection theory and practice’ Institution of Corrosion Science and Technology, Birmingham, UK. 100. Fitzgerald JH. ‘Chapter 69, Engineering of cathodic protection systems’, Figure 69.5. In: Revie RW, editor. Uhlig’s Corrosion Handbook. New Jersey (: J. Wiley and Sons, Hoboken; 2011. p. 1009. ISBN: 978-0-47008032-0. 101. Beavers JA, Garrity KC. ‘Chapter 4: Cathodic protection with galvanic anodes’ in Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 49. ISBN: 1-57590-092-0. 102. Heidersbach RH. ‘Cathodic protection’ Table 3, p. 858, ASM handbook, Vol. 13A: Corrosion: fundamentals, testing, and protection. In: Cramer SD, Covino BS, editors. ASM International; 2003. ISBN: 087170-705-5. 103. Corrosion basics: an introduction, Chapter 9: Cathodic protection, Figure 9.3. Houston, TX: NACE; 1984. p. 180, ISBN: 0-915567-02-4. 104. Beavers JA. Chapter 3: Cathodic protection – how it works’ in Peabody’s Control of Pipeline Corrosion. Figure 3.13. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 43. ISBN: 1-57590-092-0. 105. Szeliga MJ. Chapter 11: Stray current corrosion’ in Peabody’s Control of Pipeline Corrosion. Figure 11.5. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 214. ISBN: 1-57590-092-0. 106. Szeliga MJ. Chapter 11: Stray current corrosion’ in Peabody’s Control of Pipeline Corrosion. Table 11.1. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 215. ISBN: 1-57590-092-0. 107. Szeliga MJ. Chapter 11: Stray current corrosion’ in Peabody’s Control of Pipeline Corrosion. Figure 11.7. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 220. ISBN: 1-57590-092-0. 108. Bianchetti RL. Chapter 12: Construction practices’ in Peabody’s Control of Pipeline Corrosion. Figure 12.1. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. p. 240. ISBN: 1-57590-092-0.

CHAPTER

Modeling – External Corrosion

10

10.1 Introduction No corrosion takes place on the external surface of the infrastructure as long as the mitigation strategies (e.g., coating and cathodic protection discussed in Chapter 9) work properly. However, corrosion does take place when the coating deteriorates and when the cathodic protection does not adequately protect the areas where this occurs. The corrosion professionals require a predictive tool to schedule times at which coatings should be repaired, cathodic protection system should be serviced, and material of construction should be replaced. This chapter discusses the models used to predict the behavior of corrosion control strategies and the rate of corrosion when these strategies fail.

10.2 Modeling corrosion control As discussed in Chapter 9, external surfaces are protected from corrosion as long as corrosion control measures (coatings and cathodic protection) are effective. However, coatings may undergo different modes of failure during service. Some of these allow the cathodic protection current to reach the metallic surface but others do not. For this reason, several laboratory methodologies have been developed to simulate different failure modes of coatings. Standards have been developed that require a coating to be evaluated in these tests before it is selected for field use. Thus, the effectiveness of a corrosion control strategy can be modeled using the following steps: • • • • • •

Analyze the failure modes of coatings experienced in the field. Develop laboratory methodologies to simulate field failure modes. Evaluate the performance of the coating by using these laboratory methodologies. Compile data from these laboratory methodologies to model the behavior of the coating in the field. Integrate the laboratory data with field operating conditions to adopt the model. Account for the effects of secondary coatings (girth weld coatings, metallic coatings, thermal insulators, and concrete coatings).

10.2.1 Modes of failure of external polymeric coatings As long as coatings are intact and completely insulate the infrastructure from the environment, corrosion does not occur. But over their service life coatings, undergo changes which affect their Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00010-8 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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ability to protect the infrastructure from the environment. Any change in the chemical, physical, or electrochemical properties of an external coatings can be considered as a failure. Some failures are catastrophic, whereas others have little or no effect on the coating performance.

10.2.1a Modes of failure The eight most common failure modes of external polymeric coatings are discussed in this section.1

i. Air permeation Polymeric coatings are permeable because of the presence of pores at the molecular level. Gas can permeate through the pores. When gases permeate through a coating that is well bonded to a metallic structure, the pressure within the coating increases. At high levels of permeation, the pressure buildup may be reduced by the liberation of gases; resulting in the disbondment of the coating. At low levels of permeation, equilibrium is reached without any chemical or physical changes to the coating.

ii. Water permeation In addition to gases, water and salts can also penetrate the coating. Permeation is further facilitated by osmosis and electro-osmosis. When a semi-permeable membrane (e.g., polymeric coatings) separates solutions of different concentrations, the water permeates from the dilute solution side to the concentrated solution side to equalize the concentrations on both sides of the membrane. This process is called osmosis. The presence of salts on the contaminated steel surface results in the development of a process of osmosis. If osmosis is facilitated by the electrical current flow caused by the application of cathodic protection (CP), it is called electro-osmosis.

iii. Loss of adhesion The adhesion of a coating is a measure of the degree of attachment between the coating and the metallic surface. Adhesion is a force that keeps the coating on the metallic surface. It may be due to chemical, physical, and mechanical interactions. When these interactions diminish, the coating loses its adhesion.

iv. Loss of cohesion The cohesion of a coating is a measure of the degree of attachment within the coating which holds it together as one entity. A coating with a cohesive bond strength that is higher than its adhesive bond strength will break away from the metallic surface and form a free-standing coating (Figure 10.1). On the other hand, a coating with a cohesive bond strength that is less than its adhesive bond strength will

Coating separated from Steel External Pipeline Coating

Adhesion failure

Pipeline Steel

FIGURE 10.1 Schematic Diagram Showing Adhesion Failure of a Coating.1

10.2 Modeling corrosion control

623

Coating partly separated from Steel Cohesion Failure Pipeline

Part of Coating Adhering onto steel

Steel

FIGURE 10.2 Schematic Diagram Showing Cohesive Coating Failure.1

break within itself, leaving part of the coating on the surface and part off the surface (Figure 10.2). The latter mode of failure is less severe than the former because the metallic surface is protected by the part of the coating remaining on its surface.

v. Blistering Swelling of coatings due to water absorption causes a lateral distortion of the coating with respect to the metallic surface. Stress at the coating/steel interface then blisters the coating. If CP penetrates through the blistered coating, then the pH of the solution will be in the alkaline range (above 7). Under blistered coatings, pHs as high as 12 have been observed.2

vi. Disbondment and passage of cathodic protection Cathodic disbondment occurs when the cathodic reaction at the metal surface, caused by cathodic protection, reduces the adhesion of coating. Factors including pH, cathodic potential, stability of the interfacial oxide, substrate surface roughness, defect geometry, coating formulations, cyclic wetting and drying, and water uptake contribute to this process. The extent of disbondment depends on the type of coating, the species in the environment, the morphology of the disbondment, and the level of CP. Coating disbondment may lead to the formation of crevices. When access to the inside of a crevice is restricted, the chemistry of the solution within the crevice is significantly different than that of the ground water. This is because the solution is trapped within the crevice and there is little or no exchange with ground water. In this situation, the corrosion rate decreases rapidly and remains low. On the other hand, when there is an exchange of solution, i.e., when the ground water flows freely between the coating and the pipe, corrosion continues to occur and CP is required to control it. Cathodic protection can be effective if the ground water is highly conductive and if the crevice has a large opening. In such situations, the pH of the solution inside the crevice is alkaline (8–12) even when the ground water just outside the crevice is neutral. The increase in pH results from the consumption of hydrogen ions and the generation of hydroxyl ions in the cathodic reaction. Maintaining a high pH environment helps to protect the steel beneath a disbonded coating. However interruption or removal of CP may decrease the pH and increase susceptibility to corrosion.

vii. Disbondment and prevention of the passage of cathodic protection Generally this happens if the disbonded coating is impermeable to CP and if the soil is dry, i.e., solution resistance is high. If CP does not penetrate through the disbonded coating then corrosion occurs

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10000

Current density, uA/m2

Asphalt enamel

1000 Asphalt enamel Coal tar enamel

100 Polyethylene tape

10 Epoxy

1 0

5

10

15 20 Duration, Years

25

30

35

FIGURE 10.3 Cathodic Current Demand as a Function of Time for Various Coatings.4

in trapped water beneath it even when the pipe to soil potential meets the CP application criteria (see section 9.3.4).

viii. Increase of cathodic protection current It is difficult to cathodically protect a bare metal surface, because the magnitude of the current required is very large. A good quality coating decreases the current required to a minimum amount. External coating and cathodic protection thus work synergistically to mitigate pipeline corrosion. Polymeric coatings contain pores at a microscopic level, formed during crystal formation/growth.3 These pores act as potential locations for disbondment to initiate. During construction, several layers (indicated as minimum thickness) of coating are applied to reduce the pores, and care is taken to avoid damaging the protective coatings. As the coating ages, the microscopic pores enlarge to macroscopic level, i.e., holidays are formed. Sometimes coatings are accidentally removed or damaged. Consequently, during service the CP current demand continues to increase until it is no longer economically feasible to protect the pipeline. In one study, six coatings (fusion bonded epoxy (FBE), coal tar enamel, asphalt enamel, polyethylene tape, asphalt mastic and urethane) were evaluated over a period of 25 years .4 For most of these, the CP current requirement was initially low, but increased progressively with time (Figure 10.3).

10.2.1b Ranking of failure modes Although any chemical, physical, or electrochemical changes in the coating may be considered as a failure, not all changes affect the ability of coatings to protect the infrastructure. In an ideal situation, the polymeric coating protects the infrastructure and, when it fails, the CP acts as the backup. Only when both defense mechanisms fail would the infrastructure become susceptible to corrosion.

10.2 Modeling corrosion control

625

The worst case scenario of coating failure is where the coating no longer protects the infrastructure, and, in addition, it prevents the CP from doing so. This is #1 in terms of the impact of the failure on the protection of the infrastructure. The presence of holidays is the #2 cause of failure, because the CP current increases as the holiday size and number increase. Formation of disbondment behind a coating that passes CP is the third in the failure mode ranking. In such a case, the coating has failed but CP can act as the backup. The diffusion of hydroxyl ions is limited (i.e. the reaction is diffusion control (see section 5.2)) by the disbonded coatings, hence the amount of CP current required is small. Formation of blisters is the fourth ranked cause of coating failure. This failure is caused by the penetration of water, but the CP current can also penetrate through the blisters and can therefore prevent corrosion at this location. This case is better than a disbonded coating protected with CP because the CP reaches the steel surface readily and uniformly. Loss of adhesion makes the coating unable to perform its primary function; i.e., to cover the steel surface. This is the fifth ranked mode of failure. Loss of cohesion is the sixth because at least part of the coating still covers and hence protects the steel surface. Water permeation through the coating is the seventh ranked failure mode. This mode of failure establishes an electrochemical cell (see section 5.2), creating conditions for corrosion to occur. The permeation of gases may break certain chemical bonds, but will have limited effect on the overall performance of the coating. This is the eighth ranked failure mode.

10.2.2 Laboratory methodologies Laboratory methodologies play a key role in developing coatings, in evaluating them, and in predicting their behavior in the field. Typically, when a new coating is formulated, its behavior is evaluated for its intended purpose by a laboratory methodology. The laboratory methodology is developed to simulate the field conditions to which the coatings will ultimately be exposed. When a coating passes the test, it, along with the test methodology, is passed along to the user for further evaluation. Once the coating is accepted by the industry in general, then standard making organizations convert the test methodology into a standard. Therefore, the success of a coating also results in the success of the test methodology used in evaluating the coating. Since the 1940s, several different polymeric coatings have been used to protect oil and gas infrastructure. Some laboratory methodologies for evaluating them are as old as the coatings themselves. In 1958, a ten-year coating evaluation program was completed.5 The main objective of this program was to develop methodologies suitable for the evaluation of polymeric coatings. Methodologies were developed for evaluating one property of a coating at a time, under controlled and reproducible conditions. The coating properties that could be assessed by these methodologies were: water adsorption, adhesion, electrical resistance, resistance to deformation, impact resistance, bending resistance, soil resistance, resistance to petroleum oil, and resistance to the effects of cathodic protection. Tests were also conducted in the field, but these were found to be lengthy and precise results could not be obtained due to the existence of several variables. For this reason, this study could not establish a correlation between laboratory results and field performance.

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Table 10.1 First Set of Industry Standards to Evaluate External Polymeric Coatings No.

Property

ASTM Standard

Year in which the Standard Was First Published

1 2 3 4 5 6 7 8 9 10 11 12

Abrasion resistance Cathodic disbondment Water penetration Bendability Weathering (Outdoor exposure) Impact (Limestone drop) Impact (Falling weight) Penetration resistance Joint, Fitting, and Patch materials Disbondment (Direct soil burial) Chemical resistance Cathodic disbondment (Elevated or cyclic temperatures) Patch materials

G6 G8 G9 G 10 G 11 G 13 G 14 G 17 G 18 G 19 G 20 G 42

1977 1972 1972 1972 1972 1972) 1972 1972 1972 1972 1972 1975

G 55

1977

13 )

Has since been withdrawn

In 1964, the industry started the development of standardized laboratory methodologies to evaluate pipeline coatings. Between 1964 and 1977, nearly 200 laboratory methodologies for non-metallic materials were reviewed for their potential in evaluating pipeline coatings. Many methodologies could not be adapted and were, therefore, rejected. Others were dropped from further consideration because they produced data of marginal value. The laboratory methodologies retained for critical evaluation were those that yielded definitive data within the first 3 months, would not require more than 18 months to complete, and most could be completed in 30 days. The most promising of these methodologies were subjected to an intensive inter-laboratory, round-robin testing. Additional methodologies were rejected at this level, principally due to lack of precision. By 1978, this systematic process produced the first set of coatings standards for the oil and gas industry. Table 10.1 lists the 13 standard test methods to determine the properties of non-metallic coatings applied to steel pipe. Since then, several further laboratory methodologies to evaluate coatings have been standardized, and new methodologies are continuously being developed. The following sections discuss the standard and non-standard laboratory methodologies used to evaluate polymeric coatings used to protect oil and gas infrastructure.

10.2.2a Standard methodologies The standards for evaluating coatings for protecting external surfaces may be broadly divided into three types: design standards, coating evaluation standards, and property evaluation standards. Type 1: design standards. These standards provide guidelines for designing external protection of oil and gas infrastructure using polymeric coatings and CP. They refer to Type 2 standards to evaluate a

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627

specific coating type and to Type 3 standards to evaluate a specific coating property. The standards include: • • •

NACE RP0169, ‘Control of External Corrosion on Underground or Submerged Metallic Piping Systems’ Canadian Standards Association (CSA) Z662, ‘Oil and Gas Pipeline Systems (Annex L: Test Methods for Coating Property Evaluation)’ ISO 15589, ‘Petroleum and Natural Gas Industries – Cathodic Protection for Pipeline Transportation Systems’

Type 2: coating evaluation standards. Over the past 80 years, several polymeric coatings have been used (see section 9.2 for a discussion of coatings). Commonly used coatings include coal tar, asphalt, polyethylene tape, FBE, epoxy, urethane, two layer, three layer, and composite. The properties of these coatings vary considerably, so the evaluation criteria for each type of coating are different. Coating evaluation standards provide general information about a generic coating, definition of the terms, raw materials to produce the coating, performance criteria, application procedure, procedures to inspect and test the product, repair procedures, and procedures to handle, store, and ship the coatings. The standards include: Coal tar coatings • •

NACE Standard RP0399, Standard Recommended Practice, ‘Plant-Applied External Coal Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’. American National Standards Institute/American Water Works Association (ANSI/AWWA) C203, AWWA Standard for, ‘Coal Tar Protective Coatings and Linings for Steel Water PipelinesEnamel and Tape-Hot Applied’. Tape

• •

NACE Standard MR0274, Standard Material Requirements, ‘Material Requirements for Polyolefin Cold-Applied Tapes for Underground or Submerged Pipeline Coatings’. ANSI/AWWA C214, AWWA Standard for, ‘Tape Coating Systems for the Exterior of Steel Water Pipelines’. FBE

• • • •

NACE Standard RP0394, Standard Recommended Practice, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’. CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’. ISO 21809, Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries, Part 2: Fusion Bonded Epoxy Coatings. ANSI/AWWA C213, AWWA Standard for, ‘Fusion Bonded Epoxy Coating for the Interior and Exterior of Steel Water Pipelines’. Two layer

• •

NACE Standard RP0185, Standard Recommended Practice, ‘Extruded Polyolefin Resin Coating Systems with Soft Adhesives for Underground or Submerged Pipe’. CSA – Z245.21, ‘External Polyethylene Coating for Pipe’, Type A1 and A2.

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CHAPTER 10 Modeling – External Corrosion

ISO 21809, Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries, Part 4: Polyethylene Coatings (Two Layer PE). ANSI/AWWA C215, AWWA Standard for, ‘Extruded Polyolefin Coatings for the Exterior of the Steel Water Pipelines’, 1999 (1988). Three layer

• •

•

CSA – Z245.21, ‘External Polyethylene Coating for Pipe’, Type B1. ISO 21809, Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, and Natural Gas Industries, Part 1: Polyolefin coatings (Three Layer Polyethylene and Polypropylene). Composite CSA – Z245.21, ‘External Polyethylene Coating for Pipe’, Type B2.

Table 10.2 lists coating evaluation standards developed by various standard making associations. It should be noted that there are several other associations/organisations that develop standards and standards presented in this chapter are revised/updated periodically. For these reasons, the standards listed in the chapter must be considered as examples of the type of standards available, but not as the exclusive list of standards. Type 3: Property evaluation standards. The overall performance of a coating system depends on more than 100 individual properties. The property evaluation standards provide guidelines to individually evaluate each property. These standards may be broadly classified into five categories: steel, coating, steel-coating interface, coating-environment interface, and steel-environmental interface (Figure 10.4). Several associations develop standards. Of which ASTM, CSA, NACE, and AWWA are predominantly referred to in the oil and gas industry. Some coating properties for which different standards have essentially similar requirements include blast cleaning, surface profile, penetration resistance, chemical resistance, dielectric strength, electrical conductivity, and impact resistance. Properties for which standards from different organizations have different requirements include cathodic disbondment, adhesion, cohesion, water permeation, flexibility, and abrasion resistance. These properties are also important for coating performance, so harmonization of the standards used to evaluate these properties would be very useful. Properties for which no adequate standards are available include quantification of visual and non-visual contaminations of steel surface, pH measurements at the disbonded coatings, and blister formation. Properties for which adequate standards are available but are not included in Type 2 coating standards include: microbial resistance, weathering, gas permeation, and freeze thaw stability. The following section discusses standards for evaluating individual properties.

i. Steel The steel surface plays an important role in the performance of a coating. Surface imperfections, both physical and chemical, can cause premature failure. Before the application of coatings, the steel surface is blast cleaned, the surface profile is established, and physical and chemical contaminants are removed. The test methodologies and standards for determining steel properties are discussed in this section. Blast cleaning. The primary functions of blast cleaning before coating are (a) to remove physical material from the surface that can cause early failure of the coating system, and (b) to create a suitable

Table 10.2 Type 2 Coating Standards Developed by Various Associations Coating Standard Coating Type

)))

NACE RP0399 NACE RP0399 NACE MR0274 NACE RP0394 ANSI/AWWA C210)) ANSI/AWWA C222)) NACE RP0185 CSA Z245e21.B1) CSA Z245e21.B2) NACE RP0375

CSA Z662

ISO 15589 )))

ANSI/AWWA C203 ANSI/AWWA C203)) ANSI/AWWA C214)) CSA Z245e20.1A ANSI/AWWA C210)) ANSI/AWWA C222)) CSA Z245e21.A2 CSA Z245e21.B1 CSA Z245e21.B2 NACE RP0375)

AWWA )))

NACE RP0399 NACE RP0399) NACE MR0274) ISO 21809e2 ISO 21809e2)))) ISO 21809e2)))) ISO 21809e4 ISO 21809e1 CSA Z245e21.B2) NACE RP0375)

ANSI/AWWA ANSI/AWWA ANSI/AWWA ANSI/AWWA ANSI/AWWA ANSI/AWWA ANSI/AWWA ANSI/AWWA N/A N/A

C203))) C203 C214 C213 C210 C222 C215 C215)))))

For the purpose of developing a model: Coating Standard is not developed by this association for this type of coating. A standard from a different association is used AWWA develops standards for water pipelines. They are used in the oil and gas industry when equivalent standards are not available from NACE, CSA, or ISO ))) Coal tar coating standard is used for asphalt coating )))) FBE coating standard is used for epoxy and urethane coatings ))))) 2-Layer coating standard is used for 3-layer coating )

))

10.2 Modeling corrosion control

Asphalt Coal Tar Tape FBE Liquid Epoxy Liquid Urethane 2-Layer 3-Layer Composite Wax

NACE SP0169

629

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CHAPTER 10 Modeling – External Corrosion

Steel/Soil Interface

Steel Steel/Coating Interface Coating

Coating/ Soil Interface

FIGURE 10.4 Schematic Diagram Describing Locations Where Change in Coating Property May Occur.

surface profile that will enhance the adhesion of the coating. Standards describing the procedure for cleaning include: • • • • • • • • • • • • •

SSPC-SP 1, ‘Solvent Cleaning’. SSPC-SP 2, ‘Hand Tool Cleaning’. SSPC-SP 3, ‘Power Tool Cleaning’, 2004 (1982). NACE No.1/SSPC-SP 5, Joint Surface Preparation Standard, ‘White Metal Blast Cleaning’. NACE No.2/SSPC-SP 10, Joint Surface Preparation Standard, ‘Near-White Metal Blast Cleaning’. NACE No.3/SSPC-SP 6, Joint Surface Preparation Standard, ‘Commercial Blast Cleaning’. NACE No.4/SSPC-SP 7, Joint Surface Preparation Standard, ‘Brush-Off Blast Cleaning’. NACE No.5/SSPC-SP 12, Joint Surface Preparation Standard, ‘Surface Preparation and Cleaning of Metals by Waterjetting Prior to Recoating’. NACE No.8/SSPC-SP 14, Joint Surface Preparation Standard, ‘Industrial Blast Cleaning’. SSPC-SP COM, Surface Preparation Commentary for Steel and Concrete Substrates. ISO 8504–1, Preparation of Steel Substrates before Application of Paints and Related Products – Surface Preparation Methods, ‘General Principles’. ISO-8504–2, Preparation of Steel Substrates before Application of Paints and Related Products – Surface Preparation Methods, ‘Abrasive Blast Cleaning’. ISO-8504–3, Preparation of Steel Substrates before Application of Paints and Related Products – Surface Preparation Methods, ‘Hand- and Power Tool Cleaning’.

Surface preparation depends on the type of coating. Table 10.3 presents surface preparation requirements for different coatings as recommended by Type 2 standards. Different coating evaluation standards (Type 2 standards) essentially require the same surface preparation for a generic coating type. However, some standards require solvent cleaning before blast cleaning whereas others do not. Surface profile. Blast cleaning produces different surface profiles. The profile to which a steel surface should be blasted depends on the type and thickness of the coating. Table 10.4 presents surface profile requirements for various coatings as recommended by Type 2 standards. The standards describing procedure to measure surface profiles include: •

SSPC-VIS 1 ‘Visual Standard for Abrasive Blast Cleaned Steel (Standard Reference Photographs)’.

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Table 10.3 Requirements of Surface Preparation for Various Coatings Coating As required by (standards) Asphalt Coal tar

Tape FBE

2-layer

Surface Preparation Requirements NACE

CSA

ISO

AWWA

N/A (SSPC-SP1) SSPC SP6/NACE #3 or ISO 8501e1 Not specified

N/A N/A

N/A N/A

N/A

N/A

SSPC-SP 10/NACE #2

ISO 8501e1

N/A (SSPC-SP1) SSPC SP6/NACE #3/SSPC-SP 10/NACE #2 (SSPC-SP1) SSPC-SP 6/NACE #3 (SSPC-SP1) SSPC-SP 10/NACE #2

SSPC-SP 6/NACE#3 SSPC-SP 10/NACE #2 SSPC-SP 10/NACE #2

ISO 8501e1

SSPC-SP 10/NACE #2 or ISO 8501e1 SSPC-SP 6/NACE#3

3-layer Composite

ISO 8501e1

(SSPC-SP1) SSPC-SP 6/NACE#3 N/A

N/A

N/A

Table 10.4 Requirements of Surface Profiles for Various Coatings Coatings As required by (standards) Asphalt Coal tar Tape FBE

•

NACE N/A 1.5e3.5 (38e89) Not specified

3-layer

1.5 (38) 1.5e4.0 (38e102) N/A

Composite

N/A

2-layer

•

Surface Profile Requirements, mils (mm) CSA N/A N/A

ISO N/A N/A

N/A

N/A

1.5e4.5 (38e110) 1.5e4.5 (38e110) 1.5e4.5 (38e110) 1.5e4.5 (38e110)

2.0e4.0 (50e100) w1.5e4.0 (40e100) 2.0e4.0 (50e100) N/A

AWWA N/A 1.5e3.5 (38e89) 1e3 (25e75) 1.5e4.0 (38e102) 1.5e4.0 (38e102) N/A N/A

NACE RP0178 Fabrication Details, ‘Surface Finish Requirements and Proper Design Consideration for Tanks and Vessels to be Lined for Immersion Service’. ASTM D 4417 Standard Test Method; ‘Field Measurements of Surface Profile of Blast Cleaned Steel’.

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• •

•

•

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NACE RP0287 Recommended Practice for ‘Field Measurement of Surface Profile of Abrasive Blast Cleaned Steel Surface Using a Replica Tape’. ISO 8502–3 Preparation of Steel Substrates Before Application of Paints and Related Products Tests for the Assessment of Surface Cleanliness, ‘Assessment of Dust on Steel Surfaces Prepared for Painting (Pressure-Sensitive Tape Method)’. ISO 8503–1 Preparation of Steel Substrates Before Application of Paints and Related Products – Surface Roughness Characteristics of Blast Cleaned Steel Substrates, ‘Specifications and Definitions for ISO Surface Profile Comparators for the Assessment of Abrasive Blast Cleaned Surfaces’. ISO 8503–2 Preparation of Steel Substrates Before Application of Paints and Related Products Surface Roughness Characteristics of Blast Cleaned Steel Substrates, ‘Method for the Grading of Surface Profile of Abrasive Blast Cleaned Steel - Comparator procedure’. ISO 8503–4 Preparation of Steel Substrates Before Application of Paints and Related Products – Surface Roughness Characteristics of Blast Cleaned Steel Substrates, ‘Method for the Calibration of ISO Surface Profile Comparators and for the Determination of Surface Profile – Stylus Instrument Procedure’.

The criteria of a surface profile for a generic coating required by the standards of different organizations are similar. In all the standards, three methods of measuring the surface profile are described: comparison with standard surface profiles, measurements with fine-pointed probes, and replica tape measurements. Visual contamination. Dust, corroded materials, varnish, previously applied coatings, and byproducts of abrasive cleaning constitute visual contamination. They prevent the coating from adhering well onto the substrate. Visual contamination has caused failures of field pipes.8,9 The standards describing procedure to remove visual contaminations include: •

•

NACE Recommended Practice RP0394 ‘Standard Recommended Practice, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’, 1994, Appendix P. Canadian Standards Association CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’, Section 12.9.

Non-visual contamination. Non-visual contamination consists of chemicals deposited on the metallic surface. Steel contaminated with chemicals undergoes corrosion in the presence of humidity. For this reason non-visual contamination should be removed from the steel surface before applying the coating. Chemical species interfering with coating applications include chlorides, sulfates, and nitrates. The tolerance level for contamination varies with the coating. For example, the tolerance limit of FBE to chlorides, sulfates, nitrate, and ferrous ion is below 5, 7, 9, and 24 g/cm2 respectively.10 Phosphoric acid treatment is used to reduce the effects of non-visual contamination.11,12 Phosphoric acid treatment after blasting gives better adhesion and lower cathodic disbondment. This has been attributed to the surface pattern provided by the acid giving better interaction between the pipe surface and the coating. The standards describing procedures for determining non-visual contaminants include: • •

SSPC-TU 4, ‘Field Methods for Retrieval and Analysis of Soluble Salts on Substrates’. ASTM D4940, Standard Test Method, ‘Conductive Analysis of Water Soluble Ionic Contamination of Blasting Abrasives’.

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•

• • •

633

ISO 8501–1 Preparation of Steel Substrates Before Application of Paints and Related Products, ‘Rust grades and preparation grades of uncoated steel substrates and of steel substrates after overall removal of previous coatings’. ISO 8502–2 Preparation of Steel Substrates before Application of Paints and Related Products, ‘Laboratory Determination of Chloride on Cleaned Surfaces’. ISO 8502–6 Preparation of Steel Substrates before Application of Paints and Related Products, ‘Extraction of Soluble Contaminants for Analysis – The Bresle Method’. ISO 8502–9 Preparation of Steel Substrates before Application of Paints and Related Products, ‘Field Method for the Conductometric Determination of Water Soluble Salts’.

Although the effects of surface non-visual contamination on FBE coatings have been widely studied, its importance is not fully recognized in Type 2 standards. No standard is currently available to specify limits for non-visual contamination.

ii. Coating Both material properties and the quality control that is practiced during application influence the reliability of the coating. Several standard tests are performed to evaluate the properties of both the raw materials and the applied coating. These standards are classified as common (to all coatings) or specific (to a particular coating), and are discussed in the following paragraphs. Thermal conductivity. The temperature profile of the oil and gas infrastructure depends primarily on the operating conditions and to some extent on the external weather conditions. The thermal conductivity provides information on the rate at which the heat is transferred between the internal and external surfaces of the infrastructure across the coating, i.e., the heat transferability of the coating. Standards providing procedures for evaluating thermal conductivity include: •

ASTM E1225, Standard Test Method; ‘Thermal Conductivity of Solids by Means of the GuardedComparative-Longitudinal Heat Flow Technique’.

Type 2 standards do not, however, consider thermal conductivity as important for coating performance. Only standards ANSI/AWWA C203 and NACE RP0190 for coal tar coatings require the measurement of thermal conductivity. Dielectric strength. Polymeric coatings are electrical insulators and have a high dielectric strength. The dielectric strength of the coating is defined as the voltage gradient at which it starts to conduct. The standards providing procedures for determining dielectric strength include: • • •

ASTM D1000, Standard Test Method; ‘Pressure-Sensitive Adhesive-Coated Tapes Used for Electrical and Electronic Applications’. ASTM D149, Standard Test Method; ‘Dielectric Breakdown Voltage and Dielectric Strength of Solid Electrical Insulating Materials at Commercial Power Frequencies’. ASTM D495, Standard Test Method; ‘High-Voltage, Low-Current, Dry Arc Resistance of Solid Electrical Insulation’.

Table 10.5 presents the dielectric strength requirements for various coatings as stated in Type 2 standards. Electrical resistivity (or Electrical conductivity). The electrical resistivity of coatings depends on the rate and extent of polymerization, glass transition temperature, and dielectric properties. The electrical

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Table 10.5 Requirements of Dielectric Strength for Various Coatings Coatings As required by (standards) Asphalt Coal tar

Tape

FBE

2-layer

3-layer Composite

Dielectric Strength NACE

CSA

ISO

AWWA

N/A > 10 V/mm (250 V/mil) (ASTM D49) 18,000e22,000 V/mm (450 to 550 V/mil) (ASTM D1000) Not specified

N/A N/A

N/A N/A

N/A Not specified

N/A

N/A

400 V/mil (15 V/mm)

Not specified

Not specified

20 kV/mm (500V/mil) (ASTM D149) N/A N/A

Not specified

Not specified

1,000 V/mil (39.4 V/mm) (ASTM D149) 20 kV/mm (500 V/mil)

Not specified Not specified

Not specified N/A

N/A N/A

resistivity of polymeric coatings is normally high (1014 ohms). Polymeric coatings protect the infrastructure from corrosion because of their high electrical resistance; however the electrical resistance decreases as water containing ionic species enters the coating. Therefore electrical resistivity is used as a measure of coating performance. The standards that provide procedures for evaluating electrical conductivity include • •

ASTM D257, Standard Test Method; ‘DC Resistance or Conductance of Insulating Materials’. ASTM C611, Standard Test Method; ‘Electrical Resistivity of Manufactured Carbon and Graphite Articles at Room Temperature’.

Only a few Type 2 standards recognize the importance of measuring the electrical resistance of the coating. Table 10.6 presents the electrical resistance requirements for various coatings. Indentation hardness. Indentation hardness is a measure of the resistance of coatings to mechanical damage during storage, construction, and backfilling. The standards providing procedures to determine hardness include: • • • • •

ASTM D1474, Standard Test Method; ‘Indentation Hardness of Organic Coatings’. ASTM D2240, Standard Test Method; ‘Rubber Property-Durometer Hardness’. ASTM D2583, Standard Test Method; ‘Indentation Hardness of Rigid Plastics by Means of a Barcol Impressor’. ASTM D785, Standard Test Method; ‘Rockwell Hardness of Plastics and Electrical Insulating Materials’. ASTM D3363, Standard Test Method; ‘Film Hardness by Pencil Test’.

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Table 10.6 Electrical Resistivity (Or Electrical Conductivity) for Various Coatings Coatings As required by (standards) Asphalt Coal tar

Electrical Resistivity NACE

CSA

ISO

AWWA

N/A N/A

N/A N/A

N/A Not specified

N/A

N/A

500,000 MU

FBE

N/A 1  1014 ohm-cm (ASTM C611) 450,000e 550,000 MU Not specified

Not specified

Not specified

2-layer 3-layer Composite

Not specified N/A N/A

Not specified Not specified Not specified

Not specified Not specified N/A

1.1 x1015 (ASTM D257) Not specified N/A N/A

Tape

Table 10.7 presents the indentation requirements for polyethylene-based coatings. These standards all require that the indentation is measured using ASTM D2240 standard. Type 2 standards for other coatings do not require the measure of indentation. Penetration resistance. The penetration resistance of a coating is a measure of resistance of the coating to loading from soil and other buried objects. During the test, the depth or penetration as a result of the blunt rod load is measured with a micrometer depth gauge. The standards providing procedures for determining penetration resistance include: • • •

ASTM D5, Standard Test Method; ‘Penetration of Bituminous Materials’. ASTM G17, Standard Test Method; ‘Penetration Resistance of Pipeline Coatings (Blunt Rod)’. ASTM D937, Standard Test Method; ‘Cone Penetration of Petroleum’.

Table 10.7 Requirements of Indentation Hardness for Various Coatings Coatings As required by (standards) Asphalt Coal tar Tape FBE 2-layer

Indentation Hardness NACE

CSA

ISO

AWWA

Composite

N/A

N/A N/A N/A Not specified Min. 45 Shore D (ASTM D2240) Min. 50 Shore D (ASTM D2240) Min. 60 Shore D (ASTM D2240)

N/A N/A N/A Not specified Min. 45 Shore D (ISO 868) Less than 0.4 mm (Annex F) N/A

N/A Not specified Not specified Not specified N/A

3-layer

N/A Not specified Not specified Not specified Min. 60 Shore D (ASTM D2240) N/A

N/A N/A

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CHAPTER 10 Modeling – External Corrosion

Table 10.8 Requirements of Penetration Resistance for Various Coatings Coatings As required by (standards) Asphalt Coal tar

Penetration Resistance NACE

CSA

ISO

AWWA

N/A N/A

N/A N/A

N/A

N/A

Not specified Not specified

Not specified Not specified

N/A 5e55 at 50e100 g/s (or 1.8e3.53 oz/s) at 25e46 C (ASTM D5) 25% with no holiday at 22 C (ASTM G17) < 10% at 60 C (ASTM G17) 2.5e12 mm at 25 C, 100 g/5 s (ASTM G5)

3-layer

N/A 2e55 at 50e100 g/s (or 1.8e3.53 oz/s) (ASTM D5) 20% (or 30%) with no holiday at 22 C (60 C) (ASTM G17) < 10% at 93 C (ASTM G17) 3.0e12.0 mm (0.12 to 0.47 in.) (ASTM D5) N/A

Composite

N/A

Not specified Not specified

Not specified N/A

Tape

FBE 2-layer

N/A N/A

Table 10.8 presents the penetration resistance requirements as described in Type 2 standards. Water permeation. Coatings function as a physical barrier, isolating the metallic structure from moisture. Penetration of water is the first step in the development of corrosion cell (see section 5.2 for details). Therefore it is important to detect the permeation of water. To test water permeation into the coating, samples are immersed in an aqueous electrolyte for a period of time, and changes in the electrical properties are observed by several methods.13 The standards providing procedures for measuring water permeation include: • • • • • •

ASTM D570, Standard Test Method; ‘Water Absorption of Plastics’. ASTM G9, Standard Test Method; ‘Water Penetration into Pipeline Coatings’. ASTM E96, Standard Test Method; ‘Water Vapor Transmission of Materials’. ASTM F372, Standard Test Method; ‘Water Vapor Transmission Rate of Flexible Barrier Materials Using an Infrared Detection Technique’. ASTM D95, Standard Test Method; ‘Water in Petroleum Products and Bituminous Materials by Distillation’. ASTM D2247, Standard Test Method; ‘Testing Water Resistance Coatings in 100% Relative Humidity’.

Table 10.9 presents water permeation resistance as required by Type 2 standards. Studies have indicated the usefulness of electrochemical impedance spectroscopy (EIS) for evaluating the water uptake of polymer coatings. However, the accuracy of this method and the method to analyze the results are still being established (see section 10.2.2b for more details).

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Table 10.9 Requirements of Water Permeation for Various Coatings Coatings As required by (standards) Asphalt Coal tar

Water Permeation NACE

CSA

ISO

AWWA

N/A 0.2% or 0.3 g/30 cm2 (0.1 oz/50 in.2) (ASTM D95) 6.5  103 perms (ASTM E96) 0.025 to 0.035 g/24 h/100 cm2 (0.15 to 0.25 g/24 h/100 in.2) (ASTM E96) 0.5% max. & Rating 1e3 0.02 wt % (ASTM D570)

N/A N/A

N/A N/A

N/A Not specified

N/A

N/A

0.5 to 0.6 % max

0.6 %

0.1 wt % max (ASTM D570)

0.05 to 0.1%

3-layer

N/A

0.5 % mass

Composite

N/A

0.1 wt % max (ASTM D570) 0.1 wt % max (ASTM D570)

0.2% by wt. (ASTM D570) 0.2% perm (1.15 x10 11 kg (Pa.s.m2) max. (ASTM E96) Rating 1e3 (AWWA C213) 0.2 % max. (ASTM D570) 0.2 % perm (1.1 x10 11 kg (Pa.s.m2) max. (ASTM E96) N/A

N/A

N/A

Tape

FBE 2-layer

Standard providing guidelines for use of EIS to evaluate coatings includes: •

ISO 16773, ‘Paints and Varnishes – Electrochemical Impedance Spectroscopy (EIS) on HighImpedance Coated Specimen’.

Gas permeation. Permeation of corrosive gases (e.g., oxygen and CO2) through coatings may facilitate the establishment of corrosion conditions. Therefore measure of gas permeation through coatings is useful. Standards describing procedure to measure gas permeation include: • • •

ASTM D1134, Standard Test Method; ‘Determining Gas Permeability Characteristics of Plastic Film and Sheeting’. ASTM D3985, Standard Test Method; ‘Oxygen Gas Transmission Rate Through Plastic Film and Sheeting Using a Coulometric Sensor’. ASTM D737, Standard Test Method; ‘Air Permeability of Textile Fabrics’.

However, none of the Type 2 standards require the evaluation of gas permeation through pipeline coatings.

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Table 10.10 Requirements of Chemical Resistance for Various Coatings Coatings As required by (standards) Asphalt Coal tar Tape FBE

2-layer 3-layer Composite

Chemical Resistance NACE

CSA

ISO

AWWA

N/A Not specified Not specified No blistering (HCl, HNO3, NaClþH2SO4, NaCl, distilled water, NaOH) No specification (ASTM G20) N/A N/A

N/A N/A N/A Not specified

N/A N/A N/A Not specified

N/A Not specified Not specified Not specified

Not specified

Not specified

N/A

Not specified Not specified

Not specified N/A

N/A N/A

Chemical resistance. Polymeric coatings should be resistant to chemical contamination from the environment. The resistance of polymeric coatings to chemicals is determined by visual examination and by measuring the change in mechanical properties. Standards providing procedures for determining the chemical resistance of polymeric materials include: • •

ASTM G20, Standard Test Method; ‘Chemical Resistance of Pipeline Coatings’. ASTM D543, Standard Test Method; ‘Resistance of Plastics to Chemical Reagents’.

Table 10.10 presents the chemical resistance requirements for various coatings, as stated in Type 2 standards. Blistering. Blister formation is one of the common modes of failure of FBE coatings when immersed in water. The tendency to form blisters is evaluated by immersing the coated samples in hot water. The standards providing procedures to evaluate the degree of blistering include: •

ASTM D714, Standard Test Method; ‘Evaluating Degree of Blistering of Paints’.

This test method employs photographic reference standards to evaluate the degree of blistering. Blistering is commonly observed in the field on FBE and epoxy coatings, yet no Type 2 standards require the evaluation of blister formation. Studies have indicated that the processes of formation and growth of blisters can be detected by monitoring acoustic emission signals, but this technology has not yet been reliably developed to evaluate the blister-forming tendency of coatings.14,15 Weathering. During construction, coated materials may be stored outdoors. Outdoor exposure may affect the coatings through ultraviolet radiation, rain water, and temperature. Effects of outdoor exposure are determined by comparing properties of samples kept indoors and exposed outdoors. The standards providing procedures for evaluating the susceptibility of coating to weathering include: •

ASTM G154, ‘Standard Practice for Operating Fluorescent Light Apparatus for UV Exposure of Non-metallic Materials’.

10.2 Modeling corrosion control

• • •

639

ASTM G151, ‘Standard Practice for Exposing Non-metallic Materials in Accelerated Test Devices that Use Laboratory Light Sources’. ASTM D822, ‘Standard Practice for Filtered Open-Flame Carbon-Arc Exposures of Paint and Related Coatings’. ASTM G11, Standard Test Method; ‘Effects of Outdoor Weathering on Pipeline Coatings’.

Type 2 coating standards specifying tests to evaluate the weathering tendency of coatings include NACE RP0185 (on extruded polyolefin that refers to ASTM G11) and ISO 21809–1. Cohesion. Adhesive forces bond a coating onto metal, whereas cohesive forces bond a coating with itself. Cohesion tests are similar to adhesion tests. But the specimen size and dolly diameter are larger so that area of sample under the dolly is far greater than the specimen’s cross-sectional area. This arrangement ensures that the coating fails by cohesion rather than by adhesion loss at the steel-coating interface.16 The test methods for evaluating cohesion are same as those for evaluating adhesion. The standards describing procedures for determining cohesion include: • • • • • • •

ASTM D1000, Standard Test Method; ‘Pressure-Sensitive Adhesive-Coated Tapes Used for Electrical and Electronic Applications’. ASTM D879, ‘Specification for Communication and Signal Pin-Type Lime Glass Insulators’. ASTM D1002, Standard Test Method; ‘Strength Properties of Adhesive in Shear by Tension Loading (Metal-to-Metal)’. ASTM D2197, Standard Test Method; ‘Adhesion of Organic Coatings by Scrape Adhesion’. ASTM D3359, Standard Test Method; ‘Measuring Adhesion by Tape Test’. ASTM D4541, Standard Test Method; ‘Pull-Off Strength of Coatings Using Portable Adhesion Testers’. CSA 245.21, ‘External Polyethylene Coating for Pipe’, Type A1 and A2.

Type 2 coating standards specify the same adhesion tests for evaluating cohesion as well (see Table 10.14). Environmental stress cracking resistance. Due to soil stress and wet-dry cycles, coatings may crack during operation. Therefore the stress cracking tendency of the coating should be evaluated. Standards providing procedures for determining the cracking resistance of coatings include: • •

ASTM D746, Standard Test Method; ‘Brittleness Temperature of Plastics and Elastomers by Impact’. ASTM D1693, Standard Test Method; ‘Environmental Stress Cracking of Ethylene Plastics’.

Table 10.11 presents the requirements of environmental stress cracking resistance at brittle temperatures for various coatings. A thin-walled substrate may curve or bend due to stress in the coating. The curvature (deflection) can be measured using an optical microscope (cantilever method) or a strain gauge.17 Computerized visual imaging based on high-resolution color image processing has been used to inspect stress in highway coatings, but the usefulness of this technique for oil and gas industry infrastructure has not yet been established.18 Resistance to oxidation. The environment surrounding a coating can range from a relatively inert, such as sandy soil, to more hostile, such as acidic marsh. When the infrastructure operates at elevated temperatures (up to 85 C (185 F)) in a hostile environment, antioxidants are incorporated into the coatings. It is advantageous to have a rapid and reliable laboratory method to determine the resistance to degradation of antioxidants. However, no standards (either Type 2 or 3) exist to evaluate or specify this property.

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Table 10.11 Requirements of Environmental Stress Cracking for Various Coatings Coatings

Environmental Stress Cracking Resistance

As required by (standards) Asphalt Coal tar Tape FBE

NACE

CSA

ISO

AWWA

N/A Not specified Not specified Not specified

N/A N/A N/A Not specified

N/A Not specified Not specified Not specified

2-layer

N/A

N/A

300 minimum for 100% lgepal (ASTM D1693)

3-layer

N/A

N/A N/A N/A Not specified 300 minimum for 100% lgepalÔ) (ASTM D1693) 300 minimum for 100% lgepalÔ) (ASTM D1693)

Not specified

Composite

N/A

300 minimum for Class A and 1000 minimum for Class B (ASTM D1693) N/A

300 minimum for 100% lgepalÔ) (ASTM D1693)

N/A

)

Non-ionic, non-denaturing detergent. Chemical name is: octylphenoxypolyethoxyethanol

Compressive properties. It is useful to determine the changes in mechanical properties of coatings, including modulus, under various loading conditions. Standards providing procedures to determine compressive properties include: •

ASTM D695, Standard Test Method; ‘Compressive Properties of Rigid Plastics’.

No Type 2 coating standard requires the measure of compressive properties. Thermal expansion. Coating materials should have a very low thermal expansion, so that the adhesion to steel is not lost. Standards providing procedures for determining thermal expansion include: •

ASTM D696, Standard Test Method; ‘Coefficient of Linear Thermal Expansion of Plastics Between 30 C and 30 C’.

No Type 2 coating however requires the measure of thermal expansion. Coating thickness. Coating thickness is an important factor in determining service life and cost. The thickness which gives optimum performance is established in development, so measuring coating thickness is important. Non-destructive methods, such as magnetic flux, are commonly used. The standards providing procedures for measuring coating thickness include: •

ASTM G12, Standard Test Method; ‘Non-destructive Measurements of Film Thickness of Pipeline Coatings on Steel’.

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Table 10.12 Requirements of Thickness of Various Coatings Coatings As required by (standards) Asphalt Coal tar

NACE

CSA

ISO

AWWA

N/A N/A

N/A N/A

N/A 1.1 (43)

Tape FBE 2-layer

N/A 3.0e3.6 (120e140) 1.250 (50) 0.3 (12) 0.79 (31)

N/A 0.3 (12) 0.7 e 1.25)

N/A 0.35 (w12) 0.75 to 2.00

3-layer Composite

N/A N/A

2e3.22) 0.67

Not specified N/A

0.75 (30) 0.406 (16) 0.79 (31) e 1.7 (69)) N/A N/A

)

• • •

Thickness, mm (mil)

varies with pipe diameter

ASTM D4138, Standard Test Method; ‘Measurement of Dry Film Thickness of Protective Coating Systems by Destructive Means’. ASTM D4414, Standard Test Method; ‘Measurement of Wet Film Thickness by Notch Gages’. Technical Association of the Pulp and Paper Industry, TAPPI T414, ‘Thickness (Caliper) of Paper, Paperboard, and Combined Board’.

Table 10.12 presents the coating thickness requirements for various coatings as required by Type 2 standards. Brittle temperature test. Polymer coatings lose elasticity, become brittle, and crack below certain temperatures. The standards providing procedures for measuring the brittleness temperature include: •

ASTM D746, Standard Test Method; ‘Brittleness Temperature of Plastics and Elastomers by Impact’.

Table 10.13 presents the brittle temperature requirements for various coatings as required by Type 2 standards. Composition. The coating composition is specific to the particular product. Some of its ingredients are confidential. However, composition tests may be used to ensure coating quality. For example, a good quality control test for FBE and epoxy coatings is a determination of the epoxy content of the resin. Standards providing procedures for determining epoxy content include: •

ASTM D1652, Standard Test Method; ‘Epoxy Content of Epoxy Resins’.

Sag. As the coating, ages it will sag, i.e., stretch and droop. This is especially the case for coal tar coatings. A good coating should not sag as it ages. Standards providing procedures for determining sagging tendency include: •

NACE Standard RP0399, Standard Recommended Practice, ‘Plant-Applied External Coal Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’.

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CHAPTER 10 Modeling – External Corrosion

Table 10.13 Requirements of Brittleness Temperature of Various Coatings Coatings As required by (standards) Asphalt Coal tar

Brittleness Temperature (Lowest Temperature at Which Coating Does Not Crack) NACE

CSA

ISO

AWWA

N/A N/A

N/A N/A

Tape FBE 2-layer

N/A 29 C ( 20 F) (AWWA C203) Not specified Not specified Not specified

N/A Not specified Not specified

3-layer

N/A

N/A

N/A

Composite

N/A

N/A Not specified 70 C or lower for F20 (ASTM D746) 70 C or lower for F20 (ASTM D746) 70 C or lower for F20 (ASTM D746)

N/A 29 C ( 20 F) (AWWA C203) Not specified Not specified Not specified

N/A

N/A

Pliability. Pliability is a measure of the strength of the external layer of a protective coating. Standards providing procedures for determining the pliability of a coating include: •

NACE Standard RP0399, Standard Recommended Practice, ‘Plant-Applied External Coal Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’.

Gel time. Measurement of the gel time is important for thermal set coatings, e.g., FBE and epoxy. Gel time is used to establish how quickly the coating should be applied after the ingredients are mixed. Standards providing procedures for measuring gel time include: • •

NACE Standard RP0394, Standard Recommended Practice, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’. CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’.

Particle size. The particle size of the raw material determines the density of the finished coating. For this reason the particle size of raw material is controlled and measured during the application of the coating. Standards providing procedures for measuring particle size include: •

CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’.

Total volatile content. The release of volatile substances from a coating leads to the formation of voids. In addition, environmental regulations may prohibit the release of certain volatile substances. For this reason, the volatile contents of the coating are kept to a minimum. Standards providing procedures for measuring the volatile contents of coating include: •

CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’.

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Porosity. A coating must be as non-porous as possible. A measure of porosity is a good quality control test for coatings. Standards providing procedures for measuring the porosity of coatings include: • • •

NACE Standard RP0394, Standard Recommended Practice, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’. CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’. ASTM D1134, Standard Test Method; ‘Determining Gas Permeability Characteristics of Plastic Film and Sheeting’ (Gas permeability of pipeline coatings can be used to evaluate their porosity).

Viscosity. During application, the coating should wet the substrate and should spread on it so that the surface is easily and quickly covered. The viscosity of the coating determines how easily this happens. Standards providing procedures for measuring the viscosity of coatings include: •

ASTM D4212, Standard Test Method; ‘Viscosity by Dip-Type Viscosity Cups’.

Flow. To apply a coating uniformly at different locations, and to maintain efficiency, a steady flow of coating through the spray gun should be maintained. A flow test is used to evaluate the flow of coating and is a good quality control test for thermoplastic coatings, e.g., two layer, three layer and composite. Standards providing procedures for measuring the flow of coatings include: •

ASTM D1238, Standard Test Method; ‘Flow Rates of Thermoplastics by Extrusion Plastometer’.

Softening point. During application, the ingredients of a coal tar coating are heated so that they become soft and fluid. Thus, the softening point is a measure of the fluid properties of coal tar coatings. Standards providing procedures for measuring the softening point of a coating include: • • •

ASTM D36, Standard Test Method; ‘Softening point of Bitumen (Ring-and-Ball Apparatus)’. ASTM E28, Standard Test Method; ‘Softening Point by Ring-and-Ball Apparatus’. ASTM D1525, Standard Test Method; ‘Vicat Softening Temperature of Plastics’.

Shelf life. Shelf life is a measure of the duration for which the raw material can be stored before application. The shelf life of a coating material is used as a quality control measure. Standards providing procedures for measuring the shelf life of coating raw materials include: •

CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’.

Filler content. Filler materials may be added to certain coating raw materials, especially for coal tar coatings. The filler content determines the properties and performance of the coating. Standards providing procedures for measuring the filler content of a coating include: •

ASTM D2415, Standard Test Method; ‘Ash in Coal Tar and Pitch’.

Density/specific gravity. The density of the raw materials is one of the properties which determines the quality of the coating; hence it is measured during manufacture of raw material and during the application of the coating. Standards providing procedures for measuring the density of coatings include: •

ASTM D 71, Standard Test Method; ‘Relative Density of Solid Pitch and Asphalt (Displacement Method)’.

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CHAPTER 10 Modeling – External Corrosion

ASTM D792, Standard Test Method; ‘Density and Specific Gravity (Relative Density) of Plastics by Displacement’. ASTM D1505, Standard Test Method; ‘Density of Plastics by the Density-Gradient Technique’.

Tear strength. Improperly applied thermoplastic coatings, such as coal tar coatings, may tear away. Therefore the tear strength is used as a quality control measure. The tear strength is measured both in the longitudinal and in the transverse directions. Standards providing procedures for measuring the tear strength of coatings include: •

NACE Standard RP0399, Standard Recommended Practice, ‘Plant-Applied External Coal Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control’.

Curing. The extent of curing determines the strength of thermally set coatings. Several methods, including shear rheology measurement, differential scanning calorimetry (DSC), differential thermal analysis (DTA), and solvent extraction, are used to determine the extent of curing.19–24 Standards providing procedures for determining the extent of curing include: •

ASTM D3418, Standard Test Method; ‘Transition Temperature of Polymers by Thermal Analysis’.

iii. Steel-coating interface As long as the steel-coating interface is intact, corrosion does not take place. Chemical and electrochemical conditions determine the properties of this interface. The properties measured to determine the status of the steel-coating interface include adhesion, cathodic disbondment, and flexibility. Adhesion. Adhesion is a summation of a wide variety of forces that hold a coating onto a substrate. However, this cannot be measured directly. Instead, the force required to remove the coating from the surface is measured. Both adhesive and removal forces are equal but operate in the opposite directions. They both depend on the same factors including surface conditions, surface geometry, wetting, and brittleness of the coating. Numerous test procedures have been developed for evaluating adhesive strength. Common adhesion tests include hot water soak resistance, peel strength, shear strength, pull-off resistance, and resistance to scraping. Many adhesion tests produce numerical results and some are subjective in nature; a test producing numerical result is more reliable than one depending solely on the subjective assessment of the tester.25 Standards providing procedures for determining the adhesive strength include: • • • • • •

ASTM D1002, Standard Test Method; ‘Strength Properties of Adhesive in Shear by Tension Loading (Metal-to-Metal)’. ASTM D2197, Standard Test Method; ‘Adhesion of Organic Coatings by Scrape Adhesion’. ASTM D3359, Standard Test Method; ‘Measuring Adhesion by Tape Test’. ASTM D4541, Standard Test Method; ‘Pull-Off Strength of Coatings Using Portable Adhesion Testers’. ASTM D1000, Standard Test Method for Pressure-Sensitive Adhesive-Coated Tapes Used for Electrical and Electronic Applications. NACE Standard RP0394, Standard Recommended Practice, ‘Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating (Hot Water Soak)

10.2 Modeling corrosion control

• • • •

645

(to provide an accelerated assessment of the coating’s adhesion to the substrate in a hot, wet environment)’. CSA. Z245.20 (Adhesion of the Coating). CSA. Z245.21 (Peel Test – Constant Rate Or Hanging Mass). ANSI/AWWA C213 (Adhesion Using Knife Blade). ANSI/AWWA C293 (Water Soak).

As discussed in the cohesion section, only those tests that do not require attachment of features directly onto the coating are suitable for modern, high-strength coatings. Table 10.14 presents adhesion tests as required by Type 2 coating standards. Cathodic disbondment. The cathodic disbondment test is a very old and versatile test. It used to be known as the Salt Crock test.26 The test is an accelerated method for determining the compatibility between external polymeric coatings and CP. This test measures the area of disbondment – commonly known as cathodic disbondment (CD) area – caused by CP. In the 1980s, a study evaluated the predictability of long-term external coating performance from laboratory tests.27 This study found that the most useful laboratory tests for predicting field performance of coatings were CD, adhesion, resistance to soil stresses, chemical and physical stability, and impact resistance. In 1992, a study to develop quantitative techniques for predicting the rate of disbonding of anticorrosion coatings on buried natural gas pipelines was carried out.28,29 This study found that the three parameters most detrimental to the performance of pipeline coatings are CD, adhesion, and water penetration. In 1993, a review on coating evaluation practices over 50 years observed that the CD test is the most reliable for evaluating the coating.30 In the late 1990s and early 2000s, studies were carried out to predict long-term field performance of FBE coatings based on short-term tests,31–33 and the results indicated that long-term field performance may be predicted based on the performance of FBE in a CD test. Another independent study in 2002 also indicated that the CD test is one of the best tests to evaluate coating performance.34–36 Standards providing procedures for performing CD tests include: • • • • • • • • • •

ASTM G8, Standard Test Method; ‘Cathodic Disbonding of Pipeline Coatings’. ASTM G19, Standard Test Method; ‘Disbonding Characteristics of Pipeline Coatings by Direct Soil Burial’. ASTM G42, Standard Test Method; ‘Cathodic Disbonding of Pipeline Coatings Subjected to Elevated Temperatures’. ASTM G80, Standard Test Method; ‘Specific Cathodic Disbonding of Pipeline Coatings’. ASTM G95, Standard Test Method; ‘Cathodic Disbondment Test of Pipeline Coatings (Attached Cell Method)’. CSA Z245.20, ‘Plant-Applied External Fusion Bond Epoxy Coating for Steel Pipe’. CSA Z245.21, ‘Plant-Applied External Polyethylene Coating for Steel Pipe’. NACE RP 394, ‘Standard Recommended Practice, Application, Performance, and Quality Control of Plant-Applied, Fusion Bonded Epoxy External Pipe Coating’. British Standard BS 3900-F10, ‘Methods of Test for Paints: Determination of Resistance to Cathodic Disbonding of Coatings for Use in Marine Environments’. British Standard BS 3900: F11, ‘Methods of Test for Paint: Determination of Resistance to Cathodic Disbonding of Coatings for Use on Land-Based Buried Structures’.

646

Coatings As required by (standards) Asphalt Coal tar

Minimum Adhesion Strength NACE

CSA

ISO

AWWA

N/A N/A

N/A N/A

N/A

N/A

2-layer

N/A (Pull) ASTM D 4541 2.4 MPa (350 psi) (Peel) ASTM D1000 Inner layer: 60e250 ozf/in. (6.6e27 N/10-mm) width Outer layer: 40e80 ozf/in. (4.4e8.9 N/10-mm) width (Hot) NACE RP 394 (Rating 1e3) Not specified

3-layer

N/A

Composite

N/A

(Hot) CSA Z245.20 (Rating 1e3) (Peel) CSA Z245.21 3.0 N (Peel) CSA Z245.21 19.6 N (Peel) CSA Z245.21 150.0 N (Hot) CSA Z245.20 (75 C þ 28 days) 1e3

Hot water (Rating 1e3) (Peel) 3N to 50 (Peel) 3N to 25 N/A

N/A (Peel) AWWA C203 (No peeling) (Peel) ASTM D1000 Inner layer: 200 ozf/in. (2190 N/m) width Outer layer: 20 ozf/in. (200 N/m) width (Shear) ASTM D1002 3000 psi (20,685 kPa) Not specified

Tape

FBE

N/A N/A

CHAPTER 10 Modeling – External Corrosion

Table 10.14 Specifications for Determining Adhesion of Various Coatings

10.2 Modeling corrosion control

647

Table 10.15 Requirements of Cathodic Disbondment Resistance of Various Coatings Coatings

Maximum Cathodic Disbonded Area Radius, mm (in.)

As required by (standards) Asphalt Coal tar Tape FBE

NACE

CSA

ISO

AWWA

N/A 8 (0.3) 50 (2) 8 (0.3) Not specified

3-layer

N/A

Composite

N/A

N/A N/A N/A 8e15 (0.3e0.59) 12e20 (0.47e0.79) 7e15 (0.28e0.59) N/A

N/A Not specified Not specified Not specified

2-layer

N/A N/A N/A 6.5e20 (0.26e0.79) 12 (0.47) 12 (0.47) 12 (0.47)

Not specified N/A N/A

Table 10.15 presents CD tests as required by Type 2 coating standards. Studies have also shown that CD test results depend on several parameters including experimental duration, applied potential, solution conductivity, and temperature. The cathodic disbondment test results may be misleading if these effects are not considered.37–42 Table 10.16 compares how these parameters are controlled in the procedures described in various standards. Flexibility. Most oil and gas infrastructures operate at higher temperatures. Consequently they expand and contract in response to changes in both operating and atmospheric temperatures. Therefore it is essential that coatings have some flexibility. The methods to assess flexibility involve bending a coated substrate over a mandrel and determining the extent of bending before the coating starts to crack. The appearance of cracking may be determined visually or electrically. Standards providing procedures for measuring the flexibility of the coatings include: • • • • • • • • • • •

CSA - Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’. ASTM G10, Standard Test Method; ‘Specific Bendability of Pipeline Coatings’. ASTM G70, Standard Test Method; ‘Ring Bendability of Pipeline Coating (Squeeze Test)’. ASTM D522, Standard Test Method; ‘Mandrel Bend Test of Attached Organic Coatings’. ASTM D638, Standard Test Method; ‘Tensile Properties of Plastics’. ASTM D1737, Standard Test Method; ‘Elongation of Attached Organic Coatings with Cylindrical Mandrel Apparatus’. ASTM D882, Standard Test Method; ‘Tensile Properties of Thin Plastic Sheeting’. ASTM D146, Standard Test Method; ‘Sampling and Testing Bitumen-Saturated Felts and Woven Fabrics for Roofing and Waterproofing’. ASTM D790, Standard Test Method; ‘Flexural Properties of Unreinforced and Reinforced Plastics and Electrical Insulating Materials’. ASTM D4145, Standard Test Method; ‘Coating Flexibility of Prepainted Sheet’. ASTM D1000, Standard Test Method; ‘Pressure-Sensitive Adhesive-Coated Tapes Used for Electrical and Electronic Applications’.

648

Table 10.16 Comparison of Cathodic Disbondment Test Procedures in Various Standards Holiday Coating Thickness

ASTM

G8

ASTM

Potential, Cu/CuSO4

Minimum Surface Area

Temperature, C

Electrolyte

Duration, Days

Current (reported or not)

Number

Size

Not specified

3

Not less than 3 times the coating thickness, min. 6.35 mm (0.250 in)

1.45 to 1.55

Not specified

Room

1% NaCl

30

Not required in Method A, Required in Method B

G19

Not specified

3

304.8 mm (12 in); 457.2 mm (18 in); and 609.6 mm (24 in)

1.45

Not specified

Room

Soil

30 to 18 months

Current and pipe to soil potential at 0 and 30 days.

ASTM

G42

Not specified

1

3 times the thickness of coating (minimum 6.35 mm (0.25 inch)

1.5

23200 mm2 (36 in2)

60 (min)

Distilled water containing, each 1 wt% NaCl, Na2SO4, and Na2CO3

30

Current requirement in uA

ASTM

G80

Not specified

3

Not less than 3 times the coating thickness, min. 6.35 mm (0.250 in)

1.45 to 1.55

92,900 mm2 (1 sq.ft)

Room

Potable tap water containing, each 1 wt% NaCl, Na2SO4, and Na2CO3

60

Not reported.

ASTM

G95

Not specified

1

3.2 mm (0.125 in)

76.2 mm (3 inch)

Room

Distilled water with 3% NaCl

90

Not reported

CSA

Z245.20 (Sec.12.8)

300 mm

1

3.0 or 3.2 mm

1.5 3.0

6.4 (pipe wall thickness) x100100 mm

20 65

Distilled water with 3% NaCl

28 1

Not reported

CSA

Z245.20 (Sec. 12.13

300 mm

1

3.0 or 3.2 mm

1.5

6.4

20

Distilled water with 3% NaCl

28

Not reported

3

CHAPTER 10 Modeling – External Corrosion

Organization

Standard Reference

(strained at e30 C) Varies

1

6.4 mm

1.5

pipe wall thickness x100100 mm

20

Distilled water with 3% NaCl

28

Not reported

CSA

Z245.21 (sec.12.3)

Varies

1

6.4 mm

1.5

pipe wall thickness x100100 mm

Max. design temp.

Distilled water with 3% NaCl

28

Not reported

CSA

Z245.21 (sec.12.3)

Varies

1

6.4 mm

3.5

pipe wall thickness x100100 mm

65

Distilled water with 3% NaCl

1

Not reported

NACE

RP0394 (Sec.H)

360  50 mm

1

3 mm

3.5

100 mm sq.  6 mm thick

66 (150 F)

Distilled water with 3% NaCl

28

Not reported

NACE

RP0394 (Sec.H)

360  50 mm

1

3 mm

1.5

100 mm sq.  6 mm thick

66 (150 F)

Distilled water with 3% NaCl

1

Not reported

NACE

RP0394 (Sec.M) (Strained at e18 C)

360  50 mm

1

3 mm

3.5

100 mm sq.  6 mm thick

66 (150 F)

Distilled water with 3% NaCl

28

Not reported

British Gas

BGC/PS/ CW6

6 mm, 160 cutting edge. 2 holidays per temperature

1.5 (SCE)

2 in diameter

20 to 50

3% NaCl

7 and 28

Potential and current, every 24 h

British Gas

BGC/PS/ CW2

6.3 mm

36 in2

Not mentioned

3% NaCl

30

Potential and current, every 24 h

British Standard

BS 3900: F10

6

10 mm

1.0

6  4 x 0.2 inch

23 or room temperature

Aerated sea water. Natural/ synthetic. Replace weekly

180

Potential every 24 h (initially every 8 h for first 4 days)

British Standard

BS 3900: F11

4

6 mm

1.5

6  4 x 0.2 inch

23

3% NaCl

7 and 28

Potential and current, every 24 h

British Standard

BS 3164

2

6 mm

1.5

8  4 x 0.5 inch

20

3% NaCl

28

Potential, 24 h.

1.5 (for accelerated testing 2.9)

649

Z245.21 (sec.12.3)

10.2 Modeling corrosion control

CSA

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CHAPTER 10 Modeling – External Corrosion

Table 10.17 Requirements of Flexibility of Various Coatings Coatings As required by (standards) Asphalt Coal tar Tape FBE

2-layer

Flexibility NACE

CSA

ISO

N/A

N/A N/A N/A

N/A N/A N/A

Bend 2e3 (no cracking)

2 /pipe diameter at 0 C

2.5 (no cracking)

2.5 /pipe diameter at 0 C and 30 C 2 (no cracking) N/A

100e400% (ASTM D1000) 2 /pipe diameter at e18 C or 1.5 /pipe diameter permanent strain (No cracks, tears or delamination) min 100% (ASTM D 638)

3-layer

N/A

Composite

N/A

2.5 (no cracking) 2.5 (no cracking)

Table 10.17 presents the flexibility requirements of various coating as prescribed in Type 2 coating standards.

iv. Coating-environment interface The coating-soil interface is a naturally formed interface where events leading to the deterioration of coatings start. This interface must be adequately protected at the time of construction using backfill materials. The factors affecting this interface include chemicals, microbes, abrasion, impact, freeze thaw cycle, and temperature. Chemical resistance. See the chemical resistance discussion in the coating section for more information. Microbial resistance. Microbes can degrade coating materials because the coating components may form the food for microbes. A mixed population of microorganisms, including sulfate reducing bacteria (SRB) and acid producing bacteria (APB), may be involved in coating degradation. Sandy soils favor APB, and high-clay soils support populations of both kinds of organisms. Fungi also alter the optical, mechanical, and electrical properties of polymeric coatings. The resin portion of the coating is generally fungus-resistant, but other components such as plasticizers, stabilizers, and coloring agents may be susceptible to microbial attack.43 Despite these indications, a quantitative relationship between bacteria and coating damage has been difficult to establish. The general protocol for evaluating the resistance of a coating to microbes involves exposing the coating material to an environment containing microbes, then conducting performance tests (e.g., the CD test), and finally comparing the test results with those of coating

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651

material not exposed to microbes. Large samples of most coating materials will sustain extensive microbial growth under realistic field conditions for many months without apparent damage. Exposing very small coating samples to large volumes of bacterial culture leads to mixed effects. For most coatings, loss of components occurs through dissolution in water. Bacteria grow using dissolved components rather than attacking directly the coating. Direct physical and chemical changes that can be specifically attributed to microbial action are difficult to obtain. Standards providing procedures for evaluating the microbial resistance of polymeric coatings include: • • •

ASTM G21, Standard Test Method; ‘Determining Resistance of Synthetic Polymeric Material to Fungi’. ASTM G22, ‘Standard Practice for Determining Resistance of Plastics to Bacteria’. ASTM E2180, ‘Standard Test Method; ‘Determining the Activity of Incorporated Antimicrobial Agent(s) in Polymeric or Hydrophobic Material’.

No Type 2 standards however require evaluation of microbial resistance of coating. Abrasion resistance. Slurry and coarse materials abrade coatings, especially during horizontal drilling across river and road crossings. Therefore, the abrasion resistance of coatings applied on pipelines laid across river and road crossings should be evaluated. These values are then used to determine the optimum coating thickness. Standards providing procedures for evaluating the abrasion resistance of coatings include: • • • •

ASTM G6, Standard Test Method; ‘Abrasion Resistance of Pipeline Coatings’. ASTM D968, Standard Test Method; ‘Abrasion Resistance of Organic Coatings by Falling Abrasive’. ASTM D1044, Standard Test Method; ‘Resistance of Transparent Plastics to Surface Abrasion’. ASTM D4060, Standard Test Method; ‘Abrasion Resistance of Organic Coatings by the Taber Abrader’.

Table 10.18 provides the minimum resistance to abrasion for various coatings as required by Type 2 coating standards. Table 10.18 Requirements of Abrasion Resistance for Various Coatings Coatings As required by (standards) Asphalt Coal tar Tape FBE

2-layer 3-layer Composite

Thickness, mm (mil) NACE

CSA

ISO

AWWA

N/A Not specified Not specified 300 mg per 5000 cycles (ASTM D4060) Not specified N/A N/A

N/A N/A N/A Not specified

N/A N/A N/A Not specified

Not specified Not specified Not specified

Not specified Not specified N/A

N/A Not specified Not specified 0.3 (5000 cycles-gm loss) (ASTM D1044) Not specified N/A N/A

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Impact resistance. The coating should be resistant to mechanical damage during shipping, handling, installation and backfilling. Even though hardness and penetration resistance tests are used to evaluate the mechanical strength of the coating, an additional test is necessary to evaluate the impact resistance. The impact resistance is determined by dropping rock materials onto the coating and measuring the extent of penetration, either visually or electrically. Standards providing procedures for measuring the impact resistance of coatings include: • • • • •

CSA – Z245.20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’. ASTM G13, Standard Test Method; ‘Impact Resistance of Pipeline Coatings (Limestone Drop Test)’. ASTM D14, ‘Specification for Jacketed Rubber-Lined Wire Hose for Public and Private Fire Department Use’. ASTM D256, Standard Test Method; ‘Determining the Pendulum Impact Resistance of Notched Specimens of Plastics’. ASTM D2794, Standard Test Method; ‘Resistance of Organic Coatings to the Effects of Rapid Deformation (Impact)’.

Table 10.19 presents the minimum resistance to impact for various coatings as required by Type 2 coating standards. Freeze thaw stability. The freeze thaw stability test is important for coatings used to protect infrastructure operating in low-temperatures, e.g., pipelines and other infrastructure in an arctic environment. Freeze thaw tests may be performed either by varying the duration to which the samples are exposed to freezing (i.e., lower temperature) and thawing (i.e., higher temperature) conditions, or by exposing the samples for a fixed duration but varying the temperature difference between freezing and thawing. Coating properties (usually adhesion) are determined before and after the freeze thaw cycle. Standards providing procedures for evaluating freeze thaw stability include: • •

ASTM D2243, Standard Test Method; ‘Freeze Thaw Resistance of Water-Brone Coatings’. ASTM D2337, Standard Test Method; ‘Freeze Thaw Stability of Multicolor Lacquers’.

No type 2 coating standard however requires evaluation of freeze thaw stability. Resistance to elevated temperature. Operating temperatures of oil and gas infrastructure continue to increase. Beyond certain temperatures (normally 150 C (302 F)) insulators are used in addition to the anticorrosion coating (see section 10.2.9 for more details). The performance of coatings should, therefore, be evaluated at the operating temperature. Standards providing procedures for evaluating operating temperature of coatings include: • •

ASTM D2485, Standard Test Method; ‘Evaluating Coatings For High Temperature Service’. ASTM D3012, Standard Test Method; ‘Thermal-Oxidative Stability of Propylene Plastics Using a Biaxial Rotator’.

Table 10.20 provides typical maximum temperature up to which the coatings are effective.

v. Structure-environment interface A coating will protect an infrastructure as long as it does not allow it to come in contact with the environment, i.e., the structure-environment, (e.g., structure-soil, interface or pipeline-soil interface, structure-water interface) does not form. Such an interface can form when the coating is completely

10.2 Modeling corrosion control

653

Table 10.19 Requirements of Impact Resistance for Various Coatings Coatings

Impact Resistance

As required by (standards) Asphalt Coal tar

NACE

CSA

ISO

AWWA

N/A Not specified

N/A N/A

N/A N/A

Tape

30 lbf.in. (3.4 J) (ASTM G14) or No holidays after 30 drops (ASTM G13) 1.5 J (13 in.-lb) min (ASTM G14) 1.5 J N/A

N/A

N/A

N/A 650 g ball, 8-ft drop (25 C) (AWWA C203) 25 lbf.in. (2.8 N.m) (ASTM G14)

1.5 J

1.5 J

100 in-lbf (11.3 Nm)

N/A N/A

3J 5J

3.0 J/mm of actual total coating thickness 3.0 J/mm of actual total coating thickness 3.0 J/mm of actual total coating thickness N/A

3J

Not specified 40 in.lbs (0.46 kg.m). minimum (ASTM D2794) 25 lbf.in (2.8 N.m) min (ASTM G14)

FBE

Liquid epoxy Liquid urethane

2-layer

No specification (ASTM G14)

3-layer

N/A

Composite

N/A

Wax

Not specified

5 to 10 J

N/A

N/A

N/A

N/A

N/A

removed (the formation of holidays) or when the coating disbonds to create a coating-soil interface beneath the disbonded coating. Holiday detection. Normally the holidays occur during the construction stage. Therefore the infrastructure is inspected to ensure that there is no holiday before laying it underground. Standards providing procedure to detect holidays include: •

ASTM G62, Standard Test Method; ‘Holiday Detection in Pipeline Coatings’.

10.2.2b Non-standard tests There is a continuous requirement for new methodologies based on the failure modes of coatings during operation. Certain failure modes for which there is no standard laboratory methodology

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CHAPTER 10 Modeling – External Corrosion

Table 10.20 Typical Maximum Temperature of Operation for Various Coatings Temperature, Max,  C ( F)

Coatings As required by (standards) Asphalt Coal tar Tape FBE

NACE

CSA

ISO

AWWA

N/A 71e110 (160e230) 90 (194) Not specified

N/A N/A

N/A N/A

N/A Not specified

N/A Not specified N/A

N/A Manufacturer’s specification By agreement between end user and manufacturer By agreement between end user and manufacturer Manufacturer’s specification 60e110 (140e230)

Not specified Supplier specification Not specified

Supplier specification N/A

N/A

N/A

N/A

N/A

Liquid epoxy

Supplier specification

Liquid urethane

N/A

N/A

2-layer

Not specified

3-layer

N/A

Composite

N/A

Wax

52 (126)

Not specified Not specified Not specified N/A

Not specified

available at this time include wrinkling, tenting, slipping, blistering, and permeation. New methodologies to evaluate the resistant of coatings to these failure modes are described in this section.

i. Wrinkling Coatings, particularly tape coating, wrinkle when exposed to wet clay sands. A wrinkled tape coating leads to development of near neutral pH stress corrosion cracking (SCC) conditions44 and corrosion. Wrinkling occurs when the adhesion of the coating on the surface is not uniform over the entire surface. If the coating is hydrophilic (i.e., has a high affinity for water), then the wet soil adheres on the coating. In a wet-dry cycle, the soil around the pipe will expand and contract. Winkling results from soil (backfill) around the pipe. The coating adhering to the soil will hence experience pulls and relaxation. Consequently the coating starts to wrinkle if it does not adhere uniformly onto the steel. Figure 10.5 presents a schematic diagram of an apparatus for evaluating the tendency of a coating to wrinkle.45 The coated panel is first fitted into the apparatus and then clay soil is added to fill half of the container. Water (ground water or 3% NaCl solution) is added to the soil. The soil to water ratio is chosen such that the soil does not overflow the container when squeezed by the piston. Using a piston arrangement (Figure 10.6), the moist soil is held tightly onto the coating for certain period (typically 24 h). The piston is then removed, without disturbing the soil, and the soil is allowed to dry for certain period (typically 24 h). The cycle is repeated and the coating is examined after each cycle for the appearance of wrinkles. In the field, wrinkles generally appear after 10 years, so the wet-dry cycle

10.2 Modeling corrosion control

FIGURE 10.5 Schematic Diagram of an Apparatus to Simulate Wrinkling.45

FIGURE 10.6 Piston Arrangement to Simulate Soil Stress.

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CHAPTER 10 Modeling – External Corrosion

should be repeated several times; generally if the coating does not wrinkle after 50 cycles it may be assumed that it does not wrinkle in the soil tested. The test results depend on the type of soil, type of coating, mass of the soil, and the number of cycles. Equation 10.1 may be used to calculate the mass of soil used in the test: msoil ¼ Br2p hsoil :Dsoil

(Eqn. 10.1)

where msoil is the mass of soil, rp is the radius of the piston, hsoil is the height of the soil, and Dsoil is the density of soil (for clay soil it is approximately 2.02 g/cm3).

ii. Tenting Tenting normally occurs on polyethylene tapes that are spirally wrapped around the pipe. The location of tenting may be between the overlap the tape or between the pipe surface and the tape along the ridge created by the longitudinal weld. Moisture can penetrate under the tented and subsequently disbonded coating. The CP current cannot reach the pipe surface through the long path under the tented and highly electrically resistant polyethylene tape coating. Consequently, conditions are established for the occurrence of worst case coating failure; i.e., a disbonded coating that does not allow CP current (see section 10.2.1a). For these reasons the tendency of the coating to tent should be evaluated. Figure 10.7 shows a five-step sample surface to simulate tenting in the laboratory. The coating is tightly wrapped or applied on the sample. The coated sample is then immersed in a container filled with water (ground water or 3% NaCl solution) for a pre-determined period of time (typically 7 days). At the end of this period, a sharp object is used to cut the coating at each step. The tenting tendency is ranked from 1 (good) to 5 (poor); where good refers to a sample which could not be cut at any of the five steps, and poor refers to a sample that could be cut in all five steps. Figure 10.8 presents three samples ranked 3, 4, and 5.

iii. Slipping Slipping may occur in multilayer coatings, e.g., two layer and three layer coatings, if the cohesive strength between the layers is less than the adhesive strength between the coating and the steel surface. Any moisture penetrating through the outer coating layer may accelerate the loss of cohesive strength. Even though the peel and adhesion strengths represent cohesive strength, they are measured under dry conditions. Tests conducted in wet conditions simulate the field operating conditions more closely. Figure 10.9 presents an experimental set-up to evaluate the tendency of a coating to slip under wet conditions. The container is attached on to the coating by an adhesive with higher bond strength than that of the coating onto steel. If such an adhesive is not used, the experiment will terminate prematurely due to the slippage of the container rather than that of the coating. The container is filled with solution or wet soil. To apply the load, a hollow panel is machined (Figure 10.10) and then fitted outside the container. A constant load is applied onto the hollow panel to pull the assembly (Figure 10.11). The slippage of the coating is observed periodically (e.g., every day) for a pre-determined duration (typically up to 30 days). If complete slippage occurs before 30 days, the sample is considered to have failed. The slippage rate is calculated using Eqn. 10.2: Slippage rate ¼

dslip  wslip t

where d is the distance slipped in mm, w is the load in kg, and t is the time in days.

(Eqn. 10.2)

10.2 Modeling corrosion control

657

FIGURE 10.7 Specimen for Evaluating Tenting Tendency of Polymeric Coatings. (A) Schematic (B) Actual sample.

Figure 10.12 presents typical results from a slippage test.

iv. Blistering Blistering of epoxy coatings is commonly found in the field. Most field experience indicates that blistered coatings pass CP as indicated by higher pH (above 9) under the blistered coating.46,47 Therefore it is important to evaluate the blistering tendency of the coating. Current measurement during a CD test may be used to evaluate the tendency of coating to blister. The current typically exhibits characteristic spikes during the formation of blisters. For instance, the CP current increases on day 131 (Figure 10.13) from 0.003 mA to 0.475 mA and remains high for about 10 days and then decreases to 0.007 mA. Physical observation of the panel (inset in Figure 10.13) on day 132 shows the formation of blisters. This trend has been noticed in all panels that developed blisters (Table 10.21), so monitoring the CD current may be used to evaluate the blister-forming tendency of coatings.42

v. Water permeation A protective coating is an insulator and it impedes the transport of water to the metal surface. Therefore measuring the electrical resistance of organic coatings provides a means of determining the

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CHAPTER 10 Modeling – External Corrosion

Description

Samples

Before experiment

After experiment. Sample ranked #3

After experiment. Sample ranked #4

After experiment. Sample ranked #5

FIGURE 10.8 Samples from Tenting Test.

CLAMP

CLAMP

CONTAINER

DIRECTION OF APPLIED LOAD

Solution

DIRECTION OF APPLIED LOAD

CLAMP CLAMP HOLIDAY

FIGURE 10.9 Experimental Set-up for Evaluating the Slipping Tendency of Coatings.

10.2 Modeling corrosion control

659

FIGURE 10.10 Typical Experimental Set-Up to Evaluate Slipping Tendency of Coatings – Placement of Hollow Panel on the Outer Surface of the Container.

tendency of water to penetrate through the coating. This principle is used in Electrochemical Impedance Spectroscopy (EIS) or Alternating Current (AC) impedance measurement. During EIS measurement, the impedance (Z) is determined at different frequencies by applying an AC potential and measuring the resulting current. Several methods are used to analyze the EIS data to obtain information on permeation of water across polymeric coating.48 Two commonly used methods are discussed in the following paragraphs. Normally the EIS results are analyzed using a circuit analog (equivalent circuit) model. Several equivalent circuits are available, but the one widely used to analyze EIS of a metal surface with

FIGURE 10.11 Application of Load in the Slipping Apparatus.

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CHAPTER 10 Modeling – External Corrosion

Slippage distance (mm)

25 20 15 10 5 0 0

2

4

6

8

Time (days) 5 Kg load

10 Kg load

0.80

80

0.60

60

0.40

40

0.20

20

Temperature (ºC)

Cathodic Current (mA)

FIGURE 10.12 Rate of Slippage as a Function of Load.

Blister first observed at 132 days

0 0 13 26 39 52 65 78 91 104 117 130 143 156 169 182 195 208 221 234 247 260 273 286 299 312 325 338 351 364 377 390 403 416 429

0.00

Time (days)

FIGURE 10.13 Variation of Current During a Cathodic Disbondment Test (Note Current Increase Before Blister Formation.

10.2 Modeling corrosion control

661

Table 10.21 Correlation Between Current Demand and Blister Formation During Cathodic Disbondment Test42 Coating Type

Failure Mode (days)

Asphalt Coal Tar Tape FBE

Disbondment Disbondment Wrinkling Blistering (131) Blistering (61) Blistering (197) Blistering (183) Blistering (334) Blistering (304) Blistering (365) Blistering (334) No Change No Change

Liquid Epoxy (spray) Liquid Urethane 3-Layer Composite

Current Immediately Prior to Blistering (mA)

Current Immediately After Blistering (mA)

0.003 0.004 0.004 0.002 0.066 0.069 0.075 0.006

0.305 0.530 0.164 0.025 0.335 0.135 0.332 0.423

polymeric coating is presented in Figure 10.14. By adjusting the values of circuit elements, a theoretical EIS plot is generated, and this is compared with the experimentally obtained EIS plot. Several iterations may be required, by changing the values of the circuit elements, to match theoretical curve to the experimental curve. Once the theoretical and experimental plots match, the coating capacitance (Ccoat), double layer capacitance (Cdl), polarization resistance (Rcorr or Rp) (inversely proportional to corrosion rate), resistance of pores within the coating (Rcoat) and solution resistance (Rs) can be determined.

FIGURE 10.14 The Equivalent Circuit Used to Analyze the Electrochemical Impedance Spectroscopy of Polymeric Coating on Metallic Structure.

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CHAPTER 10 Modeling – External Corrosion

From the values of Ccoating calculated from the EIS measurement, the tendency of water to penetrate through the polymeric coating is determined as follows. With the uptake of water the dielectric constant increases because the dielectric constant of the water phase is about 20 times that of the polymeric coating. The volume of water uptake in the coating, vwater, can be calculated (Eqn. 10.3):49 εt Ccoat;t ¼ ¼ 80vwater (Eqn. 10.3) εo Ccoat:o where Ccoat,o is the initial coating capacitance, Ccoat,t is the coating capacitance at time t, εo is the initial dielectric constant, and εt is the dielectric constant at time t. In an alternative simpler approach, the impedance value is measured only at 0.1 Hz. From the value of impedance information on water penetration is deduced as follows:50 • • • •

For excellent coating with no which permeation, the impedance is greater than 109 ohm$cm2 For good coating permeating water at a lower rate, the impedance is between 109 and 107 ohm$cm2 For fair coating permeating water freely penetrate, the impedance is between 107 and 102 ohm$cm2 For poor coating with large holidays through which water directly reaches the steel surface, the impedance is less than 102 ohm$cm2.

vi. Gas permeation The permeation of gases through a coating is the first step in its deterioration. By monitoring microscopic changes caused by gas permeation, it may be possible to provide an early warning of coating deterioration. Gas permeation does not produce any visible changes in the coating properties, therefore sensitive techniques should be used to monitor it. One such technique is the quartz crystal microbalance (QCM). The central monitoring device in a QCM is a quartz crystal. An oscillator circuit oscillates this quartz crystal at its resonant frequency. The resonant frequency varies with a change in mass on the surface of the quartz crystal. The resolution of oscillation frequency is at least 1 Hz. Therefore the sensitivity of QCM is at the nanogram or monolayer level. For this reason the QCM can detect minute changes caused by the permeation of gases through a coating. In practice, the oscillation frequencies between two crystals are monitored. The experimental crystal is exposed to the atmosphere (gas or liquid) of interest and the reference crystal is protected from the atmosphere. The change in mass on the crystal is calculated from the change in the frequency using the Sauerbrey equation.51 Sauerbrey described the relationship between the mass change, Dm, and the change in the resonance frequency of the quartz crystal, DF, as (Eqn. 10.4): DF ¼

2fq2 Dm pffiffiffiffiffiffiffiffiffiffi Aq m q r q

(Eqn. 10.4)

where DF is the measured resonance frequency change, fq is the frequency of the quartz crystal, Dm is the mass change, Aq is the piezoelectrically active area of a quartz crystal, rq is the density of quartz (2.648 g/cm3 or 0.957 lb/in.), and mq is the shear modulus of quartz (2.947  1011 dyne/cm2). The fq is calculated as (Eqn. 10.5): ntr (Eqn. 10.5) fq ¼ 2tq

10.2 Modeling corrosion control

663

where vtr is the transverse velocity of sound in quartz, 3.34  104 m/s (1.1  105 ft/s), and tq is the thickness of the quartz crystal. With all parameters in Eqn. 10.4 remaining constant, the change in the frequency of the quartz crystal is proportional to the mass change. In addition to this change, variations in solution and coating properties such as viscosity, density, viscoelasticity, roughness, and thickness may shift the resonant frequency of a quartz crystal. Therefore variations in these properties should be considered before using Eqn. 10.4. The QCM is also known as electrochemical quartz crystal microbalance (EQCM) when the crystal is used as an electrode. Using EQCM, variations in both mass and electrochemical properties can be monitored. Figure 10.15 presents a schematic diagram of an arrangement to use EQCM to monitor the permeation of gas across a coating.52 In this configuration, the quartz crystal is attached from behind the steel panel. Placement of the EQCM crystal at the metal-coating interface is critical. The adhesive used to attach the EQCM crystal to the steel panel should provide a metal-crystal bond that is stronger than the crystal-coating bond, so that measurements respond to events occurring at the crystal-coating interface. After placing the crystal onto the steel panel, the coating is applied and the coating panel is then subjected to a performance test, e.g., CD test. The resonant frequency of the crystal is measured as a function of time during the test. No resonance is observed when the crystal is attached onto the coating. When the coating disbonds or detaches from the crystal surface, a resonant frequency is observed. The merit of EQCM for providing an early indication of coating deterioration caused by gas permeation has been demonstrated by the use of such an arrangement.52 EQCM provided early indication of coating behavior in more than 95% of 120 panels with 13 different coatings subjected to a 14 month CD test.

10.2.3 Modeling using laboratory data This modeling methodology operates in the assumption that the field performance of a coating can be predicted from its performance in various laboratory standard tests. Available data from standard

FIGURE 10.15 Schematic Diagram Indicating the Placement of Electrochemical Quartz Crystal Microbalance (Eqcm) at the Metal-Coating Interface.52

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CHAPTER 10 Modeling – External Corrosion

laboratory tests can thus be used as a first approximation to predict the performance of coating in the field. This methodology involves two steps: development of a scoring system and prediction of corrosion rate based on that system.53

10.2.3a Development of the scoring system Several properties of the coating are evaluated using standard laboratory tests (see section 10.2.2a). For compiling the scores, these properties are broadly classified into five categories: steel, coating, steelcoating interface, coating-environment interface, and steel-environment interface. In this approach, it is assumed that each category equally influences the coating behavior. For this reason the number of properties evaluated in each category should ideally be the same, so that the maximum score for all five categories is equal. But in practice number of properties evaluated in each category varies. Therefore the score for each category is normalized to 20 so that the total laboratory performance score, SLab, is one hundred (Eqn. 10.6): (Eqn. 10.6) SLab ¼ SSteel þ SCoating þ SSteelCoating þ SCoatingSoil þ SPipeSoil where SSteel is the steel category score, SCoating is the coating category score, SSteelCoating is the steelcoating category score, SCoatingSoil is the coating-soil category score, and SPipeSoil is the pipesoil category score. The next step is to calculate the score in each category. The following section describes this step.

i. Steel category The steel category score depends on four properties: blast cleaning, surface profile, visual contamination, and non-visual contamination. The performance of coating with respect to each property is evaluated using four criteria. For each criterion a score of 1, 0, or 1 is assigned. Table 10.22 presents the four criteria and guidelines to assign the score for each criterion. The score for each property thus varies between 4 and 4, so that the maximum score in steel category is 16. The maximum score is normalized to 20 using Eqn. 10.7: 20 (Eqn. 10.7) SSteel ¼ )ðSBC þ SSP þ SVC þ SNVC Þ 16 where SBC is the blast cleaning score, SSP is the surface profile score, SVC is the visual contamination score, and SNVC is the non-visual contamination score. The score for each property is assigned based on Table 10.22.

ii. Coating category The coating category score depends on 32 different properties, but not all of these are equally applicable or relevant to every coating. To account for this, the 32 coating properties are classified into three types: major, minor, and irrelevant. Table 10.23 presents this classification for various coatings. In general, all properties required by Type 2 coating standards are considered as major, and properties not required by Type 2 coating standards are considered either as minor or irrelevant. It should further be noted that standards are constantly and continuously modified. Therefore the requirements of the current version of the standard should be checked. The normalized coating category score is calculated using Eqn. 10.8: wmaj 20 wmaj )SMaj þ )SMin (Eqn. 10.8) SCoating ¼  ð4)NMin Þ 4)NMaj

Table 10.22 Assignment of Score for a Property Score Standard

1

0

L1

External corrosion control design standard

CSA Z662, NACE RP0169 or ISO 15589

Standard listed is used.

Another standard not listed is used.

Coating standard

Type 2 standard (See section 12.2.2a for an appropriate standard).

The coating is selected using the standard listed.

The coating is selected using another standard.

Property standard

Type 3 standard (See section 12.2.2a for appropriate standard for a given property). Type 3 standard (See section 12.2.2a for appropriate standard for a given property).

The property is evaluated using a standard listed.

The property is selected using another standard.

Value is within the range specified by the standard. No range specified by the standard but a result was achieved.

No range is specified in the standard and no result was achieved.

Standard used to design external corrosion control is not known or no standard is used. Standard used to select the coating is not known or no standard is used or available. Standard used to evaluate the property is not known or no standard used or available. Value is outside specified range in the standard.

Value of the property

10.2 Modeling corrosion control

Criteria

665

666

Table 10.23 Relative Importance of Various Coating Properties Asphalt

Coal Tar

Tape

Wax

FBE

CSA Standard ISO Standard NACE Standard Thermal Conductivity Dielectric Strength Insulation Resistance Hardness Penetration Resistance Water Permeation Gas Permeation Chemical Resistance Blistering Weathering Cohesion Stress-Crack Resistance Resistance to Oxidation Compress. Properties Thermal Expansion Film Thickness Low-Temp Crack Test Composition Sag Pliability Gel Time Particle Size Total Volatile Content

ANSI/AWWA C203) NACE RP0399) NACE RP0399 Major A Major Major A N/A Major

ANSI/AWWA C203 NACE RP0399) NACE RP0399 Major A Major A Major A N/A Major

ANSI/AWWA C214) NACE MR0274) NACE MR0274 N/A Major Major N/A Major

NACE RP0375) NACE RP0375) NACE RP0375 N/A Major N/A Major Major

CSA Z245e20.1A ISO 21809e2 NACE RP0394 N/A Minor B Minor B N/A Major C

Major Minor Minor N/A Minor N/A Minor Minor

Major Minor Major N/A Major N/A N/A N/A

Major N/A Major Minor Minor N/A N/A N/A

N/A N/A Major Minor

N/A N/A Major Minor

N/A N/A N/A N/A N/A N/A

N/A N/A N/A Major Major Major

Major Minor Minor N/A Minor N/A N/A N/A

A

Major Minor Minor N/A Minor N/A N/A N/A

A

N/A N/A Major Major

N/A N/A Major Major

N/A N/A Major Minor

Major Major Major N/A N/A N/A

Major Major Major N/A N/A N/A

Major N/A N/A N/A N/A N/A

E

D

C

C

CHAPTER 10 Modeling – External Corrosion

Property

Major N/A Minor Major Major A Major Major Major N/A Liquid Urethane ANSI/AWWA C222) ANSI/AWWA C222)

N/A N/A N/A N/A N/A Major N/A Major N/A 2-Layer CSA Z245e21.A2 CSA Z245e21.A2)

N/A Minor Major Major N/A N/A Major Major N/A 3-Layer CSA Z245e21.B1 ISO 21809e1

NACE Standard Thermal Conductivity Dielectric Strength Insulation Resistance Hardness Penetration Resistance Water Permeation Gas Permeation Chemical Resistance Blistering Weathering Cohesion Stress-Crack Resistance Resistance to Oxidation Compress. Properties Thermal Expansion Film Thickness Low-Temp Crack Test

ANSI/AWWA C210) N/A N/A N/A Major N/A

ANSI/AWWA C222) N/A N/A N/A Major N/A

NACE RP0185 Minor Major A N/A Major Major A

CSA Z245e21.B1) Minor N/A N/A Major Minor

Major N/A N/A N/A Major C Major F Major N/A Major Composite CSA Z245e21.B2 CSA Z2145e21.B2) CSA Z245e21.B2) Minor N/A N/A Major Minor

N/A N/A Major Minor Minor N/A N/A N/A

Major N/A Major Minor Minor N/A N/A N/A

Major Minor Major N/A Major Minor Major Major

Minor Minor Minor N/A Major Minor Major Major

Minor Minor Minor N/A Minor Minor Major Major

N/A

N/A

Minor

Minor

Minor

N/A Major Minor

N/A Major Minor

Minor Major Major

Minor Major Major

Minor Major Major

A

A

A

E E

C

D

B

667

Major N/A Minor Major Major A Major Major Major N/A Liquid Epoxy ANSI/AWWA C210) ANSI/AWWA C210)

10.2 Modeling corrosion control

Porosity Viscosity Flow Softening Point Shelf Life Filler Content Density Tear Strength Curing Property CSA Standard ISO Standard

(Continued)

668

Table 10.23 Relative Importance of Various Coating Properties Continued Property

A

Coal Tar

Tape

N/A N/A N/A N/A N/A N/A

Major N/A N/A N/A N/A N/A

Major N/A N/A N/A N/A N/A

N/A N/A N/A N/A Major N/A N/A N/A Major

N/A N/A N/A N/A N/A N/A N/A N/A N/A

N/A Major Major Major N/A N/A Major Major N/A

Wax C

This property is required by the NACE standard but not by the CSA standard This property is required only by the AWWA standard, but not by CSA, NACE, and ISO standards This property is required by CSA standard but not by NACE and ISO standards D This property is required by the CSA and NACE standards but not by the ISO standard E This property is required by the CSA standard but not by the NACE standard F This property is required by the ISO standard but not by the CSA and NACE standards ) See Table 10.2 for details B

C

Major N/A Major Major Major Major N/A Major Major Major N/A N/A Major Major Major

FBE B

D

B B

Major N/A N/A Major Major N/A N/A N/A Major Major N/A N/A Major Major Major

CHAPTER 10 Modeling – External Corrosion

Composition Sag Pliability Gel Time Particle Size Total Volatile Content Porosity Viscosity Flow Softening Point Shelf Life Filler Content Density Tear Strength Curing

Asphalt

10.2 Modeling corrosion control

669

where SCoating is the category score, wmaj is the weight assigned to major category, NMaj is the number of major properties, SMaj is the sum of the major properties scores, NMin is the number of minor properties, and SMin is the sum of the minor properties scores. The properties with major influence on the coating should be given higher weight than those with minor influence. For this reason the value of wmaj should be between 11 and 20. A value of 20 for wmaj means that the influence of minor properties is not considered. Properties that are irrelevant to the coating are not scored. The score for each property, whether it is major or minor, is assigned based on Table 10.22.

iii. Steel-coating interface category The steel-coating interface category score depends on three properties: adhesion, cathodic disbondment, and flexibility. As in previous categories, the scores for each property is assigned based on Table 10.22. The maximum score in this category is therefore 12 and is normalized to 20 using Eqn. 10.9: 20 )ðSA þ SCD þ SFl Þ (Eqn. 10.9) 12 where SSteelCoating is the category score, SA is the adhesion score, SCD is the cathodic disbondment score, and SFl is the flexibility score. SSteelCoating ¼

iv. Coating-soil interface category Certain standards in this category are only necessary and applicable under certain operating conditions. As a result, four equations are used to calculate the score in this category. When the field operating temperature is between 5 and 85 C four properties are evaluated (Eqn 10.10): SCoatingSoil ¼

 20  ) SMR þ SAR þ SIR þ SCompatibility 16

(Eqn. 10.10)

where SMR is the microbial resistance score, SAR is the abrasion resistance score, SIR is the impact resistance score, and SCompatibility is the compatibility score. When the minimum and maximum field operating temperatures below 5 C and below 85 C respectively evaluation of freeze thaw stability of the coating is included (Eqn. 10.11):   SCoatingSoil ¼ SMR þ SAR þ SIR þ SFT þ SCompatibility (Eqn. 10.11)

where SFT is the freeze thaw stability score. When the minimum and maximum field operating temperatures above 5 C and above 85 C respectively evaluation of high temperature resistance of the coating is included (Eqn. 10.12):   SCoatingSoil ¼ SMR þ SAR þ SIR þ SET þ SCompatibility (Eqn. 10.12) where SET is the resistance to elevated temperatures score. When the minimum temperature is below 5 C and maximum temperature is above 85 C evaluation of both freeze thaw stability and high temperature resistance of the coating are included (Eqn. 10.13): SCoatingSoil ¼

 20  SMR þ SAR þ SIR þ SFT þ SET þ SCompatibility 24

(Eqn. 10.13)

As in previous categories, the scores for each property is assigned based on Table 10.22.

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CHAPTER 10 Modeling – External Corrosion

v. Steel-soil interface category The steel-soil interface category score depends only on one property: holiday. The maximum score in this category is 4 (calculated based on Table 10.22) and is normalized to 20 using Eqn. 10.14: SPipeSoil ¼

20 )SHD 4

(Eqn. 10.14)

where SHD is the holiday detection score.

10.2.3b Prediction of corrosion rate Based on the total laboratory performance score, SLab, the external corrosion rate can be predicted. For this reason, it is assumed that, if the value of SLab (in Eqn. 10.6) is 100, the coating completely protects the infrastructure. Therefore the corrosion rate is predicted using Eqn. 10.15: CLab ¼ Cstd:coat

100 SLab

(Eqn. 10.15)

where CLab is the corrosion rate based on laboratory coating evaluation, and Cstd.coat is the assumed maximum corrosion rate when the coating is fully protective (see section 10.3.1 for a discussion on the selection of an appropriate value for Cstd.coat). For most cases the Cstd.coat is assumed to be 4 mpy.54 This value is based on the assumption that an effective coating system, backed up by CP, decreases the corrosion rate by 75% of that of the uncoated carbon steel.55 The merit of the coating then depends on the duration for which it effectively protects the infrastructure at this low corrosion rate. Table 10.24 provides a general guideline on how long different coatings may be effective in protecting the steel. Depending on the coating type used, on the score calculated in Eqn.10.6, and on the values in Table 10.24, the maximum duration for which the coating may be effective may be predicted (Eqn. 10.16): LLab ¼ LMax

SLab 100

(Eqn. 10.16)

where LLab is the estimated duration for which the coating is effective in protecting the structure based on laboratory performance, in years, and LMax is the maximum duration the coating is effective in protecting the infrastructure, in years (see Table 10.24).

Table 10.24 Maximum Expected Life of a Pipe Coating56 Coating Type

Years

Asphalt Coal tar Tape FBE 2-Layer 3 layer Composite

25 20 15 40 30 45 50

10.2 Modeling corrosion control

671

10.2.4 Modeling using field operating conditions The modeling described in section 10.2.3 is mainly based on laboratory tests of coatings, and it does not include field operating conditions. Oil and gas infrastructure is exposed to different environments including soil, sea water, fresh water, and terrain conditions, and it is operated under different conditions including pressure, temperature, and flow. These conditions affect the corrosion control strategies. A methodology to model the influence of field operating conditions is described in this section. Similar to modeling laboratory parameters, it involves two steps: development of a scoring system and prediction of corrosion rate based on that system.

10.2.4a Development of scoring system To develop the scoring system, the field parameters are classified into five categories: steel, construction, soil, operating conditions, and cathodic protection. Each category is given a maximum score of 20 so that the overall field parameter score is hundred (Eqn. 10.17): SField ¼ SPipe þ SConstruction þ SSoil þ SOperational þ SCP

(Eqn. 10.17)

where SField is the overall score for the field parameters, SPipe is the pipe category score, SConstruction is the construction category score, SSoil is the soil category score, SOperational is the operational category score, and SCP is the CP category score.

i. Pipe category The pipe category score depends on five properties: steel grade, pipe diameter, year of manufacture, seam type, and coated or bare. Table 10.25 presents details of scoring for each property and Eqn. 10.18 presents the overall scoring of pipe category. SPipe ¼ SSG þ SDia þ SYM þ SST:seam þ SBP

(Eqn. 10.18)

where SPipe is the pipe category score, SSG is the steel grade score, SDia is the diameter score, SYM is the year manufacture score, SST.seam is the seam type score, and SBP is the coated or bare pipe score.

ii. Construction category The construction category score depends on age of the pipeline, holiday, route change, backfill type, accessories, casing, bend, elevation profile, river crossing, and proximity to other structures. Table 10.26 presents details of scoring for each property and Eqn. 10.19 presents the normalized scoring of construction category. SConstruction ¼

 20  ) SYI þ SHD þ SRTC þ SBT þ SACC þ SCasing þ SB þ SE þ SRVC þ SFeature 54 (Eqn. 10.19)

where SConstruction is the category score, SYI is the year installed score, SHD is the holiday detected score, SRTC is the route change score, SBT is the backfill type score, SACC is the accessories scores, SCasing is the casings score, SB is the bend score, SE is the elevation profile score, SRVC is the river or road or any crossing score, and SFeature is the proximity to other features score.

672

CHAPTER 10 Modeling – External Corrosion

Table 10.25 Scores for Pipe Category Score Category

1

2

3

4

Logic for the Score

Steel grade

X40 e X50

X50 e X60

Diameter, inch

Less than X40 Higher than 26

16 e 26

8 e 16

Higher X60 Less than 8

Manufacturing year

Before 1960

1960e1980

1980e2000

Higher strength steels are more corrosion resistant. The consequence of failure increases, as the diameter increases. Also higher diameter pipelines are susceptible to stresscorrosion cracking. Modern steels are relatively clean and more carefully manufactured. Therefore it is assumed that the susceptibility to corrosion decreases. Welding increases susceptibility to coating failure and corrosion. Pipeline without coating is directly exposed to corrosive environment.

Weld

Bare pipe

Yes

Yes

After 2000

No

No

iii. Soil category The soil category score depends on type of soil, drainage, topography, and SCC susceptibility. Table 10.27 presents details of scoring for type of soil, drainage, and topography.56–59 Only certain coatings in certain soils create conditions for SCC. Table 10.28 presents details of scoring the SCC susceptibility. Eqn. 10.20 presents the overall scoring of soil category. SSoil ¼ SST þ SDrain þ ST þ SSCC

(Eqn. 10.20)

where SSoil is the soil category score, SST is the soil type score, SDrain is the drainage score, ST is the topography score, and SSCC is the SCC susceptibility score.

iv. Operational category The operational category score depends on temperature, pressure, repair, leak or rupture, third party damage, and hydrotesting. Table 10.29 presents details of scoring operational properties and Eqn. 10.21 presents the overall scoring of operational category. SOperational ¼

20 )ST þ SPressure þ SRepair þ SLR þ STP þ SHT 18

(Eqn. 10.21)

where SOperational is the operational category score, ST is the temperature score, SPressure is the pressure score, SRepair is the repair score, SLR is the leak/rupture score, STP is the third party damage score, and SHT is the hydrotesting score.

Table 10.26 Scores for Construction Category Score Category

0

1

2

3

4

5

6

7

8

9

10

Logic for the score

Year since installation

More than 50

45 to 50

40 to 45

35 to 40

30 to 35

25 to 30

20 to 25

15 to 20

10 to 15

5 to 10

Less than 5

As pipeline ages the probability of corrosion increases

Holiday detected

Yes, but no record of being repaired

Yes, but it is repaired

No information if holiday diction was performed

No holiday

Formation of holiday is an indication that the original coating was damaged during the construction

Yes

No

Change of route of a pipeline may have an influence on reestablishment of corrosion control strategies

Backfill type

• Rock • Chalk • Crushed

• Fine soil • Sand • Padding

Certain types of soil cause damage to coating while some provide compactness

Accessories

Yes

No

There are a number of accessories) including: valves, clamps, supports, taps, mechanical couplings, expansion joints, cast iron components, tie-ins, and insulating joints. The presence of them disturb the continuity of coating

Casing

Yes

No

Presence of casing pipe requires additional care to ensure the corrosion control is implemented

Bends

Yes

No

Bend creates stress to the structure

brisk

673

(Continued)

10.2 Modeling corrosion control

Route change

674

Table 10.26 Scores for Construction Category Continued Score 1

2

Elevation profile

Yes

No

Elevation profile creates stress to the structure

River crossing

Yes

No

Most of them are inaccessible. Therefore ensuring that the corrosion control measures are properly implemented is relatively difficult

Proximity of other structure

Yes

No

Several features) may be present closer to the pipelines including other pipelines; structures; electric transmission lines; rail crossings; and paved roads. These structures may interfere with corrosion control measures

)

0

Each accessory/feature should be individually ranked

3

4

5

6

7

8

9

10

Logic for the score

CHAPTER 10 Modeling – External Corrosion

Category

Table 10.27 Scores for Soil Category57e59 Score Category

1

2

Type

Peat

Creeks and Streams

Drainage

Topography

Very poor

•

Undulating

•

Ridged

3

4

•

Rock

•

Cobbles

•

Boulders

•

Gravel

Organic-Gravel

5

6

•

Lacustrine

•

Organic-Silt

Organic-Clay

7

8

•

Moraine Till

•

Glaciofluvial

•

Clay

•

Sand

9

10

Waterways

Alluvium

Logic for the Score The soil types and scores are based on the Canadian Energy Pipeline Association (CEPA) and USA soil classification systems

Poor

Imperfect

Good

A soil with good drainage will let water flow from the pipeline

Depressional

Inclined

Level

Uneven topography may produce localized stress on the pipeline

676

CHAPTER 10 Modeling – External Corrosion

Table 10.28 SCC Susceptibility Score58 Selected Coating Type

Soil Type

Topography

Drainage

Score

Asphalt or Coal Tar

Glaciofluvial or Moraine Till

Depressional Others

Tape

Others Creeks and Streams Lacustrine

Any Any Inclined, Level or Undulating

Any Good Others Any Any Poor or Very Poor Others Poor Others Any Very Poor Others Any Good Others Good Others Any Any

2 1 2 2 1 1

Depressional

Organic (Clay, Gravel or Silt)

Ridged Level or Depressional

Moraine Till

Others Inclined Others

Other

Others Any

Any Any

2 1 2 2 1 2 2 2 1 2 1 2 2

v. Cathodic protection (CP) category The CP category score depends on CP type, CP standard, stray current interference, CP evaluation criteria, and duration without CP. Table 10.30 presents details of scoring CP properties and Eqn. 10.22 presents the overall scoring of CP category. 20 (Eqn. 10.22) SCP ¼ )ðSCPT þ SCPS þ SSCS þ SCPEC þ SDWCP Þ 16 where SCP is the CP category score, SCPT is the CP type score, SCPS is the CP standard score, SSCS is the stray current source score, SCPEC is the CP evaluation criteria score, and SDWCP is the duration without CP score.

10.2.4b Prediction of corrosion rate The corrosion rate predicted from the laboratory data (calculated using Eqn. 10.15) is modified on the basis of the scores in field operating condition (calculated using Eqn. 10.17). By doing this, the scores from laboratory evaluations of external coatings and field operating conditions are integrated. Thus the field corrosion rate, Cfield, is (Eqn. 10.23): 100 CField ¼ CLab ) (Eqn. 10.23) SField where Cfield is the corrosion rate based on field operating conditions. If a laboratory evaluation of coating was not performed or if the information is not available, then a value of 4 mpy is substituted for

Table 10.29 Scores for Operation Category Score Category

0

Temperature,  C)

Pressure (fluctuation), %

Above 25

1

2

3

4

Logic for the Score

Above 95

• 65 to 95 • Below 0

25 to 65

0 to 25

25 to 50

10 to 25

0 to 10

0

In general corrosion rate increases with temperature. Oil and gas industry does not have sufficient experience at sub-zero to accurately predict the behavior The pressure score is calculated using the percent fluctuation between the minimum and maximum temperatures. The percentage is calculated using: P PFluc ¼ Min )Pmin 100% PMax

Repaired

Yes

No

Leak and rupture

Yes

No

Third party damage

Yes

No

Repair of the pipeline indicates that the original material/design was faulty Leakage or rupture indicates that the original material/design was faulty Third party damage may result in the removal of original material (Continued)

10.2 Modeling corrosion control

where PFluc is the percentage fluctuation of operating pressure, PMin is the minimum operating pressure and PMax is the maximum operating pressure

677

678

Score Category

0

Hydrotesting

• No •

1

2 • Hydrotesting

hydrotesting %Diff ¼ 0%

•

done but no information available %Diff ¼ 0 to 25

3

4

Logic for the Score

%Diff ¼ 25 to 50

%Diff higher than 50

The score is calculated by comparing the testing pressure to the maximum pressure in the pipe: PDiff ¼

PH:test PMax )100% PMax

where PDiff is the percentage difference between the maximum operating pressure and hydrostatic test pressure and PH. Test is the hydrostatic test pressure

)

The overall temperature score is determined by taking the lower of the score for the maximum and minimum temperatures

CHAPTER 10 Modeling – External Corrosion

Table 10.29 Scores for Operation Category Continued

Table 10.30 Scores for CP Category Score Category

0

CP Type

CP Standard

Stray current source nearby CP evaluation criteria

No standard followed

Criteria not known

1

2

3

4

Logic for the Score

No CP

CP type not known

Sacrificial anode

Impressed current

See section 9.3.3. for discussion on various CP type

Standard followed but not known

Yes

NACE, CSA, or ISO Standard followed and record available No

Other criteria

100 mV

950 mV or more

• •

More than 75%

50 to 75%

25 to 50%

0 to 25%

0%

Percentage lifetime without CP is calculated using: PNoCP ¼

TAge TCP 100% TAge

Where Pno.CP is the percentage duration when no CP was applied, TAge is the age of the pipe (in months or years) and TCP is the duration with CP (in months or years)

10.2 Modeling corrosion control

Duration without CP

850 mV (ON or OFF) 950 mV in SRB active soil (ON or OFF)

See section 9.3.7 for discussion on stray currents See section 9.3.4 for discussion on CP evaluation criteria

679

680

CHAPTER 10 Modeling – External Corrosion

CLab in Eqn. 10.23. However by doing this, the merits and demerits of the protective coatings are not considered in predicting the corrosion rate. The lifetime of the pipeline is then calculated (Eqn. 10.24):54,60   Pf PMax twi ) LField ¼ 0:85) (Eqn. 10.24) PY CField where LField is the lifetime of the pipe, Pf is the calculated failure pressure, PY is the yield pressure, and twi is the initial pipe wall thickness.

10.2.5 Modeling using above-ground surveys During operation, coatings may lose their integrity and ultimately fail to protect the pipeline. In locations where coatings have failed, the cathodic protection should protect the pipeline. To ensure that the corrosion control strategies are working properly, different surveys are undertaken. They can be broadly divided into: above-ground survey, inline inspection, and below-ground measurements.60–61 Chapter 11 provides details of survey techniques. These surveys are lagging indicators, i.e., they indicate corrosion after it has occurred; whereas a model is a leading indicator, i.e., it predicts the future behavior based on current conditions determined by the survey techniques. This section discusses a model to integrate the results from above-ground and inline inspection (ILI) surveys, and section 10.2.6 discusses a model to integrate the results from below-ground measurements. Similar to modeling laboratory parameters and field operating conditions, the modeling using above-ground and ILI surveys involves two steps: development of a scoring system and prediction of corrosion rate based on the scoring system.

10.2.5a Development of scoring system To develop the scoring system, the survey parameters are classified into five categories: consequence survey, CP current demand survey, above-ground survey, ILI survey, and other survey. Each category is given a maximum score of 20 so that the overall above-ground survey parameter score is 100 (Eqn. 10.25): (Eqn. 10.25) SSurveys ¼ SConsequence þ SCPDemand:S þ SAG þ SILI þ SOther:S where SSurveys is the overall score for the surveys, SConsequence is the consequence survey score, SCPDemand.S is the CP current demand survey score, SAG is the above-ground survey score, SILI is the ILIs score, and SOther.S is the other surveys score.

i. Consequence Corrosion control measures are considered only when the consequence of failure is high. The consequence category score depends on location of the pipeline, the contents it carries, and its diameter. Section 14.2.3 discusses consequences in more detail. Table 10.31 presents details of scoring consequence properties and Eqn. 10.26 presents the overall scoring of the consequence category. 20 (Eqn. 10.26) SConsequence ¼ )ðSLocation þ SContent þ SDia Þ 12 where SConsequence is the consequence category score, SLocation is the location score, and SContent is the contents score.

Table 10.31 Scores for Consequence Score 1

2

3

4

Logic for the Score

Consequence of failure

High

Medium

Low

Nil

Contents

Sour oil and sour gas

CO2, high vapor pressure liquid, and multiphase

Effluent and low vapor pressure liquid

Sweet natural gas

Diameter, inch

Higher than 26

16e26

8e16

Less than 8

Table 14.1 and 14.2 provide further details for ranking consequence. In Table 10.31 lower value is good whereas in Table 14.1 and 14.2 higher value is good. Table 10.31 guidelines should only be used as input for Eqn. 10.26. Table 14.1 provides further details for ranking consequence. In Table 10.31 lower value is good whereas in Table 14.1 higher value is good. Table 10.31 guidelines should only be used as input for Eqn. 10.26. The consequence of failure increases, as the diameter increases. Also the diameter determines the manner in which the contents are released. For e.g., smaller diameter pipeline operates at lower pressure and hence its failure leads to spill or vapor cloud and larger diameter pipeline operates at higher pressure and hence its failure may result in fire (See section 14.2.3c). Larger diameter pipelines are susceptible to stress- corrosion cracking (See section 14.2.3a).

10.2 Modeling corrosion control

Category

681

682

CHAPTER 10 Modeling – External Corrosion

ii. CP current demand The CP current demand category score depends on test point, number of surveys, and current demand. Table 10.32 presents details of scoring CP current demand and Eqn. 10.27 presents the overall scoring of CP current demand category. 20 )ðSTP þ SNS þ SResult:S Þ (Eqn. 10.27) 24 where SCPDemand is the score for CP current demand, STP is the test point score, SNS is the number of surveys score, and SResult.S is the survey result score. SCPDemand ¼

iii. Above-ground surveys Section 11.3 provides details of above-ground survey techniques. In order to obtain valid data, above-ground surveys are conducted using two or more types of techniques, and both surveys are conducted within a one year time interval. The above-ground survey category score thus depends on the number of surveys and the survey results. Table 10.33 presents details of scoring above-ground surveys, and Eqn. 10.28 presents the overall scoring of the above-ground survey category. SAG ¼

20 )ðSNS þ SSR Þ 9

(Eqn. 10.28)

where SAG is the above-ground survey score, SNS is the number of surveys score, and SSR is the average of the two most recent survey results.

iv. Inline inspections Section 11.5 discusses ILI in detail. Table 10.34 presents a procedure to develop ILI scoring. ILI produces the wall loss data for the entire length of the pipeline for which the inspection is carried out. The wall loss data is used to calculate a corrosion rate.

v. Other surveys Coupon surveys are sometimes conducted to ensure that the CP current reaches the metal surface. In addition, other surveys conducted for monitoring non-corrosion activities may provide useful information on the corrosion status, e.g., patrol and leak detection survey. Table 10.35 presents details of scoring other surveys and Eqn. 10.29 presents the overall scoring of other surveys category. SOthers ¼ SCoupon þ SPressure þ SLeak þ SADD

(Eqn. 10.29)

where SOthers is the score for the entire category, SCoupon is the coupon survey score, SP is the patrol survey score, SLeak is the leak survey score, and SADD is the additional survey score.

10.2.5b Prediction of corrosion rate One of the surveys in the above-ground measurement category is the ILI survey. This provides the wall loss directly, from which the corrosion rate can be calculated. Thus, if an ILI has been performed, the corrosion rate can be calculated from ILI data (Eqn. 10.30): CILI:Survey ¼

DILI ðYS YI Þ

(Eqn. 10.30)

Table 10.32 Scores for CP Category Score Category

0

Test point location

No survey

Current demand (uA/cm2))

No survey or greater than 10,000

)

2

3

4

3 or more segments downstream or upstream One survey with tape coating

2 segments downstream or upstream

1 segment downstream or upstream

This segment

One survey with 2 or 3 layer coating

One survey

Two or more surveys

See section 11.3.3 for more details

1,000 to 10,000

8

100 to 1000

12

10 to 100

16

1 to 10

20

Less than 1

Logic for the Model Accuracy of the survey may decrease as the distance the test point and segment increases. Because of the electrical shielding nature of tape coating more survey is required. Higher current demand indicates larger coating damage and higher probability of corrosion. The application of CP is high. Therefore the influence of it in the scoring system is high.

10.2 Modeling corrosion control

Number of surveys, per year

1

683

684

Table 10.33 Scores for Above-ground Survey Category Score 0

1

2

3

4

5

Logic for the Score

Number of surveys

No survey

One or more surveys of a pipe with a tape coating

One or more surveys of a pipe with a 2 or 3 layer coating

There is only one recent survey

There is a pair of recent surveys (within one year of each other) but all the same method

There is a pair of recent surveys (within one year of each other) and they are of different types

Close interval survey, mV

•

Because of the limitations of the aboveground techniques, at least two surveys should be conducted using different techniques within one year interval. The pipeline potential is measured with a reference electrode, positioned directly over the pipeline, at regular intervals, typically about 1 meter. See section 11.3.1 for details. When a DC current is applied to a coated pipe, current flows from the soil to the pipe through defects in the coating, thereby producing voltage gradients in the soil. See section 11.3.2 for details. Pipeline coatings are dielectric. Therefore should have high electrical resistance (i.e., low conductance) See section 11.3.4 for details.

•

Direct current voltage gradient (DCVG), % IR

Coating conductance, (mS/m2)

750 or more positive 1,100 or more negative

Greater than 60

950 to 1100

750 to

850

900 to

950

850 to

900

50 to 60

30 to 50

15 to 30

Less than 15

Greater than 2000

500 to 2000

100 to 500

Less than 100

CHAPTER 10 Modeling – External Corrosion

Survey Category

Alternating Very large current voltage gradient (ACVG)

Pearson, Volume increase

Very high

Greater than Current attenuation, % 50 loss

Large

Medium

Small

Very small

High

Medium

Small

None

40 to 50

30 to 40

20 to 30

Less than 20

10.2 Modeling corrosion control

The current flowing through the defects produces a voltage gradient in the soil, the magnitude of which varies depending on the extent of coating damage. See section 11.3.5 for details. In Pearson method, an AC potential is applied to a pipeline causes flow of current through defects in the coating (i.e., path of least resistance). See section 11.3.6 for details. If the coating is a good dielectric and isolates the pipe from the earth, then the current attenuates logarithmically with distance from the source. See section 11.3.7 for details.

685

686

CHAPTER 10 Modeling – External Corrosion

Table 10.34 Scores for ILI Survey Category Score Survey Category ILI survey

0

4

8

12

16

20

Logic for the Score

No survey

One or more surveys of a pipe with a tape coating

One or more surveys of a pipe with a 2 or 3 layer coating

One survey on pipelines with other coatings

Two or more surveys all of the same ILI type

Two or more surveys with at least two different types of surveys

Every ILI technique has some limitations; therefore at least two surveys should be conducted

where CILI.survey is the corrosion rate (mpy or mm/y, DILI is the maximum depth (mils or mm) of the corrosion feature as determined by the ILI inspection, YS is the year (and month) the survey was conducted; and YI is the year (and month) the pipe was installed. If an ILI survey was not or cannot be performed, then the corrosion rate can be predicted from the above-ground technique score (Eqn. 10.25) using Eqn. 10.31: CSurveys ¼ CField )

100 SSurveys

(Eqn. 10.31)

where Csurveys is the corrosion rate based on survey. If the information needed to use Eqn. 10.23 is not available, then CField in Eqn. 10.31 can be replaced with CLab (calculated using Eqn. 10.15). If the information needed to use Eqn.10.15 is also not available, then a value of 4 mpy may be used for CField in Eqn.10.31. The lifetime of the pipeline is then calculated using Eqn. 10.24, by replacing Cfield with Csurveys.

10.2.6 Modeling using below-ground measurements During operation, the environmental (soil) may be removed to expose pipeline. This provides opportunity to directly determine the status of the infrastructure. This section discusses various Table 10.35 Scores for Other Surveys Category Score Survey Category

0

5

Remarks

Coupon survey

No

Yes

Coupon survey provides information on the effectiveness of cathodic protection.

Patrol survey

No

Yes

Patrol survey indicates any unintentional leakage from the oil and gas pipelines. The leakage may be due to corrosion.

Leak detection survey

No

Yes

Leak detection survey indicates any unintentional leakage from the oil and gas pipelines. The leakage may be due to corrosion.

Additional survey, if any

No

Yes

Any other surveys which may indicate corrosion related information.

10.2 Modeling corrosion control

687

below-ground measurements and a model to integrate the results from below-ground measurement. Similar to modeling laboratory parameters, field operating conditions, and above-ground measurement, the modeling of below-ground measurement involves two steps: development of a scoring system and prediction of corrosion rate based on the scoring system.

10.2.6a Development of scoring system The overall score for the below-ground measurement is based on five categories: soil, coating, chemical, corrosion, and repair (Eqn. 10.32): SFBGM ¼ SSoil þ SCoating:B þ SChem=Mirco þ SCorrosion þ Srepair:C

(Eqn. 10.32)

where SFBGM is the overall score for the FBGM, SSoil.B is the soil category score, SCoating is the coating category score, SChem/Micro is the chemical/microbial category score, SCorrosion is the corrosion category score, and SRepair.C is the repair category score.

i. Soil category Section 10.2.4 discusses the soil parameters from the perspective of initial field operating conditions. This section discusses the scoring of soil based on the conditions prevailing when the below-ground survey is conducted. The soil scoring depends on pipe to soil potential, soil resistivity, soil classification, moisture content, and pH. Table 10.36 presents details of scoring soil category and Eqn. 10.33 presents the overall scoring of soil category. SSoil:B ¼

 20  ) SPSP þ SWF þ SResis þ SSC þ SMC þ SpH 40

(Eqn. 10.33)

where SPSP is the pipe to soil potential score, SWF is the water-filled coating score, SResis is the soil resistivity score, SSC is the soil classification score, SMC is the moisture content score, and SpH is the pH score.

ii. Coating category Corrosion probably occurs when the coating deteriorates. The coating category score depends on visual inspection of coating, type of defect, pattern of defect, adhesion of coating, accumulation of solution below the coating, and the pH of the solution. Table 10.37 presents details of scoring coating category and Eqn. 10.34 presents the overall scoring of coating category. SCoating ¼

 20  ) SV þ STCD þ SPD þ SA þ SSlBC þ SpHBC þ SSdBC þ SCR 28

(Eqn. 10.34)

where SV is the visual score, STCD is the type of coating defect score, SPD is the pattern of defect score, SA is the adhesion score, SSlBC is the solution below coating score, SpHBC is the pH below coating score, SSdBC is the solids below coating score, and SCR is the coating removal score.

iii. Chemical/Microbial category The chemical and microbial environment around the pipelines influences the probability of coating deterioration, effectiveness of cathodic protection, and probability of corrosion. Table 10.38 presents details of scoring chemical and microbial environment and Eqn. 10.35 presents the overall scoring of chemical and microbial category (see also sections 11.7.5 and 11.7.6).

688

Table 10.36 Scores for Soil category Score) 1

2

3

Standard followed for pipe to soil potential

No standard

Other standard

NACE TM0497

Results of pipe to soil measurement, mV Vs. CCS

550 to 750 with SCC and Pitting

Water-filled coating

Yes

No

Standard followed for resistivity measurement

No standard

Other standard

ASTM G57 and G187

Resistivity measurement, Ohm/cm

Less than 1000

1,000 to 5,000

5,000 to 10,000

Soil classification

Ranking same for soil classification in Table 10.2.7

Standard followed to determine the moisture content

No standard

Other standard

AASHTO T265

Moisture content, Percentage

More than 20

10 to 20

5 to 10

Standard followed to measure pH

No standard

Other standard

ASTM D4972

pH

5.5 to 10

• Less than 4 • No measurement

4.5 to 5 and Above 10

)

750 to

900 mV with MIC

4

5

Other values

Remarks

The potential region between 550 and 900 is susceptible to corrosion (See section 11.7.2 for details) (See section 11.7.1 for details) 10,000 to 50,000

Greater than 50,000

(See section 11.7.3 for details)

1 to 5

The standard score and measurement score are summed to calculate the overall score for that category

1

Higher moisture contents sustains corrosion

5.5 to 10 is the SCC susceptibility region. pH less than 4 acidic and corrosive. (See section 11.7.4 for details)

CHAPTER 10 Modeling – External Corrosion

Survey Category

Table 10.37 Scores for Coating Category Score Survey Category

0

1

2

3

4

Visual inspection

Detached from substrate

Any other noticeable change Holiday Patch 50 to 80

Wrinkled

Discolored

Good

Disbondment Random 10 to 50

Bulging Isolated 1 to 10

No defect No defect Less than 1

Type of defect Pattern of defect Adhesion, Percentage disbondment Solution below coating

Continuous 80 to 100

Yes

Solids below coating

Coating removed )

No standard

Other standard

ASTM D4972

5.5 to 10

Less than 4 No measurement

4.5 to 5 and Above 10

Yes

No

Yes

No

The standard score and measurement score are summed to calculate the overall score for that category

e

Indicated permeation of coating, creating conditions for corrosion to take place.

e

5.5 to 10 is the SCC susceptibility region. Less than pH 4 is acidic and corrosive. May be due to evaporation of solution or due to improper surface preparation. Coating is removed only when it is damaged.

10.2 Modeling corrosion control

Standard followed to measure pH) pH value)

No

Remarks

689

Table 10.38 Scores for Chemical and Microbial Category Score) 2

3

Standard followed for measuring soil sulfate

No standard

Other standard

ASTM D516

Concentration of sulfate, mg/L

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring soil sulfide

No standard

Other standard

EPA 376.1

Concentration of sulfide, mg/L

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring soil chloride

No standard

Other standard

ASTM D 512

Concentration of chloride, mg/L

Greater than 100

50 to 100

25 to 50 or No data

Standard followed for measuring soil carbonate

No standard

Other standard

In-house standard

Concentration of carbonate, mg/L

Greater than 1000

100 to 1000

Standard followed for measuring soil bicarbonate

No standard

Other standard

In-house standard

Concentration of bicarbonate, mg/L

Greater than 1000

100 to 1000

11 to 100

Standard followed for measuring soil microbial sulfate reducing bacteria (SRB)

No standard

Other standard

In-house standard

Concentration of SRB, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring soil microbial heterotrophic aerobic bacteria

No standard

Other standard

In-house standard

Concentration of soil microbial heterotrophic aerobic bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

11 to 100

4

5

Remarks Increase of sulfate may increase the severity of SRB activity.

1 to 10

Less than 1

Higher concentration of sulfide may be due to SRB activity. 1 to 10

Less than 1

Chloride ion increases the susceptibility to pitting corrosion. 10 to 25

1 to 10

Less than 10

Less than 1

Higher concentration of carbonate increases the probability of corrosion.))

Less than 1

Higher concentration of bicarbonate increases the probability of corrosion.)))

or No data

1 to 10

or No data Higher concentration of SRB increases the probability of corrosion. 1 to 10

1 to 10

Less than 1

Less than 1

Higher concentration of heterotrophic aerobic bacteria increases the probability of corrosion.

CHAPTER 10 Modeling – External Corrosion

1

690

Survey Category

Other standard

In-house standard

Concentration of soil microbial anaerobic bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring soil microbial acid producing bacteria

No standard

Other standard

In-house standard

Concentration of soil microbial acid producing bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating sulfate

No standard

Other standard

ASTM D516

Concentration of beneath coating sulfate, mg/L

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating sulfide

No standard

Other standard

EPA 376.1

Concentration of beneath coating sulfide, mg/L

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating chloride

No standard

Other standard

ASTM D 512

Concentration of beneath coating chloride, mg/L

Greater than 100

50 to 100

25 to 50 or No data

Standard followed for measuring beneath coating carbonate

No standard

Other standard

In-house standard

Concentration of beneath coating Greater than 1000 carbonate, mg/L

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating bicarbonate

Other standard

In-house standard

No standard

Higher concentration of anaerobic bacteria increases the probability of corrosion. 1 to 10

Less than 1

Higher concentration of APB decreases pH and increases the probability of corrosion. 1 to 10

Less than 1

Increase of sulfate may increase the probability of SRB activity. 1 to 10

Less than 1

Higher concentration of sulfide may be due to SRB activity. 1 to 10

Less than 1

Chloride ion increases the susceptibility to pitting corrosion. 10 to 25

Less than 10

Higher concentration of carbonate increases the probability of corrosion.)) 1 to 10

Less than 1

Higher concentration of bicarbonate increases the probability of corrosion.)))

(Continued)

691

No standard

10.2 Modeling corrosion control

Standard followed for measuring soil microbial anaerobic bacteria

692

Table 10.38 Scores for Chemical and Microbial Category Continued Score) 1

2

3

4

5

Concentration of beneath coating bicarbonate, mg/L

Greater than 1000

100 to 1000

11 to 100 No data

1 to 10

Less than 1

Standard followed for measuring beneath coating microbial sulfate reducing bacteria (SRB)

No standard

Other standard

In-house standard

Concentration beneath coating of SRB, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating microbial heterotrophic aerobic bacteria

No standard

Other standard

In-house standard

Concentration of beneath coating microbial heterotrophic aerobic bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

Standard followed for measuring beneath coating microbial anaerobic bacteria

No standard

Other standard

In-house standard

Concentration of beneath coating microbial anaerobic bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 No data

Standard followed for measuring beneath coating microbial acid producing bacteria

No standard

Other standard

In-house standard

Concentration of beneath coating microbial acid producing bacteria, cFU/ml

Greater than 1000

100 to 1000

11 to 100 or No data

)

Remarks

Higher concentration of SRB increases the probability of corrosion. 1 to 10

Less than 1

Higher concentration of heterotrophic aerobic bacteria increases the probability of corrosion. 1 to 10

Less than 1

Higher concentration of anaerobic bacteria increases the probability of corrosion.)) 1 to 10

Less than 1

Higher concentration of APB decreases pH and increases the probability of corrosion.))) 1 to 10

Less than 1

The standard score and measurement score are summed to calculate the overall score for that category Higher concentration of carbonate ion normally decreases corrosion. But is considered here as increasing the probability of corrosion based only on its effect in increasing the solution conductivity ))) Higher concentration of bicarbonate ion normally decreases corrosion. But is considered here as increasing the probability of corrosion based only on its effect in increasing the solution conductivity ))

CHAPTER 10 Modeling – External Corrosion

Survey Category

10.2 Modeling corrosion control

SChemical=Microbial ¼

0

20 B )@ 144

SSSa þ SSSi þ SSCi þ SSCa þ SSBC þ SSMSR þ SSMHA þ SSMA þSSMAP þ SBCSa þ SBCSi þ SBCCi þ SBCCa þ SBCBC þSBCMSR þ SBCMHA þ SBCMA þ SBCMAP

693

1 C A

(Eqn. 10.35)

where SSSa is the soil sulfate score, SSSi is the soil sulfide score, SSCi is the soil chloride score, SSCa is the soil carbonate score, SSBC is the soil bicarbonate score, SSMSR is the soil microbial sulfate reducing score, SSMHA is the soil microbial heterotrophic aerobic score, SSMA is the soil microbial anaerobic score, SSMAP is the soil microbial acid producing score, SBCSa is the beneath coating sulfate score, SBCSi is the beneath coating sulfide score, SBCCi is the beneath coating chloride score, SBCCa is the beneath coating carbonate score, SBCBC is the beneath coating bicarbonate score, SBCMSR is the beneath coating microbial sulfate reducing score, SBCMHA is the beneath coating microbial heterotrophic aerobic score, SBCMA is the beneath coating microbial anaerobic score, and SBCMAP is the beneath coating microbial acid producing score.

iv. Corrosion category Characterization of corrosion is a direct measure of the effectiveness of coating and cathodic protection. Table 10.39 presents details of scoring corrosion category and Eqn. 10.36 presents the overall scoring of chemical and microbial category (see also section 11.7.7). SCorrosion ¼

 20  ) SProduct þ ST þ SDepth þ SLength þ SCorrosion:C 25

(Eqn. 10.36)

where SProduct is the corrosion products score, ST is the corrosion type score, SDepth is the corrosion feature depth score, SLength is the corrosion feature length score and SCorrosion.C is the corrosion feature cluster score.

Table 10.39 Scores for Corrosion Category Survey Category

Score 1

2

3

4

5

Remarks

Corrosion products

FeS

FeCO3

FeO

Others

No

Type

SCC

Pitting

Narrow axial external corrosion

General

No

Formation of any products indicates occurrence of corrosion. If both coating and cathodic protection function there should be no corrosion. Indicates progress of corrosion. Indicates progress of corrosion. Indicates progress of corrosion.

Depth Length Cluster

0

Any depth Any length Yes

No No No

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CHAPTER 10 Modeling – External Corrosion

v. Repair category When the pipeline and coating are in good condition, no repair is carried out. The excavated ditch is refilled and operation continues. In this scenario, the score for SRepair is 20 (see also section 10.2.7 before scoring). When the infrastructure has extensive corrosion, making it unsuitable for further operation, the section is replaced with new material with new coating. In this scenario, the score for SRepair is again 20. When the surface only has minor corrosion feature, but is otherwise fit for service based on engineering assessment (see section 14.3.3f), the surface is polished to remove any corrosion defect, sandblasted, and a new repair coating is applied. Under this scenario, the score for SRepair is calculated using Eqn. 10.37:     twi tR SRepair:C ¼ ðSRC þ SMLR Þ) 100 100 (Eqn. 10.37) twi where SRC is repair coating score, SMLR is the mainline-repair coating compatibility score, and tR is the remaining wall thickness. SMLR depends on the compatibility between mainline and repair coatings and its value may range between 0 and 5. It is assumed that one of the girth weld coatings is also used as repair coating (see section 10.2.7). The SRC is calculated using Eqn. 10.38: SRC ¼

SRci )15 100

(Eqn. 10.38)

where SRci is the initial repair coating score and is calculated for the repair coating as though it is a mainline coating, i.e., the procedure described in section 10.2.3a is followed.

10.2.6b Prediction of corrosion rate Below-ground measurement enables the direct measurement of pit or corrosion feature depth, from which the corrosion rate can be directly calculated. Thus if a depth measurement has been performed, the actual corrosion rate can be calculated (Eqn. 10.39): CFBGM ¼

DDM ðYS YI Þ

(Eqn. 10.39)

where CFBGM is the corrosion rate (mpy or mm/y) from below-ground measurement, and DDM is the maximum depth (mils or mm) of the corrosion feature as determined by direct measurement. If the pit measurement is not performed because there are no corrosion pits, or cannot be performed because the coating is in good condition, then the corrosion rate can be predicted from the belowground measurement score (Eqn. 10.32) and from field corrosion rate (Cfield) (Eqn. 10.23) using Eqn. 10.40: CFBGM ¼ CField )

100 SFBGM

(Eqn. 10.40)

where CFBGM is the corrosion rate based on below-ground measurement. If the information needed to use Eqn. 10.23 is not available, then CField in Eqn. 10.40 can be replaced with CLab (calculated using Eqn. 10.15). If the information needed to use Eqn.10.15 is also not available, then a value of 4 mpy may be used for CField in Eqn.10.40. The life time of the pipeline is then calculated using Eqn. 10.24, by replacing Cfield with CFBGM.

10.2 Modeling corrosion control

695

Table 10.40 Maximum Expected Life of Mainline Joint Coating Combinations62 Years Mainline Coating Type

Mainline Coating Alone

MainlineLiquid Epoxy

Mainline-Liquid Urethane

MainlineTape

MainlineSleeve

FBE 2-Layer 3 layer Composite

40 30 45 50

32 15 18 25

16 6 18 20

24 24 36 30

24 24 36 30

10.2.7 Modeling the effect of joint coatings In the early days of the oil and gas industry, coatings were only applied in the field, but now, mainline coating is applied onto line pipe, in coating mills. The line pipe sections, with modern coating, are then shipped to the field, where they are joined (by welding) to produce pipeline. After welding, coatings to protect these welded sections are applied. These coatings are known as girth weld coatings or joint coatings. In addition, coatings are applied in the field on couplings, irregular fittings, as well as to repair the main line coatings (see section 9.2.2 for more details). A recent study investigated the compatibility between 13 girth weld coatings with four mainline coatings using cathodic disbondment, impact, flexibility, pull adhesion, peel, and hot water immersion tests (see section 10.2.2). The test panels had both mainline and girth weld coatings and were prepared by removing a portion of previously applied mainline coating and applying a girth weld coating. Before performance testing, the panels were exposed to four different temperatures for four months. Based on the results, relative rankings on the compatibility between 13 girth weld coatings with four mainline coatings have been established.62 From their relative performances in the tests, a general guideline on how long the mainline coating and girth weld coating combination may be effective in protecting the steel can be developed, as a first approximation (Table 10.40).

10.2.8 Modeling the effect of insulators Section 9.2.4 discusses the application of insulators on top of anticorrosion coatings. Corrosion can occur below the insulation when water enters beneath the insulator. Water may enter when the insulator on top of the anticorrosion coating has been completely destroyed or has deteriorated. Such a mode of failure provides free passage to water. In this mode of failure, the corrosion may be controlled by the application of CP. In this scenario, the CP current would also follow the path of the water to reach the pipeline surface and would protect it from corrosion. On the other hand, if the insulator deteriorates elsewhere, providing an entry point for water, and if the water subsequently migrates laterally along the pipeline and then penetrates through the anticorrosion coating to reach the steel surface, then corrosion may occur beneath an intact insulator. Under this situation, CP may not reach the steel surface to protect it. Studies have indicated that no lateral movement occurred on properly applied insulation. However, no model is currently available to predict the long-term performance of an insulator over the entire duration of oil and gas infrastructure operation.63–65

696

CHAPTER 10 Modeling – External Corrosion

10.2.9 Modeling the effect of metallic coatings Section 9.2.5 describes some characteristics of metallic coatings. They are normally used as under coatings below polymeric coatings. The performance of thermally sprayed coatings depends on certain critical properties. A corrosion potential of w 0.725 vs. Saturated Calomel Electrode (SCE) is a good measure to determine whether the metallic coating effectively protects the steel. An adhesion strength of at least 1,000 psi (6.9 MPa) is required, but that of most metallic coatings exceeds 2,300 psi (16 MPa). Thermally sprayed aluminum is susceptible to crevice attack in the absence of oxygen. Oxygen is required to repair any holidays in the oxide film. If the rate of oxygen supply is lower than the oxygen required for repairing aluminum oxide, corrosion takes place inside the crevice. In the traditional polymeric coating and CP system for protecting underground pipelines, the coating is the first line of defense. When the coating fails, CP is the backup, and the pipeline is protected. However there are situations in which both the coating and CP fail to protect the pipeline, and the susceptibility to corrosion and SCC increases.66,67 Scenarios where such conditions develop include: • •

The coating disbonds but does not conduct CP towards the pipe surface. Ground water penetrates between the disbonded coating and the pipe surface. The coating fails (e.g., holidays form) and exposes the pipe surface. Ground water accumulates on top of the pipe surface, but a highly resistive soil prevents CP from reaching the surface.

In these scenarios, the presence of a metallic sacrificial coating will be beneficial as the third line of defense. Metals with active (negative) potentials in the galvanic series are suitable candidates as metallic sacrificial coatings. The introduction of a third line of defense may cause different scenarios, four of which are discussed below.

10.2.9a Scenario 1: Good adherence of polymeric top-layer coating In this scenario, the polymeric top-layer coating is the primary source of protection. It will protect the pipeline under all conditions – whether it is CP permeating or not, whether the pipeline is in low- or high-resistance soil, whether external CP is functional or not, or whether a metallic coating is present or not. The application of metallic coating is not necessary in this scenario.

10.2.9b Scenario 2: Disbondment of CP permeating polymeric top-layer coating in conducting soil In scenario 2, external CP is the primary source of protection. When the first line of protection (polymeric coating) fails, the CP first interacts with the metallic coating moving its potential in the positive direction (noble direction), dissolves it to expose the underlying steel, and ultimately protects the pipeline steel. The selection of metallic under-layer coating is critical in this scenario. One should not select a metallic coating with a corrosion potential in between that of steel and the external CP potential. If such a system were chosen, then when the polymeric coating fails, the external CP would cathodically protect the metallic coating rather than the steel. This situation would be worse if the metallic coating also disbonded from the steel surface. Under such conditions, the metallic coating does not protect the steel, and it prevents external CP from reaching the steel surface.

10.2 Modeling corrosion control

697

An ideal metallic under-layer coating should be one that has a stable corrosion potential that is more negative than the external CP potential and negative to that of pipeline steel. Under this scenario, if the metallic under-layer coating is present, the CP will move the potential of the metallic coating to 850 mV (or whatever the applied potential is) vs. CCS. The pipe will be protected by both metallic coating and CP. But the CP decreases the efficiency of the metallic coating by moving its potential in the positive direction; as a result, the metallic coating will anodically dissolve, ultimately leaving the traditional external CP system to protect the steel. However, the reaction product from the dissolution of the metallic coating may create pressure, and spall off the polymeric coating. If this happens, then the CP current demand will likely be higher than it would be in the absence of a metallic coating, as more polymeric coating would disbond than if the metallic under-layer coating were not present. Promising metallic coatings have corrosion potentials of around 1,000 mV vs. CCS, which is more negative than both the external CP potential ( 850 mV vs. CCS) and the steel corrosion potential ( 670 mV vs. CCS). Of the four metallic coatings evaluated in one study,66 85%Zn–15%Al and 48% Zn–52%Al are more suitable than pure Zn or Al because of their stable corrosion potential, stable galvanic corrosion current, and good adhesion to steel.

10.2.9c Scenario 3: Disbondment of CP permeating polymeric top-layer coating in non-conducting soil Under this scenario, the pipe will only be protected by the metallic coating. This is the ideal situation for using the metallic under-layer coating. The pipe would be protected by the metallic under-layer coating when the solution accumulates between the steel and the polymeric top-layer coating. If this situation is prolonged, it is likely that the metallic under-layer coating will all dissolve and, because the external CP is shielded, the pipe will corrode. However if the corrosion products of the metallic coating adhere onto the steel, further protection may be expected. The absence of a metallic under-layer coating establishes potentials that are known to initiate near neutral pH SCC.

10.2.9d Scenario 4: Disbondment of CP non-permeating polymeric coating This situation is similar to the one described in scenario 3. It is another situation in which the presence of a metallic coating is beneficial.

10.2.10 Modeling the effect of concrete coatings Section 9.2.6 discusses the application of concrete coatings. Their reliability depends on two factors: the durability of the concrete itself, and the permeation of water and other species (e.g., chloride ions) through it to reach the polymeric coating. The durability of concrete depends on the temperature cycle, alkali-aggregate reactions, presence of sulfates, flow, and carbonation.68 Field experience with concrete coatings in the oil and gas industry is limited, but the infrastructure industry (building and bridges) have long experience in controlling the corrosion of rebar steel in concrete structures with polymeric coating and cathodic protection. The sequence of materials in both cases is the same; i.e., steel/polymeric coating/concrete/cathodic protection. Before using knowledge transferred from other industries, one important aspect should be noted. The use of polymeric (anticorrosion) coatings has been controversial in the infrastructure industry with some recommending their use and others recommending against them; i.e., the use of polymeric coating is an option in the

698

CHAPTER 10 Modeling – External Corrosion

infrastructure industry. In contrast, the use of polymeric coatings is mandatory in the oil and gas industry, and concrete coatings are only used in special situations; i.e., the use of concrete coatings is optional.69,70 The occurrence of corrosion beneath a concrete coating may be predicted using two parameters: the chloride threshold and the incubation time. Steel will begin to corrode when aggressive species (e.g., chloride ions) penetrate through the concrete and reach a certain concentration. The minimum chloride ion concentration at which corrosion initiates is commonly called the chloride threshold. Corrosion may also initiate when the pH around steel decreases, due, for example, to carbonation. There is a threshold time after which corrosion initiates on steel inside concrete. Thus, the first step in predicting corrosion under concrete is to determine the concentration of aggressive species (e.g., chloride ion and CO2) as a function of time. After the aggressive species reach threshold concentrations the steel starts to corrode. The presence of a polymeric (anticorrosion) coating may delay the development of corrosion conditions beneath concrete coatings. As long as they adhere well on to steel as well as onto concrete the probability of corrosion is low. When the concrete coating is properly formulated and applied on polymeric coating, no disbonding of the polymeric coating from either steel or concrete occurs. A properly applied epoxy coating can protect steel from corrosive environments containing chloride ions up to 0.08 weight percent. Loss of coating adhesion may not necessarily lead to corrosion, as long as the CP current reaches the steel surface through concrete and polymeric coatings. A limited laboratory study has indicated that the concrete coating, anticorrosion coating, and CP are compatible. Because of their porous structure, concrete coatings are highly permeable to water. Consequently, this allows the permeation of CP current. The pH beneath the concrete coating reaches alkaline values; consequently the corrosion probability is low. It was found experimentally that the cathodic disbondment area of anticorrosion coating beneath the concrete coating was far less than similar coatings in the absence of concrete coatings. Although there was only one measurement of a concrete coating, it was evident that its presence did not accelerate the deterioration of the anticorrosion coating, i.e., the technology of reliably applying concrete coatings has been perfected. Concrete coatings do not create chemical environments for accelerated disbondment of anticorrosion coating.71

10.3 Modeling corrosion Strategies to mitigate external corrosion are implemented from the manufacturing or installation stage itself. Therefore, corrosion becomes a threat only when the mitigation strategies fail. Section 10.2 discusses models to predict the performance of mitigation strategies. In that section a constant corrosion rate of 4 mpy was assumed, with a premise that even properly applied corrosion control strategies cannot prevent corrosion but can only keep it to a low value. This section describes models to predict the most common types of corrosion which occur on the external surfaces of oil and gas infrastructures.

10.3.1 Modeling localized pitting corrosion Section 5.5 describes the general mechanism of pitting corrosion. The objective of modeling is to provide the operators the knowledge on how long the structure can be operated after the corrosion

10.3 Modeling corrosion

699

mitigation measures have failed. The operator can therefore schedule the inspection or maintenance activity accordingly. The accuracy of scheduling such activities depends on the accuracy of the predicted corrosion rate, which also provides an estimate of the corrosion allowance, which in turn is useful in determining the wall thickness of the infrastructure. The oil and gas industry almost always determines the corrosion allowance for carbon steel using the corrosion rates obtained from long-term field tests. These tests were conducted by the National Bureau of Standards (NBS) between 1920 and 1947. Salient features of the study and the corrosion rates reported are described in the following paragraphs.72 This study was carried out in 47 sites across the United States of America (USA). Table 10.41 presents characteristics of the soil in these 47 sites. They covered all eight basic soil types in the USA as classified by the Department of Agriculture. Pipes made from eight different types of ferrous alloy were used. All pipes were of 6 inch (152 mm) in length. They were either 1.5 inches (38 mm) in diameter (0.145 inch (3.7 mm) thickness) or 3 inches (76 mm) in diameter (0.216 inch (5.5 mm) in thickness). Samples were retrieved from the sites at regular intervals, with the last set retrieved after 12 or 17 years. The change in mass was measured after the removal of corrosion products. The corrosion penetration was measured from the deepest pit on the pipe. Both measurements were the average of two samples. The general corrosion rate and pitting corrosion rate were calculated from mass loss and pit depth by dividing them by exposure time. Table 10.42 presents the pitting corrosion rates measured in each site. The pitting ratio was calculated from the ratio of maximum pitting corrosion rate to

Table 10.41 Characteristics of Soil in 47 Sites in USA Where Long-Term Field Tests Were Conducted72 Soil Property

Unit

Minimum

Maximum

Conductivity Mean temperature Annual precipitation Moisture equivalent Air pore space Soil density Volume shrinkage (shrinkage by drying) Burial depth pH Total acidity Naþ Ca2þ Mg2þ HCO3 Cl SO24

S/m C Mm Percentage Percentage Kg/m3 Percentage

0.002 4 300 3 1 1.3  103 0.1

2 21 1,600 80 40 2.1 x103 40

M

0.5 3 0.005 0.002 0.0006 0.001 0.0008 0.0001 0.0008

2.4 9.5 0.4 0.5 0.008 0.1 0.02 0.5 0.5

mol/kg mol/kg mol/kg mol/kg mol/kg mol/kg mol/kg

of soil of soil of soil of soil of soil of soil of soil

700

CHAPTER 10 Modeling – External Corrosion

Table 10.42 Maximum Pitting Corrosion Rate of Carbon Steel in Underground Soil in Various Sites in the USA55,72 Ratio of Maximum Pit Depth to Maximum General Corrosion Depth (m/m)

Pitting Corrosion Rate, mm/y Site

Mean

Standard Deviation

Minimum

Maximum

Range

Mean

Standard Deviation

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

0.23 0.16 0.33 0.20 0.14 0.10 0.14 0.35 0.28 0.19 0.32 0.16 0.42 0.42 0.23 0.30 0.13 0.24 0.28 0.15 0.29 0.23 0.45 0.08 0.15 0.19 0.14 0.38 0.34 0.12 0.13 0.17 0.23 0.15 0.09

0.05 0.07 0.19 0.06 0.05 0.09 0.07 0.29 0.26 0.13 0.19 0.08 0.22 0.24 0.13 0.13 0.05 0.14 0.20 0.05 0.06 0.08 0.12 0.03 0.06 0.12 0.05 0.09 0.09 0.03 0.06 0.05 0.07 0.05 0.05

0.15 0.07 0.12 0.11 0.06 0.03 0.05 0.12 0.07 0.08 0.12 0.05 0.16 0.17 0.08 0.12 0.05 0.08 0.12 0.06 0.22 0.12 0.30 0.02 0.06 0.05 0.06 0.23 0.19 0.06 0.06 0.09 0.09 0.07 0.01

0.35 0.35 0.79 0.37 0.25 0.35 0.25 1.43 1.14 0.57 0.89 0.40 0.95 1.50 0.56 0.57 0.21 0.59 0.88 0.25 0.40 0.41 0.79 0.13 0.26 0.48 0.27 0.57 0.57 0.19 0.29 0.30 0.43 0.27 0.31

0.21 0.28 0.67 0.27 0.19 0.32 0.20 1.31 1.07 0.49 0.77 0.35 0.79 1.33 0.48 0.45 0.16 0.51 0.75 0.20 0.18 0.29 0.49 0.10 0.20 0.42 0.21 0.34 0.38 0.13 0.23 0.21 0.35 0.20 0.29

6.2 6.8 13.4 6.7 6.0 27 6.7 16.0 13.8 8.0 35.9 15.7 8.1 26.4 6.7 9.5 3.6 17.4 16.0 6.9 10.5 7.1 5.1 17.3 14.8 16.1 5.9 5.4 5.5 7.2 10.1 12.8 5.8 8.7 10.2

1.1 2.6 3.9 2.5 2.1 32.7 2.6 11.4 10.6 2.7 16.0 7.5 2.6 18.9 2.5 3.0 0.7 10.2 6.3 1.8 3.0 1.8 0.7 8.5 6.0 9.8 2.0 1.3 1.3 1.9 3.3 3.9 1.5 2.9 5.4

10.3 Modeling corrosion

701

Table 10.42 Maximum Pitting Corrosion Rate of Carbon Steel in Underground Soil in Various Sites in the USA55,72 Continued Ratio of Maximum Pit Depth to Maximum General Corrosion Depth (m/m)

Pitting Corrosion Rate, mm/y Site

Mean

Standard Deviation

Minimum

Maximum

Range

Mean

Standard Deviation

36 37 38 39 40 41 42 43 44 45 46 47

0.15 0.23 0.09 0.17 0.24 0.20 0.32 0.30 0.25 0.23 0.31 0.08

0.06 0.09 0.04 0.05 0.07 0.05 0.10 0.12 0.10 0.07 0.15 0.03

0.06 0.13 0.04 0.10 0.14 0.10 0.18 0.15 0.12 0.15 0.10 0.03

0.31 0.57 0.18 0.29 0.38 0.30 0.53 0.63 0.55 0.41 0.70 0.12

0.25 0.44 0.14 0.19 0.23 0.20 0.34 0.47 0.43 0.26 0.60 0.09

14.1 7.2 13.7 8.2 7.5 9.1 7.8 6.2 18.6 7.6 13.7 7.0

4.1 1.6 7.7 2.1 1.6 1.6 2.5 2.7 5.6 1.8 4.6 1.9

(See Table 10.40 and Fig.12.10)

maximum general corrosion rate. Table 10.42 presents the pitting ratio for each site. The pitting corrosion rate and pitting ratio do not exhibit any trend, indicating that there is no correlation between the general corrosion and pitting corrosion rates. The calculation of general and pitting corrosion rate assumed that the corrosion rate was essentially constant over time. However, analysis of data from samples retrieved at different intervals of time indicated that both general and pitting corrosion rates decreased with exposure time (Figure 10.16). The pitting corrosion rate decreased at a higher rate than the general corrosion rate. In general, when surface layers form, they resist the transportation of reactants and products across them. Consequently corrosion rates decrease with time. Equation 10.42 presents a general relationship between corrosion rate and time: Ccorr ¼ atb

(Eqn. 10.42)

where Ccorr is the corrosion rate, and ‘a’ and ‘b’ are constants. The value of ‘b’ varies between 0 and 1 and normally a value of 0.5 is assumed. Values of ‘b’ greater than 1 indicate that the pit growth rate increases with time. Analysis of the data obtained in this study indicates that value of ‘b’ is less than one, but it does not reveal an exact value for ‘b’. A constant corrosion rate derived from the NBS study has been used for designing underground carbon steel infrastructure for the oil and gas industry. This rate is used as a starting point irrespective of operating conditions and local soil environment. The operator may use a lower corrosion rate when they can demonstrate that the anticipated corrosion rate is lower than that derived from this study.

0.50

1

0.40

0.8

0.30

0.6

0.20

0.4

0.10

0.2

Mass loss rate (g/m2/d)

CHAPTER 10 Modeling – External Corrosion

Average penetration rate (mm/y)

702

0

0.00 1 to 3

3 to 5

5 to 7

7 to 9

9 to 11

11 to 15 Above 15

Duration, Years FIGURE 10.16 Variation of Corrosion Penetration Rate as a Function of Exposure Duration.55,72

10.3.2 Modeling stress corrosion cracking Section 5.17 discusses the general mechanism of SCC. SCC has caused several high profile failures in oil and gas transmission pipelines. Such failures occur in specific steel exposed in specific environments, operating under specific conditions. Approaches have been made to model SCC, but model development and validation is not conclusive.73–76 This section summarizes the experience gained by the industry. SCC develops under slow loading cycle conditions (typically one cycle per day). The same pipeline in sea water does not develop SCC. In a medium loading cycle (typically 100 cycles per day) fatigue corrosion cracks develop. In a fast loading cycle (typically several hundred cycles per day) fatigue cracks develop. In this condition, the amount of time during which the metal is in contact with the environment in the loading cycle is minimal, so corrosion does not contribute to the failure. In general, a steel pipe in a bicarbonate-carbonate environment75 (Figure 10.17) undergoes two types of SCC: high pH SCC and near neutral pH SCC. Table 10.43 shows the typical chemical species present in environments leading to the two types of SCC. Table 10.44 presents the main differences between these two types of SCC.77

10.3.2a High pH SCC High pH SCC is intergranular; i.e., the cracks grow along the grain boundaries. For this reason the cracks are narrower and tighter (Figure 10.18).78 Metals and alloys with grain boundaries which are more reactive (i.e., have a higher corrosion tendency) than the grains are susceptible to high pH SCC. The air-formed thin protective surface layer on carbon steel is stable in a carbonate/bicarbonate environment with pH greater than 9, and in the presence of cathodic protection. This surface layer protects the carbon steel from corrosion. If the surface layer is stretched and broken due to operational

10.3 Modeling corrosion

703

Relative Percentage of Substance (%)

100

80 H CO HCO Low pH

60

HCO

CO High pH

40

20

0 3

4

5

6

7

8

9

10

11

12

13

14

pH

FIGURE 10.17 Near Neutral pH SCC and High pH SCC Susceptible Regions.

stress or strain (e.g., pressure fluctuation), then the steel is exposed, and SCC initiates. If the strain is elastic in nature (i.e., reversible), the surface layer is reformed and the SCC stops growing, but if it is plastic in nature (i.e., irreversible), the surface layer does not form again and the SCC continues. Thus the crack initiates, becomes dormant, and grows depending on the pressure fluctuations.

10.3.2b Near neutral pH SCC Near neutral pH SCC is transgranular, i.e., the cracks grow across or through the grains (Figure 10.19).78 The cracks are larger (than high pH SCC), with corrosion occurring on their side walls. In general, near neutral pH SCC occurs when three conditions simultaneously exist: susceptible metal, corrosive environment, and tensile stress. Steel is susceptible to near neutral pH SCC if it undergoes plastic deformation (i.e., permanent elongation of metal) in localized areas. Cyclic load may cause plastic deformation in steels at nominal Table 10.43 Typical Chemical Compositions of Solution Leading to Different Types of Scc76 Species

Near Neutral pH SCC

High pH SCC

pH Carbonate) Bicarbonate) Carbonic acid) Chloride ion) Nitrate ion)

5.5 to 7.5 0.00002 0.15 0.04 0.0024 0.000005

Above 9.3 0.83 0.47 Not available 0.063 0.0037

)

Average content in percentage weight of species in solutions in solution found under coatings in regions susceptible to SCC

704

CHAPTER 10 Modeling – External Corrosion

Table 10.44 Characteristics of High pH and Near Neutral pH SCC in Pipelines76 Factor Location

Temperature

Environment

Corrosion potential

Crack path and morphology

Near Neutral pH SCC (Non-Classical) 65 percent occurred between the compressor station and the first downstream block valve (distances between valves are typically 16 to 30 km) 12 percent occurred between the first and second valves 5 percent occurred between 2nd and 3rd valves 18% occurred downstream of the third valve SCC associated with specific terrain conditions, alternate wetdry soils, and soils that tend to disbond or damage coatings No apparent correlation with temperature of pipe. Appear to occur in the colder climates where CO2 concentration in groundwater is higher Dilute bicarbonate solution with a neutral pH in the range of 5.5 to 7.5 At free corrosion potential: 760 to 790 mV (CCS) Cathodic protection does not reach pipe surface at SCC sites Primarily transgranular (across the steel grains) Wide cracks with evidence of substantial corrosion of crack side wall

High pH SCC (Classical) Typically within 20 km of compressor station Number of failures falls markedly with increased distance from compressor and lower pipe temperature. SCC associated with specific terrain conditions, alternate wetdry soils, and soils that tend to disbond or damage coatings

Growth rate decreases exponentially with temperature decrease

Concentrated carbonatebicarbonate solution with an alkaline pH greater the 9.3 600 to 750 mV (CCS) Cathodic protection is effective to achieve these potentials Primarily intergranular (between the steel grains) Narrow, tight cracks with no evidence of secondary corrosion of the crack wall

stress levels after several cycles. The number of cycles before steel suffers localized plastic deformation depends on its chemistry and other properties. Its susceptibility increases as its mechanical strength increases. However, its susceptibility to near neutral pH SCC also depends on steel chemistry and non-metallic impurities. SCC occurs when the length of its non-metallic impurities (e.g., manganese sulfides) exceeds a certain value (normally above 200 to 250 mm). The presence of mill scale and pits also increases the SCC susceptibility. When the coating disbonds from the surface, and prevents CP current from reaching the surface it establishes an environment conducive to near neutral pH SCC. Polyethylene coatings are known to cause such susceptible environments (Table 10.45) in the following way. A clay soil adheres onto the

10.3 Modeling corrosion

705

FIGURE 10.18 A Typical High pH SCC Morphology.78 Reproduced with permission from the National Energy Board.

FIGURE 10.19 A Typical External Near Neutral pH SCC Morphology.68 Reproduced with permission from the National Energy Board.

706

CHAPTER 10 Modeling – External Corrosion

Table 10.45 Distribution of SCC Failures With Type of Coating77 Coatings Applied on a Transmission Pipeline

Percentage Failure Due to Near Neutral pH SCC

Polyethylene tape Coal tar Asphalt Others

73 9 9 9

polyethylene coating when wet and pulls the coating from the steel when dry. The repeat of this process ultimately wrinkles the coating (see section 10.2.2b). If the pipeline with wrinkled coatings is in a poorly drained soil which retains moisture around the pipe, or in a depressed landscape (e.g., the base of a hill or near a stream) which facilitates the flow of water along it, the ground water penetrates beneath the polyethylene tape. Further, if the composition of the ground water is in the range indicated in Table 10.46, and if CO2 dissolves in the water stabilizing the pH between 5.5 and 7.5, then a near neutral pH susceptible environment is created.79 As the temperature decreases, more CO2 dissolves in water decreasing the pH. It is for this reason near neutral pH is predominant in cold countries such as Canada and Russia. Near neutral pH SCC has also been experienced with pipelines protected by other coatings (e.g., asphalt and coal tar). This happens when the pipeline is in the sandy well-drained soil (i.e., dry and high-resistant) in which driving the CP current across is difficult. Table 10.47 presents various sources of stress; operating pressure (internal pressure) is the major contributor. This stress, commonly known as hoop stress, is calculated using the Barlow formula (Eqn.10.41): s¼

Pdpipe 2tw

(Eqn. 10.41)

where s is the hoop stress, P is the operating pressure, dpipe is the diameter of the pipe and tw is the wall thickness.

Table 10.46 Typical Compositions (G/L) of Solutions in the Near Neutral pH SCC Susceptible Regions79 Name of Solution Chemicals

NS1

NS2

NS3

NS4)

KCl NaHCO3 CaCl2.2H2O MgSO4.7.H2O

0.149 0.504 0.159 0.106

0.142 1.031 0.073 0.254

0.037 0.559 0.008 0.089

0.122 0.483 0.181 0.131

)

Commonly used to simulate near neutral pH SCC environment in the laboratory

Table 10.47 Sources of Stress in a Pipeline44 Longitudinal (axial) Stress

Remarks

Internal operating pressure (hoop stress)

This is the highest stress component in a pipeline

When a pipeline is buried and restrained from moving in the longitudinal direction, longitudinal stress is about one third of hoop stress. When a pipeline is not restrained from moving in the longitudinal direction, the longitudinal stress is about one half of hoop stress

Maximum pressure, pressure fluctuation (R value), and rate of pressure fluctuation influence the stress value

Residual stress

Yes

Bending stress

Yes

Local stresses

Yes

Soil movement

Yes. Only a minor component when the pipeline is squeezed due to soil settlement

Major component when soil movement bends cyclically

Due to temperature variation

Through the thickness of the pipeline

Along the length of the pipeline

Residual stress is due to manufacturing process, e.g., welding. However, expansion process during manufacturing of coating, grit-blasting during application of coatings, and hydrotesting reduce the residual stress Bending stress is due to deformation of pipe, e.g., dent and other manufacturing errors (pipe edges are offset from one another) Local stresses are due to mechanical defects, e.g., gouges, corrosion pits, small dents Soil movement is due to land slides, land settlement, and/ or by the physical weight of the soil above the pipe (overburden) Usually not a major contributor

707

Circumferential Stress

10.3 Modeling corrosion

Source

708

CHAPTER 10 Modeling – External Corrosion

Table 10.48 Maximum Allowable Operating Stress1 in Various Class Locations in Canada44 Maximum Operating Stress (% of SMYS)4 Class location2

Description3

Natural Gas

Sour Gas

HVP

LVP

1 2

Less than 10 dwellings 10 to 46 dwellings or designated areas Greater than 46 dwellings Buildings 4 storeys or more

80 72

72 60

80 64

80 80

56 44

50 40

64 64

80 80

3 4 1

As per CSA Z662e94 Based upon a class location area which extends 200 m on both sides of the center line of any continuous 1.6 km length of pipeline 3 Z662e94 clause 4.3.2 contains full description 4 Maximum operating stress may be lower due to the hydrostatic testing pressure and other factors such as proximity to roads and railway 2

Commonly, the stress on a pipe wall is expressed as specified minimum yield strength (SMYS) which is a percentage of the hoop stress. Regulations in several countries specify the maximum hoop stress as 72% SMYS, and others specify a maximum hoop stress depending on the location in which the pipeline operates. Table 10.48 presents typical maximum hoop stresses prescribed in Canada. The stress of the pipeline depends not only on the total pressure, but also on the extent and frequency of pressure fluctuation. The pressure fluctuation is given as the ‘R ratio’, which is the ratio of the minimum to the maximum pressure. In a gas pipeline, the pressure fluctuation depends on the rate at which the gas is injected into and withdrawn from it, and in an oil pipeline, the pressure fluctuation depends on the pump speed (on and off of pump) and changes in fluid density. Laboratory tests indicate that for a given number of cycles the crack growth rate is higher at lower frequencies than at higher frequencies. At lower frequencies, the contact time for interaction between the cracks and environment is longer, therefore the cracks grow faster. Stress can act in two directions: circumferential stress acts around the pipeline and longitudinal or axial stress acts along the length or axis of the pipeline. The actual stress at any given point is the combined effects of both circumferential and longitudinal stresses. Cracks form in the direction perpendicular to the direction of the stress (Figure 10.20):80 • •

Circumferential stress creates longitudinal cracks and Longitudinal stress creates circumferential cracks.

About 75% of near neutral pH SCC failures experienced in Canada are longitudinal (axial) cracks, indicating that circumferential stress caused them. The failures have occurred in Class 1 (see Table 10.48) locations which allow higher pressures, i.e., higher stress levels. Stress influences near neutral pH SCC by initiating SCC cracks. There is an uncertainty in the industry over whether or not a threshold stress for crack initiation exists. In general, higher pressures (higher SMYS) and higher pressure fluctuations (higher R value) increase the probability of crack

10.3 Modeling corrosion

709

Diameter Circumferential stress

Wall thickness

P P P P

Longitudinal (axial) cracks

Longitudinal (axial) stress

P P Circumferential (transverse) cracks

P P

P = Pressure

FIGURE 10.20 Directions of Axial and Circumferential Stresses on a Pipeline.70 Reproduced with permission from the National Energy Board.

initiation. Stress also increases the number of SCC cracks initiated. Figure 10.21 presents the number of SCC colonies per unit area of pipe.81 Except for one data point, the number of colonies increases with increased operating pressure. In general, the larger the number of cracks per unit area, the more closely spaced they are.

FIGURE 10.21 Influence of Internal Pressure on Near Neutral pH SCC.71 Reproduced with permission from the National Energy Board.

710

CHAPTER 10 Modeling – External Corrosion

FIGURE 10.22 Typical Near Neutral pH Life Cycle.72 Reproduced with permission from the National Energy Board.

Stress also influences the rate of SCC growth. There is a threshold stress below which the cracks do not grow. This threshold stress depends on the type of steel and the environment. Increasing applied stress (pipeline operating pressure) and decreasing R value normally increase the crack growth rate. Heat-affected zone have about 30% higher growth rates, and the presence of pearlitic microstructure stops crack growth. The time-averaged near neutral pH SCC growth rate in a Canadian gas transmission pipeline was found to be about 2  10 8 mm/s (0.63 mm/y). Figure 10.22 presents a typical SCC life cycle.82 Cracks may initiate, grow, become dormant, reinitiate, and re-grow. For this reason the crack growth rate over short intervals of time may be higher or lower than the time-averaged crack growth rate. Crack growth rates observed in the laboratory vary between 10 9 mm/s (0.03 mm/yr) to 10 6 mm/s (30 mm/y) depending on the stress and fluctuations in it. Stress further coalesces the cracks. As adjacent cracks grow, their tips may join together to form a longer crack. When cracks coalesce, the crack growth rate accelerates. An increase in the operation pressure of the pipeline increases the probability of the formation of several cracks in close proximity to one another. The distance between adjacent cracks determines whether they coalesce, become dormant, or grow apart. Studies have indicated that circumferential cracks at distances less than 20% of the wall thickness become dormant, and those at distance greater than 20% coalesce. Studies have also indicated that colonies of cracks long in the longitudinal direction and narrow in the circumferential direction tend to align head-to-tail with one another and coalesce, whereas colonies of cracks with similar length and width tend to grow on the edge of the colony and become dormant.

References

711

10.3.3 Modeling AC corrosion Section 5.23 discusses the mechanism of AC corrosion. This occurs above a threshold AC current density of approximately 100A/m2. The risk of AC corrosion can be estimated using Eqn. 10.42:83 iac ¼

8Vac rsoil p:dholiday

(Eqn. 10.42)

where iac is the AC current density, Vac is the AC voltage of the structure to remote earth, rsoil is the soil resistivity, and dholiday is the diameter of a circular holiday having an area equal to that of the actual holiday.

References 1. Papavinasam S, Attard M, Revie RW. Modes of failures of external polymeric pipeline coatings. Materials Performance 2006;45(10):28–30. 2. Papavinasam S, Attard M, Revie RW. Performance Evaluation of External Polymeric Coatings for Pipeline Protection, Corrosion 2007, Paper #7021, NACE International, Houston, TX, USA (2007). 3. Papavinasam S. Permeability and electrocatalytic properties of film prepared by electropolymerisation of maminophenol. Synthetic Metals 1993;58:173–85. 4. Banach JL. Pipeline coatings – evaluation, repair, and impact on corrosion protection design and cost. CORROSION 1987, Paper # 29. Houston, TX: NACE; 1987. 5. Compton KG. Selection of protective coatings for metals. Corrosion 1948;4(3):112. 6. Allen ER. A coating evaluation testing program. Corrosion 1958;14(12):546t. 7. Senkowski E. Standard laboratory tests for pipeline coatings. Materials Performance 1979;18(8):23. 8. Vincent L., Surface preparation standards. Houston, Texas: NACE Corrosion conference 2001, Paper # 1659. 9. Beavers JA. PR186–917. Assessment of the effects of surface preparation and coatings on the susceptibility of line pipe to stress-corrosion cracking; February 1992. 10. Rodriguez V, Castaneda L, Luciani B. Effect of contaminants on FBE performance. Houston, Texas: NACE Corrosion 98, Paper #612; 1998. 11. Partridge PE. PRCI PR247–9511. Effects of phosphoric acid treatment on the performance of fusion bonded epoxy coatings; October 1997. 12. Chappelow CC, Cooper GR, Pinzino CS, LaRue B, Rose D, Spurlin SR. AGA Project #. Pr-138–907. Effect of substrate contaminants on the performance of fusion-bonded epoxy pipeline coatings; January 1992. 13. Line Pipe Coating Analysis Volume 1: Laboratory studies and results. (Appendix A: Background and data for the characterization of basic coating materials and free films), November 1978, American Gas Association, A. G.A. Catalog # L00036. 14. Tsuru T, Sagara A, Haruyama S. Acoustic emission measurements to evaluate the degradation of coating films. Corrosion 1987;43(11):703. 15. Papavinasam S, Revie RW. Protective Pipeline Coating Evaluation, NACE CORROSION 2006, Paper #6047, NACE International, Houston, TX, USA (2006). 16. Shepperd LR. Determining the effect of formulation on physical properties of asphalt mastic coatings. Corrosion 1961;17(4):157t. 17. Korobov Y, Salem L. Stress analysis as a tool in coatings research. MP 1990;29(4):30. 18. A. Zdunek, G. Shubinsky, K. H. Jan, ‘inspection and evaluation of protective coatings by visual imaging techniques,’ NACE CORROSION 95/Paper # 592, Houston, Texas.

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19. P. E. Partridge, ‘Maximizing the accuracy and precision of cure determination of fusion bonded epoxy by differential scanning calorimetry,’ NACE CORROSION 2000/Paper # 0770. 20. Temple G, Coulson KEW. The use of differential scanning calorimetry to determine coating cure. MP 1985; 24(11):17. 21. Gray W, Lunn H, Mcardle O. Evaluation of epoxy pipeline coatings. MP 1983;22(7):9. 22. Neal P. Fusion-bonded epoxy coatings-cure and glass transition temperatures. MP 1993;32(2):49. 23. Mills G. Interpretation of differential thermal data analysis for fusion bonded epoxy powder coatings. MP 1984;23(6):45. 24. Neal P. Fusion-bonded epoxy cure by solvent extraction. MP 1994;33(11):26. 25. Hamner N. Adhesion fundamentals and methods of testing organic coatings. MP 1970;9(5):31 and Line Pipe Coating Analysis Volume II: Topical Report on Adhesion, November 1978, AGA Catalog # LOOO37. 26. Shepperd LR. Determining the effect of formulation on physical properties of asphalt mastic coatings. Corrosion 1961;17(4):157t. 27. Banach JL. Pipeline coatings – evaluation, repair, and impact on corrosion protection design and cost, CORROSION 87, Paper #29, NACE International, Houston, TX, USA (1987). 28. Lukezich SJ, Hancock JR, C.Yen B, Werner P. Prediction of the field performance of anti-corrosion coatings for buried steel pipelines. International Gas Research Conference; 1992. 512 GTI Headquarters1700 S Mount Prospect RoadDes Plaines, IL 60018. 29. Lukezich SJ, Hancock JR, Yen BC. State-of-the-art for use of anticorrosion coatings on buried pipelines in the natural gas industry. Gas Research Institute, GRI-92/0004; April 1992. Werner, S. J. Lukezich, ‘Selection and use of anticorrosion coatings for corrosion control of buried natural gas pipelines,’ 92-DT-63. 30. Sloan RN. 50 years of pipe coatings we have come a long way. Houston, Texas: NACE CORROSION 1993, Paper # 17; 1993. 31. Sridhar N, Dunn S, Seth M. Application of a general reactive transport model to predict environment under disbonded coatings. Corrosion 2001;57(7):598. 32. Orazem ME, Esteban JM, Kennelley KJ, Degerstedt RM. Mathematical models for cathodic protection of an underground pipeline with coating holidays: part 1 –theoretical development. Corrosion 1997;53(4):264. 33. Song FM, Kirk DW, Graydon JW, Cormack DE. Steel corrosion under a disbonded coating with a holiday – part 2: corrosion behavior. Corrosion 2003;59(1):42. 34. Papavinasam S, Revie RW. ‘Coating gap analysis’, PRCI Report #L51971. 35. Papavinasam S, Revie RW. Coatings for pipelines. In: Smith C, Siewert T, Mishra B, Olson D, Lassiegne A, editors. Coatings for Corrosion Protection: Offshore oil and gas operation facilities, Marine Pipelines, and Ship Structures. NIST Special Publication 1035; 2004. p. 178. 36. Papavinasam S, Revie RW. Advanced coatings R&D for pipelines and related facilities. Pipeline protective coating; June 9–10, 2005. National Institute of Standards and Technology (NIST), NIST Special Publication 1044, September 2005. 37. NACE Technical Committee, Laboratory Evaluation of Coatings. Materials Performance Journal 1962; 1(6):10. 38. Smith HM, Bird MF, Penna RH. Examination of tests for buried-pipe coatings. MP 1991;30(1):18. 39. Norman D, Swinburne R, Roder WR. polyurethane and epoxy coatings for the rehabilitation and repair of pipelines. Houston, Texas: NACE CORROSION 2000, Paper #758; 2000. 40. Kellner J. laboratory evaluation of in-ground cathodic disbondment of pipeline coatings. MP 1986;25(9):20. 41. Kellner J. Non-destructive evaluation of cathodic disbondment. MP 1983;22(7):25. 42. Papavinasam S, Attard M, Revie RW. Determination of blister formation of external pipeline coatings based on current spikes in the cathodic disbondment test. Corrosion 2009;65(10):639–44. 43. Jack TR, Boven GV, Wilmott M, Worthingham RG. Evaluating performance of coatings exposed to biologically active soils. MP 1996;35(3):39.

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44. National Energy Board, Canada. Report of the Inquiry, Stress corrosion cracking on Canadian oil and gas pipelines; November 1996. MH 2–95, ISBN: 0–662–25246–2, National Energy Board, 311 Sixth Avenue S. W., Calgary, AB, Canada, T2P 3H2. 45. Papavinasam S, Attard M, Revie RW. Laboratory methodologies to simulate field operating conditions of external pipeline coatings. Journal of Protective Coatings and Lining February 2009. 46. Papavinasam S, Revie RW. ‘Coating gap analysis’, PRCI Report #L51971. 47. Papavinasam S, W.Revie R. Coatings for pipelines. In: Smith C, Siewert T, Mishra B, Olson D, Lassiegne A, editors. Coatings for corrosion protection: offshore oil and gas operation facilities, marine pipelines, and ship structures. NIST Special Publication 1035; 2004. p. 178. 48. Papavinasam S, Attard M, Revie RW. ‘Electrochemical impedance spectroscopy measurement during cathodic disbondment experiment of pipeline coatings’, Journal of ASTM International, 6, 3, Paper ID. JAI 101247. 49. Hack JP, Scully JR. Defect area determination of organic coated steels in seawater using the break point frequency method. J Electrochem Soc 1991;138(1):33. 50. Gray GSL, Appleman BR. EIS: electrochemical impedance spectroscopy: a tool that can measure remaining life in protective coatings?. Tampa, Florida: SSPC 2002 National Conference; November 3–6, 2002. 51. Sauerbrey G. The use of quartz oscillators for weighing thin layers and for microweighing. Z. Phys 1959;155:206. 52. Papavinasam S, Attard M, Revie RW. ‘electrochemical quartz crystal microbalance technique to monitor diffusion through external polymeric pipeline coating’, Journal of ASTM International 6, 3, Paper ID. JAI 101246. 53. Papavinasam S, Doiron A. A 5-M approach to control external pipeline corrosion. Paper #14151, Houston Texas: NACE CORROSION; 2010. 54. NACE Standard RP0502. Pipeline external corrosion direct assessment methodology. NACE International, Houston, TX, USA. 55. Ricker RE. Analysis of pipeline steel corrosion data from NBS (NIST) studies conducted between 1922–1940 and relevance to pipeline management. Gaithersburg, MD 20899, NISTIR 7415: National Institute of Standards and Technology; May 2, 2007. 56. Papavinasam S, Doiron A. Methodologies for Evaluating and Qualifying External Pipeline Coatings for Northern Pipelines, Corrosion 2009, Paper No. 9051, NACE International, Houston, TX, (2009). 57. Canadian Energy Pipeline Association (CEPA) Stress Corrosion Cracking Recommended Practices. 2nd ed.; Dec. 2007. 58. NACE RP0204 – 2004Stress corrosion cracking (SCC) direct assessment methodology; November 2004. 59. USDA. Soil taxonomy a basic system of soil classification for making and interpreting soil surveys. Washington, DC: The Soil Survey Staff, Natural Resources Conservation Service, US Dept. of Agriculture; 1999. 60. API 1160, ‘Managing system integrity for hazardous liquid pipelines’. American Petroleum Institute, 1220 L Street, NWWashington, DC 20005-4070 61. NACE RP0104. The use of coupons for cathodic protection monitoring applications. NACE International, Houston, TX, USA 62. Papavinasam S, Zaver N, Matchim M, Pannerselvam T, DeRushie C, Doiron A, Pollock J. ‘Laboratory methodologies to evaluate the compatibility between mainline and girthweld coatings’, NACE CORROSION 2013, Paper #2176, Houston Texas. 63. Papavinasam S, Doiron A. Relevance of cathodic disbondment test for evaluating external pipeline coatings at higher temperatures. Houston, TX: NACE Corrosion Conference, 2009, Paper No. 9050; 2009. 64. Papavinasam S, Krausher J, Ghods P, Isgor OB. Evaluation of compatibility between thermal insulator, external coating, and cathodic protection at 150 C. Houston, Texas: Paper #18649, NACE; 2011. 65. Papavinasam S, Matchim M. Compatibility between pipeline anticorrosion coating and thermal insulator in the presence of cathodic protection. Paper #2175, Houston Texas: NACE Corrosion; 2013.

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66. Papavinasam S, Arsenault B, Attard M, Revie RW. metallic under-layer coating as third line of protection of underground oil and gas pipelines from external corrosion. Corrosion 2012;68(12):1146–53. 67. Papavinasam S, Attard M, Arseneult B, Revie RW. State-of-the-art of thermal spray coatings for corrosion protection. Corrosion Reviews 2008;26(2–3):105–46. 68. Virmani YP, Clear KC, Pasko TJ. Time-to-corrosion of reinforcing steel in concrete slabs: vol. 5 – calcium nitrite admixture or epoxy coated reinforcing bars as corrosion protection systems. Report No. FHWA-RD83/012, Federal Highway Administration September 1983. 69. Broomfield JP. Modeling the rate of deterioration of reinforced concrete structures. Houston, TX: Corrosion 2011, Paper #11003, NACE; 2011. 70. Lee SK. Characterizing corrosion behavior of disbonded epoxy coated reinforced steel. Houston, TX: Corrosion 2007, Paper # 7274, NACE; 2007. 71. Papavinasam S, Matchim M. Compatibility between concrete coatings, mainline coating, and CP system. Paper #2174, Houston Texas: NACE Corrosion; 2013. 72. Logan KH. Underground corrosion. Washington D. C: National Bureau of Standards (USA); 1945. 73. Beavers JA, Harper WV. Stress corrosion cracking prediction model. Houston, TX: Corrosion 2004, Paper # 4189, NACE; 2004. 74. Zheng W, Chen W. Progress in understanding SCC of existing pipelines and relevance to the new pipelines in the Canadian North. PICon Journal 2005;(11) [accessed 02.03.13], http://www2.nrcan.gc.ca/picon/Journal/ 2005/paper11.asp; 2005. 75. Charles EA, Parkins RN. Generation of stress corrosion cracking environments at pipeline surfaces 1995; 51(7):518. 76. National Energy Board. Based on Figure 3.4, p. 22. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 77. National Energy Board. Table 3.1, p. 16. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 78. National Energy Board. Figs. 3.1 and 3.2, p. 19. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 79. Parkins RN, Blanchard WK, Delanty BS. Transgranular stress corrosion cracking of high-pressure pipelines in contact with solutions of near neutral pH. Corrosion 1994;50(5):394. 80. National Energy Board. Figure 3.15, p. 36. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 81. National Energy Board. Figure 3.17, p. 42. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 82. National Energy Board. Figure 3.23, p. 48. Report of the inquiry: stress corrosion cracking on Canadian oil and gas pipelines; Nov. 1996. MH-2–95, ISBN: 0–662–25246–2, Regulatory Support Office, National Energy Board, 311, Sixth Avenue, S. W., Calgary, Alberta, T2P 3H2. 83. Wakelin RG, Gummow RA, Segall SM. AC corrosion – case histories, test procedures, and mitigation. Houston, TX: Corrosion 98, Paper #565, NACE; 1998.

CHAPTER

Monitoring – External Corrosion

11

11.1 Introduction Chapters 9 and 10 discuss strategies for controlling the external corrosion of infrastructure. As discussed in these chapters, these strategies are part and parcel of the infrastructure; i.e., modern coating is applied as the material (e.g., steel) is produced, and CP is applied, by regulation in most of the world, within the first year of the installation of the underground infrastructure. For this reason, many techniques focus on monitoring the effectiveness of the external corrosion control strategies rather than external corrosion rate of the infrastructure. This approach is thus different from monitoring internal corrosion; internal corrosion monitoring techniques mostly measure the actual corrosion rate or wall loss due to internal corrosion. External monitoring techniques may be broadly classified into holiday detection, above-ground monitoring, remote monitoring, in-line inspection, hydrostatic testing, and below-ground inspection. Holiday detection, above-ground monitoring and remote monitoring mainly focus on the status of the coating, and CP; in-line inspection (ILI), and below-ground inspection mainly focus on the corrosion rate or remaining wall of the infrastructure; and hydrostatic (pressure) testing focuses on the overall strength of the infrastructure in withstanding the operating conditions. This chapter discusses various monitoring techniques and Chapter 14 provides guidelines on the frequency at which these techniques should be used.

11.2 Holiday detection The first step in the external corrosion monitoring is ensuring that the coating completely covers the entire surface of the infrastructure. As discussed in Chapter 10, the larger the area covered by the coating, the lower is the CP requirement. Any defect or discontinuity in the coating, such as uncoated regions, bubbles, voids, cracks, thin spots, metallic inclusions, or contaminants are commonly known in the oil and gas industry as ‘holidays’.1 Almost all protective coatings used for oil and gas infrastructure are polymeric in nature. Therefore, the presence or development of holidays can be detected by electrical devices. Such devices are commonly referred to as ‘jeepers’ or ‘holiday detectors’.2 They apply a voltage and detect the current leakage through the coating. The voltage used depends on the thickness of the coating. Eqn 11.1 presents a general guideline to determine the minimum voltage.3 pffiffiffiffi (Eqn. 11.1) VHoliday ¼ x: tc Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00011-X Copyright Ó 2014 Elsevier Inc. All rights reserved.

715

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CHAPTER 11 Monitoring – External Corrosion

where Vholiday is the minimum voltage required for holiday detection; x is a constant (7,900 if the coating thickness is given in millimeters, or 1,250 if the coating thickness is given in milli-inches); and tc is the coating thickness. The constants indicated are only applicable if the holiday is detected before the pipeline is installed or if the existing pipeline is excavated to detect the holiday. Most holidays develop during transportation of pipeline from the mill where the coating is applied and to the construction site or during the handling and installation of the pipeline. Table 11.1 presents a case history of transporting pipe sections over a distance of approximately 1,500 km (932 mile) on a Canadian winter road.4 To ensure the quality of the coating, holiday detection is performed as soon as the coating is applied, after the line pipe is transported to the construction site, and before it is lowered into the ditch. Any detected holidays are repaired, and holiday detection is performed again to ensure that they have all been dealt with.

Table 11.1 Damage to Coatings from Transporting Pipe Sections for Approximately 1,500 km on Canadian Winter Road4 Defect per 6 Feet Length of Pipe Pipe Diameter, Inches

Coating (Qualification Standard)

By Visual Inspection

36 36 36

Fusion bonded epoxy (CSA Z245.20) Fusion bonded epoxy (CSA Z245.20) Fusion bonded epoxy (CSA Z245.20)

36 36 36 36 36 36 36 36 6 6 6 6 6 6 6 6 6 6 6

Fusion bonded epoxy (CSA Z245.20) Fusion bonded epoxy (CSA Z245.20) Fusion bonded epoxy (CSA Z245.20) Composite (CSA Z245.21.B2) Composite (CSA Z245.21.B2) Composite (CSA Z245.21.B2) Composite (CSA Z245.21.B2) Composite (CSA Z245.21.B2) 2-Layer (CSA Z245.21.A1) 2-Layer (CSA Z245.21.A1) 2-Layer (CSA Z245.21.A1) 2-Layer (CSA Z245.21.A1) 2-Layer (CSA Z245.21.A1) 2-Layer (CSA Z245.21.A1) 3-Layer (CSA Z245.21.B1) 3-Layer (CSA Z245.21.B1) 3-Layer (CSA Z245.21.B1) 3-Layer (CSA Z245.21.B1) 3-Layer (CSA Z245.21.B1)

6

3-Layer (CSA Z245.21.B1)

Multiple chips, scratches, and pinholes One pinhole and multiple dents Multiple scratches, chips, raised pimples 1 chip and multiple scratches 1 chip and multiple scratches Multiple chips and scratches Multiple nicks 1 scratch 1 scratches No damage No damage 1 Nick Multiple nicks Multiple scratches Multiple scratches No damage No damage 1 deep scratch Scratches and nicks 1 small nick 1 dent and metal imbedded in coating Multiple dents and metal imbedded in coating Multiple scratches and one dent

By Holiday Detector 3 1 8 2 2 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

11.3 Above-ground monitoring techniques

717

The following standards provide general guidelines for conducting holiday detection: • •

NACE Standard Recommended Practice RP0274, ‘High-Voltage Electrical Inspection of Pipeline Coatings’. NACE Standard Recommended Practice RP0188, ‘Discontinuity (Holiday) Testing of New Protective Coatings on Conductive Substrates’.

11.3 Above-ground monitoring techniques As described in Chapter 2, most oil and gas industry infrastructure, except for refinery equipment, exists below-ground (onshore structures) or under water (offshore structures). Therefore techniques that do not require physical access to the structures, i.e., above-ground techniques, are valuable for monitoring such structures. The above-ground monitoring techniques may use direct current (DC) techniques or alternating current (AC) techniques. Table 11.2 provides general guidelines when different above-ground techniques can be used.5 Table 11.2 Situations in which Above-Ground Techniques can be Effectively Used5

Conditions Coating holidays Anodic zones with bare pipe Near river or water crossing Frozen ground Stray currents Corrosion under shielding coating Adjacent metallic structure Near parallel pipelines Under high-voltage alternating current overhead electric transmission lines Under paved roads Crossing other pipelines Cased piping At very deep burial location (Generally, a pipe is buried at a 1- to 1.5- m depth (approx.3 to 5 ft.)) Wetlands Rock terrain, rock ledges, rock backfill

Close Interval Survey

Direct Current Voltage Gradient Survey

Alternating Current Voltage Gradient Survey

Pearson Survey

Current Attenuation

2 2 2 3 2 3 2 2 2

1, 3 2 3 1, 3 1, 1, 1,

2 2 2

1, 2 3 2 3 1, 2 3 1, 2 1, 2 1, 2

2 3 2 3 2 3 3 3 2

1, 3 2 1, 1, 3 1, 1, 2

3 2 3 3

3 1, 2 3 3

3 1, 2 3 3

3 2 3 3

1, 2 1, 2 3 3

2 3

1, 2 3

1, 2 3

2 3

1, 2 2

2

2

1: Applicable for small defects, typically less than 1 in2 or 600 mm2 2: Applicable for large defects, typically more than 1 in2 or 600 mm2 3: Generally not applicable

2

2 2 2 2

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CHAPTER 11 Monitoring – External Corrosion

The DC techniques apply direct current to the structure (e.g., pipelines) and measure the resulting potential of the pipeline or the gradient in the earth (see section 9.3.4). The four commonly used DC techniques are close interval survey (CIS) of structure-to-soil potential, DC rail systems, DC voltage gradient (DCVG), cathodic protection current requirement (CPCR), and coating conductance (CC). All DC techniques are susceptible to errors resulting from stray DC current from neighboring structures, such as foreign cathodic protection rectifiers, DC rail systems, or DC welding generators. These should be de-energized during the test period. The success of the DC technique depends on an ability to overcome such interferences. AC techniques apply an AC signal to the structure and measure its voltage drop or current attenuation. Commonly used AC techniques are alternating current voltage gradient (ACVG), electromagnetic current attenuation (ECAT), and transwave system (TS). Electrochemical impedance spectroscopy (EIS) is another AC technique that is widely used in the laboratory (see section 10.2.2b), but this is not used in the field because of the requirement for sophisticated equipment and complex analysis. AC techniques are susceptible to induced AC; so electronic filtering should be used to minimize these effects.

11.3.1 Close interval survey (CIS) Section 9.3 discusses the criteria for applying cathodic protection. A close interval survey is carried out to ensure that the potential of the structure with respect to the environment (soil or water) meets the cathodic protection criteria. Since the potential is measured, CIS may also be known as a close interval potential survey (CIPS). In order to conduct a CIS survey, electrical connection to the structure should be made. This is accomplished by attaching an electrically insulated wire to it. Typically a wire of length 3 to 5 miles is attached and is unwound as the surveyor travels along the structure.6 Further, the centre line of the pipeline should be accurately located to conduct the survey. The survey is conducted by placing a reference electrode directly above the structure (close-earth survey). A copper-copper sulfate (CCS) electrode is commonly used as the reference electrode. The reference electrodes are typically placed at about 1 to 2 m intervals along the structure.7 The potential between the structure and reference electrode is measured using a high-impedance (107 ohms or above) data logger-voltmeter or multimeter. A depolarized or static CIS may also be run to gather the required data to use the 100-mV depolarization criteria (see section 9.3.4d). During the CIS, both ON and instant-OFF potentials are measured (see section 9.3.4). Figure 11.1 presents typical CIS results.8 The regions where both ON and OFF potentials are most positive are those susceptible to corrosion. Some may also consider that all regions where the instant-OFF potentials are more positive than the -850 mV vs. CCS (see section 9.3.4c) criterion are susceptible for corrosion. The extent to which the potential shifts in the positive direction indicates the extent of corrosion susceptibility. It is important to measure both ON and OFF potentials during the CIS and calculate the voltage drop, so that the extent of the potential shift is determined reliably. A CIS may also be conducted on a structure that does not have cathodic protection. In this case, the corrosion potential is measured. The regions where the corrosion potential is the most negative are those susceptible to corrosion (see galvanic series; section 5.2). Figure 11.2 presents a typical CIS conducted on a structure not protected by CP.9

11.3 Above-ground monitoring techniques

719

-1500

Pipe to Soi Potential , mV vs. CCS

Instant-Off Potential

On Potential

-1400 -1300 -1200 -1100 -1000 -900

-850 mV vs. CCS

-800 -700 -600 -500 0

10

20

30

40

50

Pipe length, km FIGURE 11.1 Typical CIS on Structure with Cathodic Protection.8 Current interrupted (Sections with potentials more positive than -850 mV vs. CCS are susceptible to corrosion). Reproduced with permission from NACE International.

Pipe to Soil Potential, mV vs. CCS

-750

-500

-250

0

0

5

10

15

20

25

30

35

Pipe length, Km

FIGURE 11.2 Typical Pipe-to-Soil Potentials on a Structure without Cathodic Protection.9 (Sections with most negative readings are susceptible to corrosion). Reproduced with permission from NACE International.

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CHAPTER 11 Monitoring – External Corrosion

The primary advantage of CIS is that it provides information without exposing the underground infrastructure (e.g., pipeline). Data-logging equipment is available which can record both the potential and distance information. The presence of impressed current anode beds and nearby structures can cause errors in the potential measurement, so all cathodic protection systems on nearby structures should be switched off during CIS or synchronously interrupted. Synchronized current interrupters are used for this purpose.10 GPS timed switching is also becoming the norm. The main disadvantages of the technique are that the potential is recorded only at test points and that it is labor-intensive.11–12 In addition, its reliability depends on the surveyor’s ability to accurately measure an instant-OFF potential. The sensitivity of CIS decreases with increasing infrastructure depth and soil resistance. Both of these factors as well as the voltage drop must be accounted for before establishing the relationship between the corrosion severity rating and the actual coating damage (see section 10.2.1 for more details).13 However, it is generally conceded that CIS cannot easily detect any coating disbondment. CIS is not primarily used for coating evaluation but rather to assess the level of cathodic polarization. Standards providing guidelines for conducting CIS include: • •

NACE Standard Practice SP0207, ‘Performing Close Interval Potential Surveys and DC Surface Potential Gradient Surveys on Buried or Submerged Metallic Pipelines’. NACE Standard Practice SP 0502, ‘Pipeline External Corrosion Direct Assessment Methodology’.

11.3.2 Direct current voltage gradient technique (DCVG)14–17 The DCVG technique is very similar to CIS. Both techniques involve measurement of DC potential: the CIS technique measures structure-to-soil potential, whereas the DCVG technique measures the voltage gradient between two reference electrodes. The center line of the pipeline needs to be accurately located to perform this survey. During DCVG measurement, a DC current is applied to the structure, e.g., a coated pipeline, which triggers current from the soil to the pipe through defects in the coating. The current produces a voltage gradient in the soil which is detected by a DC voltmeter connected between two reference electrodes. If the size of the defect is small, the voltage gradient between the two reference electrodes will be small. As the defect size increases, the voltage gradient increases and becomes detectable. The potential difference between a reference electrode located immediately above a defect and a reference electrode located at remote earth indicates the severity of the defect. DC current may be applied to the pipeline using either an existing rectifier or a temporary current source. With the current on, the surveyor walks along the pipeline placing the reference electrodes at different locations and measures the voltage difference between two reference electrodes. When one of the reference electrodes is placed directly above a coating defect, a voltage difference between the electrodes is observed. The center of the coating defect can be established by adjusting the positions of the electrodes. The voltage gradient is then measured between a reference electrode placed immediately above the center of the defect and an electrode placed far away from the defect. The severity of the defect is thus determined from the voltage gradient. Only standard equipment (for example, reference electrode, voltmeter, current interrupter) and one surveyor are required to conduct DCVG survey. No physical connection to the pipe is required. However, the surveyor needs to walk along the pipeline. A DCVG survey can locate coating defects

11.3 Above-ground monitoring techniques

721

and indicate the severity of defect, but it does not indicate extent of defect. The DCVG survey may indicate if corrosion is active only if the pipeline surveyed has no applied cathodic protection. It does not provide a permanent record of the defect’s location; use of a data logger with global position satellite (GPS) however overcomes this issue. Further the DCVG technique has all limitations discussed for CIS. Standards providing guidelines for conducting DCVG include: • • •

NACE Standard Practice SP 0207, ‘Performing Close Interval Potential Surveys and DC Surface Potential Gradient Surveys on Buried or Submerged Metallic Pipelines’. NACE Standard Practice TM0109, ‘Above-ground Survey Techniques for the Evaluation of Underground Pipeline Coating Evaluation’. NACE Standard Practice SP 0502, ‘Pipeline External Corrosion Direct Assessment Methodology’.

11.3.3 Cathodic protection current requirement technique (CPCR) The amount of current required to cathodically protect a structure depends on the quality of the coating; the better the coating quality, the lesser the current needed. Thus, the CP current indicates the overall quality of the coating and the corrosion condition of the structure. This is the principle behind the CPCR technique. The corrosion potential is first measured at various intervals along the entire length or at each end of the structure. A DC current is then applied to the structure using either a temporary anode or an existing CP current source. The amount of current drawn from the DC source is continuously monitored. ON and instant-OFF potentials are then measured at all the locations where the corrosion potential was measured. An interrupter is used to switch the current on and off to measure ON and instant-OFF potentials. The current applied is adjusted so that the potentials at the end of the pipe section reach a pre-determined value; typically 0.85 V vs. a CCS reference electrode. The line current at different sections of the structure is also measured (see section 11.3.4 for a procedure for measuring line current). The results are plotted by several ways; some typical plots are as follows: • •

• • • • •

For a particular point of the structure, the amount of current flowing into the structure and the potential as a function of time.18 The corrosion potential, ON potential, and instant instant-OFF potential are plotted as a function of distance. Figure 11.3 presents a typical plot. For instance, merging of all three potentials on the right hand side of Figure 11.3 indicates that that section may be short-circuited by another structure (e.g., casing pipe).19 Polarization potential, DVp (the difference between instant-OFF potential and corrosion potential) as a function of distance (Figure 11.4).20 Driving potential, DV (the difference between instant-OFF and ON potential) as a function of distance (Figure 11.4).20 Line current, DI (the difference between ON and OFF current) as a function of distance. When plotting the DI the direction in which the current is flowing is also indicated. DVp as a function of DV (Figure 11.5).21 Current density of a section as a function of time (Figure 11.6).22

722

CHAPTER 11 Monitoring – External Corrosion

Potential Vs. CCS, mV

-1500 -1400

Corrosion Potential

-1300

Instant OFF Potential ON Potential

-1200 -1100 -1000 -900 -800 -700 -600 -500 -10

-8

-6

-4

-2

0

2

4

6

8

10

Length of Pipeline from the Test Point (Arbitrary Unit)

FIGURE 11.3 Typical Pipe-to-Soil Potentials During Cathodic Protection Current Demand Measurement.19 Reproduced with permission from Elsevier.

400 350

Potential, mV

300

Driving Potential Polarization Potential

250 200 150 100 50 0 -15

-10

-5

0

5

10

Pipe Length, Arbitrary Unit FIGURE 11.4 Polarization Potential (DVp) and Driving Potential (DV) Obtained from CPCR Survey as a Function of Pipe Distance.20 Reproduced with permission from Elsevier.

11.3 Above-ground monitoring techniques

723

400

Polarization Potential, mV

350 300 250 200 150 100 50 0

0

50

100

150

200

250

300

350

Driving Potential, mV

FIGURE 11.5 Driving Potential (DE) Versus Polarization Potential (DVp).21 Reproduced with permission from Elsevier.

6

Coating B 5

Year

4

Coating A

3

2

1

1

10

100

1,000

10,000

Current Requirement FA/m2

FIGURE 11.6 Current Density on a Pipe Section Protected with Different Coatings.22

100,000

1,000,000

724

CHAPTER 11 Monitoring – External Corrosion

The CPCR technique is not affected by the depth of pipe burial. Many cross-country pipelines have permanently installed test points for performing CPCR measurement. If permanent test points do not exist along a calibrated length of pipe, then a test lead must be attached carefully without contact resistance. The potential polarization per unit of current density determined by the CPCR technique is a general indication of the quality of the coating. But polarization also depends on soil conditions, moisture content, microbial activity, temperature, and aeration. For example, an increase in the conductance of a coating increases the cathodic protection current density.23 Similarly, a pipe in aerated soil requires a higher current density than a similar pipe in deaerated soil.24 Therefore the CPCR data cannot be readily used to compare coating performances in different environments. The technique requires a measurement of corrosion potential before applying the cathodic protection current, and it further requires the polarized potentials to reach a steady state.25 Therefore this survey is time-consuming. The standards provide guidelines for performing CPCR measurement include: •

NACE Standard Practice TM0109, ‘Above-ground Survey Techniques for the Evaluation of Underground Pipeline Coating Evaluation’.

11.3.4 Coating conductance technique (CC)26–27 The CPCR and the CC techniques are similar; both require current to be applied and the resultant potential to be measured. The CPCR technique measures cathodic polarization, i.e., the difference between the instant-OFF potential and corrosion potential, and provides information on the extent of polarization per unit of applied current density (typically in mV/mA/ft2); whereas the CC technique measures the potential drop across the coating and provides information on coating conductance (in Siemens/ft2). The coating conductance measurement is based on Ohm’s law. Polymeric coatings are dielectric, i.e., they have high electrical resistance (or low electrical conductance). The coating conductance can be determined from the voltage drop across it due to the applied current. As long as the coating is intact, it does not allow current from the structure to the environment, but as it deteriorates, it allows current. This current is commonly known as leakage current and is a measure of coating conductance. Thus, the increase in leakage current is proportional to the deterioration of the coating. Figure 11.7 presents typical a set-up used to determine coating conductance.28 During this survey, a DC current is applied and the resulting voltage change is measured. The CC technique may be broadly classified as a general method, potential attenuation method, or current attenuation method.

11.3.4a General method In this method, two parameters are measured: pipeline-earth potential and long-current in the structure – both under ON and OFF conditions: • •

The change in the potential (DE) is calculated from the ON and OFF potential measurement. When corrosion occurs there is current flow between anode and cathode (see section 5.2). This current is a measure of the corrosion taking place on the surface of structure. This current is known in the oil and gas industry as the long-line current or long-current. If the coating is intact, both corrosion rate and long-current are low; but as coating deteriorates, both corrosion rate and long current increase. The long-current is measured during a coating conductance survey. In ideal

11.3 Above-ground monitoring techniques

725

FIGURE 11.7 Typical Setup to Measure Line Current and Voltage Drop Across the Coating in Order to Calculate Coating Conductance.28 Reproduced with permission from NACE International.

measurement conditions, four test pins are used: two inner pins for current measurement and two outer pins for voltage drop measurement. The distance between the two inner test pins is commonly known as the span length. Figure 11.8 presents a schematic diagram of the four pin arrangement.29 Several such pin arrangements are installed at various locations along the pipeline, or as a minimum two sets of such pins are installed at the ends of the pipeline. Even though steel is a metal, it has some resistance to the flow of current. The magnitude of this resistance depends on the pipe length, pipe diameter, and pipe wall thickness. This resistance causes a voltage difference between test points and is measured using a high resistance dc voltmeter. The

FIGURE 11.8 Four Point Measurement of Pipeline Voltage Drop (To Calibrate Resistance between Terminal 2 and 3).29 Reproduced with permission from NACE International.

726

CHAPTER 11 Monitoring – External Corrosion

Table 11.3 Properties of Steel30

Pipe Size, Inches

Outside Diameter, Inches

Wall Thickness, Inches

Mass per Foot, Pounds

Resistance of One Foot in Microohm [[ (16.061 x 18))/ mass per foot pounds)]))

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

2.375 4.500 6.625 8.625 10.750 12.750 14.000 16.000 18.000 20.000 22.000 24.000 26.000 28.000 30.000 32.000 34.000 36.000

0.154 0.237 0.280 0.322 0.365 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375

3.65 10.80 19.00 28.60 40.50 49.60 54.60 62.60 70.60 78.60 86.60 94.60 102.60 110.60 118.70 126.60 134.60 142.60

79.20 26.80 15.20 10.10 7.13 5.82 5.29 4.61 4.09 3.68 3.34 3.06 2.82 2.62 2.44 2.28 2.15 2.03

)

Steel resistivity is 18 microohm-cm Based on steel density of 489 pounds per cubic foot and steel resistivity. Reproduced with permission from NACE International.

))

resistance of the span length should be known in order to calculate the current from the voltage drop. Table 11.3 presents typical resistances of steel pipe.30 Alternatively, this resistance can be determined by impressing a known amount of current and measuring the voltage change. To do this, the current is applied between the two outer pins and the resultant voltage drop between the two inner pins is measured. This process is repeated for various amounts of current, and these values are used to calculate the resistance of the span (Rspan) length using Eqn. 11.3:   DE1 DE2 DEn n (Eqn. 11.3) Rspan ¼ þ þ .: þ DIn DI1 DI2 where DE1 is the difference between ON and instant-OFF potentials in the first measurement, DI1 is the amount of current applied in the first measurement, DE2 is the difference between ON and OFF potentials in the second measurement, DI2 is the amount of current applied in the second measurement, and n is the number of measurements. The voltage drop between the two inner pins under normal operating conditions is then measured and divided by Rspan to obtain the line current.

11.3 Above-ground monitoring techniques

727

Table 11.4 Typical Data Obtained During Coating Conductance Measurement6,31 Test Point

Units

Test Point 1)

Test Point 2)

Pipe to CuSO4, ON Pipe to CuSO4, OFF DV Pipe span potential drop, ON Pipe span potential drop, OFF Resistance of span length (calibrated) Pipeline current, ON Pipeline current, OFF DI

V V V mV mV Amps per mV

1.75 0.89 0.86 þ0.98 þ0.04)) 2.30

1.70 0.88 0.82 þ0.84 -0.02)) 2.41

Amps Amps Amps

þ2.25 þ0.09 2.16

2.03 0.05))) 2.08

The section between test points 1 and 2 consists of 15,000 feet of coated pipeline with a total external surface area of 50,070 ft2 This data is below the resolution of most meters; it is presented just to illustrate the calculation procedure ))) Negative current indicates that the current is flowing in the opposite direction )

))

Table 11.4 presents typical data in coating conductance measurement.31 The coating conductance is calculated from this data as follows: DEðaverageÞ ¼

0:86 þ ð 0:82Þ ¼ 2

DIðdifferenceÞ ¼ 2:16

0:84V

2:08 ¼ 0:08A

(Eqn. 11.4)

(Eqn. 11.5)

2

Therefore the coating conductance (CC) of the area (50,070 ft ) between the two test points – in Siemens (reciprocal of resistance in ohms): CC ¼

0:08 ¼ 0:095 Siemens 0:84

(Eqn. 11.6)

The coating conductance per unit area (CCA) is then: CCA ¼

0:095 w2:10 50; 070

6

Siemens=ft2

(Eqn. 11.7)

This low value of coating conductance indicate that the coating is in excellent condition (see Table 11.5).

11.3.4b Potential attenuation method If there is any attenuation of potential along the pipeline, then the coating conductance can be determined by the attenuation method. In this method, the ON and OFF potentials are recorded at two ends of the pipeline using the same procedure described in the general method. The attenuation constant is calculated from this measurement using Eqn. 11.8:29,32 aA ¼

a ln DV DVb

L

(Eqn. 11.8)

728

CHAPTER 11 Monitoring – External Corrosion

where aA is the attenuation constant, DVa is the difference in ON and OFF potentials in one end of the pipeline, DVb is the difference in ON and OFF potentials in the opposite end of the pipeline, and L is the length of the section between location ‘a’ and ‘b’. The coating conductance between points ‘a’ and ‘b’ is then given by (Eqn. 11.9): CC ¼

a2A Rpipe

(Eqn. 11.9)

where CC is the coating conductance between points ‘a’ and ‘b’ and Rpipe is the resistance of pipe length (see Table 11.3). The coating conductance per unit area (CCA) is then: CCA ¼

CC A

(Eqn. 11.10)

where A is the surface area of the coated pipe between ‘a’ and ‘b’.

11.3.4c Current attenuation method In the current attenuation method, the ON and OFF line currents are recorded at two ends of the pipeline using the same procedure described in the general method. From the measurement, attenuation constant is calculated using Eqn. 11.11:32 aA ¼

a ln DI DIb

L

(Eqn. 11.11)

where DIa is the difference in ON and OFF line current in one end of the pipeline, DIb is the difference in ON and OFF line current in the opposite end of the pipeline, and L is the length of the section between location ‘a’ and ‘b’. From the aA, the coating conductance between points ‘a’ and ‘b’ and coating conductance per unit area is calculated using Eqns. 11.9 and 11.10 respectively. Soil resistance influences the coating conductance determined using Eqn. 11.7 and Eqn. 11.10. During potential measurement, the reference electrode is placed in the soil. Consequently the resistance (and hence conductance) determined includes that of both the coating and the soil. For this reason, the coating resistance is normalized with respect to a specific soil resistance (Eqn. 11.12): rsoil (Eqn. 11.12) CCnormalized ¼ CC: rnormalized where CCnormalized is the normalized coating conductance in soil of constant resistivity, rsoil is average resistivity (in U-cm) of soil for the length of pipeline for which the coating conductance is measured, and rnormalized is a constant to represent the normalized resistivity and is typically 1,000 U-cm. It should be noted that linear normalization using Eqn. 11.12 may overstate the coating conductance in some situations. Access to the entire pipeline is not required to perform a CC survey, because sufficient accuracy can be achieved by measuring potentials at each end. This technique can be conducted without any knowledge of the corrosion potential, and only requires that the polarized potential be at a steady state. Since the coating conductance depends primarily on defect size and soil resistivity, CCnormalized may be used as a qualitative representation of coating quality (Table 11.5).33 This technique does not pinpoint the location of coating damage. Its accuracy depends on the ability to measure the instant-OFF

11.3 Above-ground monitoring techniques

729

Table 11.5 Qualitative Relationship between Normalized Coating Conductance and Coating Quality29,33 Normalized Coating Conductance 2

Coating Quality

(mS/m )

(mS/ft2)

Excellent Good Fair Poor

Less than 100 101 to 500 501 to 2,000 Greater than 2,000

Less than 10 11 to 50 51 to 200 Greater than 200

potential reliably. This technique is not applicable when parallel pipelines are protected with different coatings and with the same CP source. Standards providing guidelines for conducting this survey include: •

NACE Standard Test Method TM0102, ‘Measurement of Protective Coating Electrical Conductance on Underground Pipelines’.

11.3.5 Alternating current voltage gradient technique (ACVG)34 AC current through defects in the coating (i.e., path of least resistance) produces a voltage gradient in the soil. For a given pipe depth and environment (e.g., soil resistivity) the magnitude of the voltage gradient depends directly on the extent of coating damage. During the survey, an AC signal is applied to the pipeline and the resulting voltage gradient in the earth is monitored using an electrode pair separated by a fixed distance. The monitoring device may contain an array of such electrode pairs. The voltage gradient is normally displayed on a scale between 0 to 100 dB (decibel) mV or simply dB. The center line of the pipeline must be accurately located for carrying out this survey. To conduct the survey, an AC current is applied to the pipe section and a surveyor walks along the pipe taking measurement using the electrode pair at regular intervals (typically at every 1.5 to 3 m (5 to 10 feet)). When the first electrode is directly over a coating defect, the voltage difference between the two electrodes is at its maximum. When the defect is in between the electrodes, a slight depression in the signal is noticed. Again when the second electrode is directly over the coating defect the voltage difference is at the maximum again. Figure 11.9 presents a typical result.35 Normally a signal above 30 dB indicates the presence of a coating defect. When a defect is suspected, the survey interval is reduced (typically to 0.3 m or 1 ft) and the distance between the electrodes is adjusted to define the location and extent of the coating damage.36 This technique allows for direct assessment of the condition of the coating regardless of cathodic protection condition. During the survey, all impressed current sources which influence the pipe section must be temporarily interrupted, if the AC survery frequency is 60 Hz or a harmonic of 60 Hz. Usually the AC receiver will have a filter to eliminate these. This survey requires only one surveyor, but the surveyor needs to walk the full length of the pipeline. Soil resistivity, pipe depth, and electrical interference affect the measurement. The sensitivity of this method in high-resistivity soils is low. This technique may not be accurate when several coating defects exist. The success of using this method depends on the surveyor’s knowledge and experience.

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CHAPTER 11 Monitoring – External Corrosion

FIGURE 11.9 Typical Survey Result from the ACVG Method.35 Reproduced with permission from NACE International.

Standards providing guidelines for conducting an ACVG survey include: •

NACE Standard Test Method TM0109, ‘Above-ground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition’.

11.3.6 Pearson survey (PS)37,38 Pearson survey is similar to an ACVG, except that in this survey an audio signal is used to locate coating defects. Similar to ACVG survey, the center line of the pipeline must be accurately located for carrying out this survey. In this survey, an AC signal is applied to the pipeline – normally at a frequency of 1,000 Hz for thick coatings, e.g., asphalt, coal tar, extruded polyethylene, and tape, and 175 Hz for thin coatings, e.g., FBE or liquid epoxy. The audio signal from the pipeline is monitored using a receiver that is tuned to the frequency of the transmitter. The receiver is connected between two probes. This survey requires two surveyors each carrying a probe. The distance between the surveyors is fixed. The probes connect to the ground through contact electrodes which are either hand-held (e.g., modified aluminum ski poles) or attached to the feet of the surveyors (e.g., studded boots). The surveyors may walk along the pipeline either in one-behind-the-other formation (preferred) or in walk-parallel-toone-another formation. In the latter formation, one surveyor walks on top of the pipeline and the other on the side. In one-behind-the-other formation: • • •

When the front surveyor is directly over a coating defect, the voltage gradient between the front and rear probes is greatest and the audio signal is strongest. When the defect is centered between the two surveyors, both surveyors are at equi-potential from the potential gradient, and hence the audio signal is a null. When the second surveyor is directly over the coating defect the audio signal peaks again.

In the walk-parallel-to-one-another formation, only one peak signal is observed. Once coating defects is suspected, the formation, position, and distance between the surveyors are adjusted to accurately establish the location and extent of the coating damage.

11.3 Above-ground monitoring techniques

731

The advantages and disadvantages of Pearson survey are similar to those of ACVG, but the Pearson survey is generally considered to be the more accurate. Standards providing guidelines for conducting a Pearson survey include: •

NACE Standard Test Method TM0109, ‘Above-ground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition’.

11.3.7 Electromagnetic current attenuation (ECAT)39–41 The electromagnetic current attenuation technique (ECAT) or more simply, current attenuation technique (CAT), is different from the current attenuation technique discussed in section 11.3.4. The technique described in section 11.3.4 measures the current attenuation directly, whereas ECAT measures the electromagnetic field. When an AC current is applied to a coated and buried metallic structure, it creates an electromagnetic field. The electromagnetic field attenuates (i.e., grows weaker) as a function of its distance from the source. For a given signal frequency, soil resistivity, and structure characteristics (e.g., pipe diameter, wall thickness, and depth), the electromagnetic field is a function of coating quality. For a good coating, the current attenuates logarithmically with distance from the source. However, in the presence of poor coating, i.e., coating with holidays and other imperfections, the current attenuates rapidly. In this technique, a transmitter applies an AC signal to the structure. The receiver measures the strength of the electromagnetic field around the structure on both sides of the transmitter. The transmitter is in physical contact with the structure, but the receiver is not. The receiver is normally placed at an interval of 15 to 60 meters (50 to 200 feet) along the structure. Depending on the attenuation, several transmitters may be used. All impressed current sources should be interrupted during the survey. The rate of attenuation is measured as the ratio of electromagnetic signal amplitudes at two points divided by the distance between them. The results are presented as an average attenuation per unit length, e.g., millibels per meter (mB/m), millibels per foot (mB/ft), decibels per meter (dB/m), or decibels per foot (dB/ft). The current attenuation is obtained from the rate of electromagnetic signal attenuation (Figures 11.1035,42 and 11.11),43 and this is used to calculate the coating conductance.

FIGURE 11.10 Typical Current Data at Each Survey Point During a Current Attenuation Survey.35,42 Reproduced with permission from NACE International.

732

CHAPTER 11 Monitoring – External Corrosion

FIGURE 11.11 Typical Current Attenuation Plot.35,43 (Sections with attenuation 2, 5, and 7 are locations with poor coatings). Reproduced with permission from NACE International.

The coating conductance is further normalized with respect to pipe diameter, wall thickness, and soil resistivity to identify the locations of poor coatings (Figure 11.12).35,44 The accuracy of this technique depends on the soil resistivity, the pipe depth, the frequency, and the strength of the transmitter. The correlation between defect size and attenuation rate depends on the instrument; hence the relationship established for one instrument may not be applicable for another operating at a different frequency. The current attenuation survey can be carried out on a pipeline buried to a depth of 15 m (49 ft.). This survey can be carried out by single surveyor and can be performed through magnetically transparent materials such as dry earth, concrete, ice, snow, water, and tarmac. The presence of pipeline fittings, electrical connections, pipe branches, anodes, cables, and nearby facilities distort the electromagnetic signal. The equipment required for this survey is relatively expensive. Standards providing guidelines for conducting a current attenuation survey include: •

NACE Standard Test Method TM0109, ‘Above-ground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition’.

11.3.8 Transwave system technique (TS)45–47 The TS technique analyzes the waveform generated by CP rectifiers. Waveform readers installed at the ends of the infrastructure (e.g., pipeline) measure the waveform. The waveform attenuates along the pipeline as a function of distance. The rate of attenuation depends on the characteristics of the pipe, soil, waveform frequency (normally the frequency of CP rectifiers is 120 Hz), and the quality of the coating. The quality of the coating is assessed from the signal attenuations, but the analysis of the waveform is rather complex. Simpler wave form analyzers are also available.

11.3 Above-ground monitoring techniques

733

FIGURE 11.12 Coating Conductance Calculated from Current Attenuation Data Presented in Figure 11.11.35,44 (Sections with coating conductance 1,293, 8,079, and 15,830) are locations with poor coatings). Reproduced with permission from NACE International.

Access to the pipeline is not required because the waveform readers are only needed at the ends of the structure. The survey also provides information on cathodic protection. However, the survey requires sophisticated equipment, complex analysis of the waveform, and specially trained personnel to operate and interpret the data. Further, the changes in pipe depth and soil resistivity should be accounted for before any information can be obtained from this survey. No standard is currently available to provide guidelines to use this technique.

11.3.9 Electrochemical impedence spectroscopy (EIS)48–50 EIS is primarily a laboratory technique, but it has been tested in the field. Its principles are discussed in section 8.3.5. A coated pipeline can be electrically modeled as a network of resistors and capacitors. The values of these resistors and capacitors can be determined from the frequency response of the pipeline to an AC input. Coating resistance, as well as other electrical characteristics can therefore be derived from the model or be determined directly from the measurements. This technique requires specially qualified personnel, requires special instrumentation, involves extensive data, is complex, and is labor intensive. This technique is not used in the oil and gas industry for monitoring external coating. Magnetically Assisted Electrochemical Impedance Spectroscopy (MEIS) is a variation on the standard EIS method and it uses magnetometers. However, this technique has not yet been proven in the field with respect to its ability to monitor coating performance. No standard is currently available to provide guidelines for using this technique in the field.

734

CHAPTER 11 Monitoring – External Corrosion

11.3.10 Infrared camera An infrared camera forms an image using infrared radiation (wavelength 14,000 nanometer or 14 micrometer). In comparison to infrared camera, a normal camera uses visible light (wavelength 450 to 750 nanometer). Infrared cameras are widely used in several other fields to scan thermal images, and are being tested in the oil and gas industry.

11.3.11 Cautions in using above-ground monitoring techniques The different modes of coating failures are presented in section 10.2.1. Table 11.6 presents the ability of above-ground monitoring techniques to determine these different modes of coating failure.52 As the table indicates, above-ground monitoring techniques do not determine all modes of coating failures. More importantly, none of these techniques is capable of determining the worst case of coating failure, which is disbondment with shielding of CP. In addition, certain conditions may cause errors in these techniques. These errors should be recognized and overcome before using the data. Normally, two complimentary techniques, e.g., CIS and DCVG, are used to verify the data. Some are discussed in the following paragraphs. Most above-ground coating measurements are based on Ohm’s law, i.e., the measurements depend on the relationship: E ¼ IR

(Eqn. 11.13)

where E is the potential, I is the current, and R is the resistance. The various techniques differ only in terms of how the current is applied (DC or AC), how the potential is measured (between the structure and reference electrode or between two reference electrodes), and how the errors are accounted for. Almost all above-ground techniques measure resistance in one form or another. This resistance is a combination of the coating resistance, soil resistance, and voltage drop, and is a function of temperature. For precise evaluation of corrosion conditions, the soil resistance should be subtracted from the total resistance. Methodologies to determine soil resistance are available (see section 11.7.1).53 To determine the voltage drop, the potential of the structure of interest is measured with the CP current on (ON potential) and off (instant-OFF potential). The difference between ON and OFF potentials is approximately the voltage drop.54 Table 11.7 presents other interfering factors in each technique.52 Most above-ground monitoring techniques are electrical in nature. Calcareous deposits resulting from the application of cathodic protection or large accumulations of corrosion products may increase the electrical resistance, causing errors in the reading by varying the resistivity of the structure. Stray currents from neighboring structures make obtaining useful monitoring data difficult (see section 9.3.7). Telluric currents (see section 5.22) can generate extraneous potentials and currents along pipelines. They are usually of short duration, hence recording data after a few minutes, hours, or days may overcome this issue. Casings at road and railroad crossings may pose another problem for monitoring the effectiveness of cathodic protection. A casing in electrical contact with the carrier pipe acts as an electrical shield, and prevents CP current from reaching the carrier pipe. If the carrier pipe is to be fully protected inside the casing, the casing and pipe must be separated electrically. Isolation spacers are used to prevent contact between the pipe and casing.

Table 11.6 Coating Defects Detectable by the Above-Ground Techniques52 Coating Defect

Ability of Above-Ground Techniques to Detect Coating Defects

Ranking

CPCR

DCVG

CC

CIS

ACVG

CA

TS

EIS

Infrared

Disbondment and Prevention of Passage of CP Holidays Disbondment with passage of CP Blistering Loss of Adhesion Loss of Cohesion Water Permeation Air Permeation

1

No

No

No

No

No

No

No

No

Unknown

2 3

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

Yes Unknown

4 5 6 7 8

Unknown No No Yes No

Unknown No No Unknown No

No No No Unknown No

No No No Unknown No

No No No Unknown No

No No No Unknown No

No No No Unknown No

No No No Yes No

Yes Unknown Unknown Unknown No

11.3 Above-ground monitoring techniques

Type

735

736

CHAPTER 11 Monitoring – External Corrosion

Table 11.7 Factors Interfering During the Measurement of Coating Performance52 Interfering Factors Measuring Technique

Signal

VoltageDrop

Soil Resistance

Temperature

Others

CIS DCVG CPCR CC ACVG

DC DC DC DC AC

Yes e Yes Yes e

Yes Yes Yes Yes Yes

Yes Yes Yes Yes Yes

CA TS EIS

AC AC AC

e e e

Yes Yes Yes

Yes Yes Yes

On & off potentials Voltage gradient On & off potentials On & off potentials Probe design and voltage gradient AC signal strength CP rectifier EIS models

11.4 Remote monitoring55 The above-ground techniques may also be used to remotely monitor offshore oil and gas infrastructure. The principle of monitoring onshore and offshore infrastructures is the same, but the methods by which the instruments are deployed are different. The instruments may be attached to remotely operated vehicles (ROV) or may be carried out by divers.

11.5 In-line inspection56 Sections 7.2 and 8.4 discuss general aspects of pigging and ILI as used to monitor internal corrosion respectively. ILI involves the insertion and transportation of a device inside the pipeline to inspect the condition of the pipe wall. It is a sophisticated and critical operation. An ILI tool measures defects in the pipe wall itself; therefore it is a direct indication of the condition of the pipe wall. The type of defects detected depends on the type of ILI tool used. Several key activities, factors, and precautions should be considered before conducting an ILI inspection; some common aspects are discussed in this section and aspects specific to individual techniques are discussed in the individual tool sections. Piggability: The pipeline section should be piggable, i.e., it should have facility to insert, transport (no restriction such as change in pipe diameter and intrusion), and receive the ILI tool. Section 7.2 discusses various requirements of a pigging operation. Often a dummy ILI and geometry (caliper) detection tools are first sent to ensure that the line is piggable. Detection: ILI tools can detect several features including corrosion pits, cracks, mechanical damages, disbonded coating, DC current flow and magnitude, and mechanical features. Therefore it is important to establish the features to be inspected and ability of the tool to inspect such a feature. Measurement: Once an appropriate tool is selected, it is important to establish its measurement accuracy with respect to feature length, width, depth, and orientation. In many situations, additional engineering judgment may be required to measure the features.

11.5 In-line inspection

737

Interference: The ability of the tool to detect a particular feature, e.g., cracks in the presence of other features. The extent of interference during the detection and measurement of the feature of interest should be established. Location: ILI discretely measures each and every feature, so it is important to establish their location. For this purpose, the three commonly-used methods are: odometer reading, inertial navigation, and benchmarking. • •

•

Several odometers (for redundancy) are attached in the wheel of the ILI tools. They record and indicate location along with ILI data. Inertial navigation tools measure angular change and velocity change in the X, Y, and Z directions as the ILI tool travels through the pipeline. Inertial navigation is more accurate for establishing location. Markers are placed along the pipeline. These makers may be permanent (e.g., magnets) or portable (above-ground markers (AGM)). These markers track the ILI tools as they pass through them. The readings are mainly used to correct any distance inconsistency in the odometer reading due to slippage or topography change.

Cost/benefit: ILI tool indicates the corrosion condition of the pipeline at the time when the inspection is performed. However, the costs of conducting the run and of analyzing the data are prohibitive. Therefore a cost/benefit analysis should be performed to determine whether, and how frequently, an ILI inspection should be carried out. Information presented in section 10.2 may be used as a guideline to set the initial frequency of running ILI tools. Types of fluids: Type of fluids is important with respect to three aspects of ILI: speed control, corrosivity, and compatibility. Each ILI tool requires an optimal speed for maximum performance. The ILI tools are normally transported by the flow of the product (e.g., oil or gas) being transported in the pipeline. Sometimes the ILI speed is controlled by increasing the throughput (to increase the speed of the ILI tool) or by using a by-pass valve (to decrease the speed of the ILI tool). The components of the ILI tools should be resistant to the fluids being transported. Some ILI tools (e.g., ultrasonic) require liquids to transmit the signal from the tool to the pipe wall; such tools cannot be used in gas pipelines unless liquids are intentionally added during the inspection. Tool tracking: It is important that the ILI tools travel from the launcher to the receiver without any trouble. The ILI tool is tracked using remote acoustic or other electronic devices, or physically by traveling on the right of way along with the tool. Data maintenance: ILI run produces large amounts of data which should be properly handled, i.e., the reliability of the data is established, only reliable data are analyzed to establish the corrosion condition of the pipeline, and the analyzed data are properly stored for future reference. Section 13.4 discusses aspects of data maintenance. Side effects: ILI run should be carried out without causing any undesired side effects. Two common ones are accumulation of metallic debris from the tool, and magnetization of the pipe. The magnetization effect happens only with a magnetic flux leakage (MFL) tool. Magnetization may cause problems during subsequent runs and during welding. ILI tools may broadly be classified into metal loss and crack detection tools. Table 11.8 presents general characteristics of both types, and the following paragraphs discuss them further.57

738

Table 11.8 General Characteristics of ILI Tools57 Crack Detection Tools

Magnetic Flux Leakage

Anomaly

Defect

Metal loss

External corrosion Internal corrosion) Gouging

Cracks

Standard Resolution (SR)

High Resolution (HR)

Ultrasonic Compression Wave(M)

Ultrasonic Shear Wave(M)

Transverse MFL

Geometry Tools

• Detection(A) • Sizing(B) • No external

• Detection(A) • Sizing(B)

• Detection(A) • Sizing(B)

• Detection(A) • Sizing(B)

• Detection(A) • Sizing(B)

• No

• Detection(A)

• Detection(A) • Sizing(B)

• Detection(A) • Sizing(B)

• Detection(A) • Sizing(B)

• No

• No

• Detection(A) • Sizing(B)

• Limited

• No

detection

and internal corrosion defect discrimination

Narrow axial external corrosion

• Detection(A)

Stress corrosion cracking

• No detection

• No detection

detection

detection(A,

detection

detection

C) (B)

Fatigue cracking

• No detection

Long seam cracks (toe cracks, hook cracks, incomplete fusion, and preferential seam corrosion

• No

Circumferential cracks

• No

Hydrogen i nduced cracking)

• No

detection

detection detection

• No detection

• No detection

• Detection(C) • Sizing(B) • No detection

• No detection

• No detection

• No detection

• No detection(A)

• Detection(A) • Sizing(B)

• Detection • Sizing(B)

(A)

• Detection(A) • Sizing(B) • Limited detection

• Sizing • Limited

detection(A,

• No detection

C)

• Sizing(B) • Detection(A) • Sizing(B)

• No

• No

• No

detection

• No detection

detection

detection

• No detection

CHAPTER 11 Monitoring – External Corrosion

Metal Loss Tools

Deformation

Miscellaneous

• Detection(E,G)

• Detection(E,L)

• Detection(E,G)

• Detection(E,G)

• Detection(E,G)

Flat dents

• Detection(E,G)

• Detection(E,L)

• Detection(E,G)

• Detection(E,G)

• Detection(E,G)

Buckles

• Detection(E,G)

• Detection(E,L)

• Detection(E,G)

• Detection(E,G)

• Detection(E,G)

Wrinkles, Ripples

• Detection(E,G)

• Detection(E,L)

• Detection(E,G)

• Detection(E,G)

• Detection(E,G)

Ovalities

• No

• No

• No

• No

• No

Detection(F) Sizing

detection

detection

detection

detection

detection

In-line valves and fittings

• Detection

• Detection

• Detection

• Detection

• Detection

• • • • • • • • • • •

Casings (Concentric)

• Detection

• Detection

• No

• No

• Detection

• No

Casing (Eccentric)

• Detection

• Detection

• No

• Detection

• No

Bends

• Limited

• Limited

• Limited

• Limited

detection

detection

detection

detection

detection

Branch appurtenances/ hot taps

• Detection

• Detection

• Detection

• Detection

• Detection

• Detection(H) • Sizing(H) • No

Close metal objects

• Detection

Thermite welds

• No

Pipeline coordinates

• No

Type A repair sleeve

• Detection

Composite sleeve

• Detection(I)

• Detection(I)

• No detection

detection

Type B repair sleeve

• Detection

• Detection

• Detection

Patches/half soles

• Detection

• Detection

Puddle welds

• Limited

• Limited

detection detection

detection

• Limited

Detection(F) Sizing Detection(F) Sizing Detection Sizing(B) Detection

detection

detection

• No

Detection(F) Sizing

detection

detection

• Detection

• No detection

detection

• No detection

• No detection

• No

• Detection

• No

• No

• No

detection

• No detection

detection detection

detection

• Detection(K)

• Detection(K)

• Detection(K)

• Detection(K)

• Detection(K)

• Detection

• No

• No

• Detection

• No

• Detection(I)

• No

• Detection

• Detection

• No

• Detection

• Detection

• Detection

• No

• No

• No

• Limited

• No

detection detection

detection

• No

detection detection detection detection

detection

detection

detection

detection

detection

(Continued)

739

detection

11.5 In-line inspection

Previous repairs

Sharp dents

740

Table 11.8 General Characteristics of ILI Tools57 Continued Metal Loss Tools

Crack Detection Tools

Anomaly

Defect

Standard Resolution (SR)

Miscelleneous damage

Laminations

• Limited detection

Inclusions (lack of fusion)

• Limited

Cold work

• No

Hard spots

• No

Grind marks

• Limited

detection detection detection detection(A)

High Resolution (HR)

Ultrasonic Compression Wave(M)

• Limited

• • • • •

detection

• Limited detection

• No detection

• No

Transverse MFL

Geometry Tools

Detection Sizing(B)

• Limited

• Limited

• No

Detection Sizing(B)

• Limited

No detection

• No

• No

detection

• Limited

Ultrasonic Shear Wave(M)

detection

• Detection(A, B)

detection(A)

detection detection detection

• No detection

• Detection(A, B)

detection

• Limited detection

• No detection

• No detection

• Limited detection(A,

detection

• No detection

• No detection

• No detection

• No detection

B)

Strain

• No detection

)

Grid weld anomaly (e.g., void)

• Limited

Scabs/slivers/ blisters

• Limited

• No

• No

detection

detection

• Detection

• Detection

detection

• Detection(D)

detection(A)

• No

• Limited

• Detection(A,

detection

B)

• Detection(A, B)

• Detection(J)

detection

• No detection

detection

On the internal surface of the pipeline; all other anomalies are on the external surface Limited by depth, length, and width of the indication (B) Defined by the sizing accuracy of the tool (C) Probability of detection decreases for tight cracks (D) Transducers should be rotated to 90 (E) Probability of detection depends on size and shape of the indication (F) Also circumferential position, if the tool is equipped (G) Sizing is not reliable (H) If the tool is equipped for bent measurement (I) Composite sleeves without markers cannot be detected (J) If the tool is equipped; depends on several parameters (K) If the tool is equipped with mapping capability (L) Sizing depends on tool (M) Used only in liquid environment, i.e., liquid pipelines or gas pipelines with liquid couplant (A)

• No

• Limited detection(A)

• No detection

• Limited detection

CHAPTER 11 Monitoring – External Corrosion

Magnetic Flux Leakage

11.5 In-line inspection

741

11.5.1 Metal loss tools As the name implies, these tools detect loss of wall thickness. This loss may be due to corrosion, manufacturing defect, or mechanical damage. The most commonly used techniques are MFL and ultrasonic (UT).

11.5.1a Magnetic flux leakage (MFL) During an MFL inspection, a magnetic flux is induced between two poles of a magnet and the pipe wall is saturated with this flux. The magnetic flux leakage is monitored by sensors. If the steel is homogeneous and free from any defect, the leakage of flux is uniform. Any loss of wall thickness (for example, due to corrosion) increases the magnetic flux leakage. The shape and magnitude of the magnetic flux is analyzed using sophisticated computer algorithms to determine the amount of pipe wall loss and to discriminate external corrosion features from internal corrosion features. Section 8.3.10 presents additional information on MFL tool.

11.5.1b Ultrasonic (UT) During an ultrasonic inspection, a transducer emits an ultrasonic signal perpendicular to the pipe surface. Both the internal and external surfaces of the pipe echo the signal. A monitor records the time taken for the echo to return from the pipe surfaces. The wall thickness is calculated by comparing the time taken for the echo to return and the speed of ultrasound in the pipe. A liquid medium is necessary to transmit the signal efficiently from the transducer to the pipe wall, hence the UT technique cannot be used to inspect gas pipelines. For this reason, the UT tool is placed in a pool of liquid (water or diesel) contained between two batch pigs. Table 11.9 provides some characteristics of ultrasonic tools with respect to inspect external corrosion.58 Sections 8.3.9 (non-intrusive monitoring) and 8.4.8 (ILI-UT internal) provide more information on ultrasonic techniques.

11.5.2 Crack detection tools Cracks, such as stress corrosion cracks, stress cracks, and welding defects, on the external surface of the pipeline can occur either in the longitudinal direction or in the circumferential direction. Section 10.3.2 discusses factors causing various types of cracks. In order to increase the probability of detection and to increase sensitivity it is important to send ILI signal in the right direction. For detecting longitudinal cracks occurring perpendicular to the hoop stress the signal is injected in the circumferential direction. Similarly for detecting circumferential cracks the signal is injected in the longitudinal direction. The following section describes commonly used crack detection tools.

11.5.2a Liquid-coupled tools These tools transmit ultrasonic pulses and monitor the shear waves generated in the pipe wall. The pulses are sent at an angle, so that they propagate in the pipeline at an angle of 45 . As with all ultrasonic tools, these tools require a liquid environment. They cover the entire surface and body of the pipeline and can discriminate defects present on the internal and external surfaces, as well as in the bulk of the pipeline steel. During the inspection, the actual thickness of the pipe wall is measured. Table 11.10 provides some characteristics of this technique.59 These tools are primarily used to inspect longitudinally oriented, external stress, corrosion cracks. They can also identify fatigue cracks, toe cracks, welds, dents, valves, T-pieces, notches, grooves, scratches, inclusions, and laminations.

742

CHAPTER 11 Monitoring – External Corrosion

Table 11.9 Characteristics of Ultrasonic In-Line Inspection Tools for Determining External Corrosion58,59 Characteristics

Values

Axial sampling distance, mm (in.) Circumferential sensor spacing, mm (in.) Maximum inspection speed requirement, m/s (mph) Depth sizing accuracy, with respect to depth, mm (in.) Longitudinal resolution, mm (in.) Circumferential resolution, mm (in.) Minimum depth of corrosion pit, mm (in) Location accuracy, axial (relative to closest girth weld), mm (in.) Location accuracy, circumferential,  Confidence level of detection, % Other features interfering during the ILI-MFL inspection of external corrosion

3 (0.12) 8 (0.3) 2 (4.5) 0.5 (0.02) 3 (0.12) 8 (0.3) 0.2 (0.008) 0.1 (4) 5 80 Internal corrosion pits, welds (girth, longitudinal, spiral, and cold), dents, deformations, bends (field, forged, and hot), sleeves, T-pieces, flanges, valves, laminations, internal hydrogen induced cracks, blisters, inclusions, longitudinal channeling, and wall thickness variation

11.5.2b Wheel-coupled tools These tools use a liquid-filled wheel as a transducer. They inject shear waves into the pipe wall at an angle of 65 . These tools can operate in both liquid and gas pipelines, but they cannot discriminate internal and external corrosion. Table 11.10 provides some characteristics of this technique.

11.5.2c Circumferential MFL tools These tools magnetize the pipe wall circumferentially to detect external cracking. They can operate in both liquid and gas pipelines, but they cannot discriminate between internal and external corrosion. Provides some characteristics of this technique.

11.5.2d Electromagnetic acoustic transducer tools Electromagnetic acoustic transducer (EMAT) tools use AC to generate ultrasound through forces that move charges in a magnetic field. The mode of ultrasound depends on the type and configuration of the transducer. These tools do not require a coupling medium and hence can readily be used in gas pipelines.

11.5.2e Eddy current tools Section 8.3.11 provides information on eddy currents. These tools are not useful for external corrosion or cracking measurements because eddy currents have a limited ability to penetrate the pipeline.

11.5.3 Other tools In addition to external mass loss and crack detection tools, several other tools are used in complimentary or supplementary roles. Section 8.4.9 describes these tools.

Table 11.10 Characteristics of External Crack Detection Tools 58,59 Characteristics

Interfering materials

)

Circumferential Magnetization Tool

3.0 (0.12)

5.0 (0.2)

3.3 (0.13)

10 (0.4)

210 to 285 (8.3 to 11)

4 (0.16)

1.0 (2.3)

0.2 to 4 (0.45 to 9)

1 (0.04)

0.5 to 3 (1.1 to 6.7)) 1 to 3 (2.2 to 6.7))) 25 % of wall thickness

25% of wall thickness

30 (1.2)

50 (2)

25 (1) 0.1 (0.004)

15

10

15  25 mm (1.0 in.)

10

10 (4)

50 (2) 100 (4)

100 (4)

200 (8)

5

5

7.5

80 56 to 142 (22 to 56)

80 61 and 76 to 91 (24, and 30 to 36)

80 15 to 142 (6 to 56)

Welds, dents, valves, T-pieces, notches, grooves, scratches, inclusions, and laminations

743

In liquid In gas

))

Wheel-coupled Ultrasonic Tool

11.5 In-line inspection

Axial sampling distance, mm (in.) Circumferential sensor spacing, mm (in.) Maximum inspection speed, m/s (mph) Minimum depth of defect detected, mm (in.) Minimum length of defect detected, mm (in.) Minimum width of defect detected, mm (in.) Defect alignment,   of pipe axis Accuracy of sizing, length, for defects greater than 100 mm (4 in.), %wt Accuracy of sizing, length, for defects lesser than 100 mm (4 in.), mm (in.) Accuracy of sizing, width of cracks, mm (in.) Location accuracy, axial with respect to girthweld, mm (in.) Location accuracy, circumferential   Confidence level, % Available sizes, cm (in.)

Liquid-coupled Ultrasonic Tool

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CHAPTER 11 Monitoring – External Corrosion

Standards providing guidelines for using ILI tools include: • •

NACE Standard Report 35100, ‘In-line Nondestructive Inspection of Pipelines’. NACE Standard Practice SP0102, ‘In-line Inspection of Pipelines’.

11.6 Hydrostatic testing A hydrostatic test is a pressure test in which the pipe or other component is pressurized to evaluate its integrity. This test is used to evaluate the structural integrity of pipeline or other pressure containing infrastructure. During the test, the pipe is filled with water and the water pressure is increased, held for a certain duration, and then released. The test is performed at pressures above the normal operating conditions of the pipeline. Normally the test is performed when the pipeline is put into service, but can also be conducted to evaluate the integrity of the infrastructure after a certain length of operation. It is important to remove all water used for hydrostatic test and dry the pipeline before operation, otherwise the locations where water accumulates become susceptible to internal corrosion. To avoid this issue, sometimes nitrogen is used for pressure testing.

11.7 Below-ground inspection Below-ground inspection is the most direct method of determining the status of the infrastructure. Underground structures are excavated to carry out maintenance work. Such activities provide opportunities to assess the status of corrosion and corrosion control measures. During an excavation two types of activities are performed: to visually inspect the status of the structure (direct inspection) and to collect samples for further analysis (measurement). The relevance of below-ground measurements depends on the season and location in which the samples are collected. For instance, the soil properties may vary seasonally, i.e., the properties may be different in summer, fall, winter, and spring. Therefore, ideally samples should be collected and analyzed four times a year, at three month intervals. Similarly, the samples may be collected from soil just below the surface, immediately surrounding the coating, and at the interface between disbonded coating and infrastructure. Whereas collecting samples from just below the surface is relatively easy, it is not representative of environment surrounding the infrastructure. On the other hand, collectings samples from the structure-coating interface requires removal of existing coating and reapplication of a new coating. This process changes environment before and after sample collection. Some activities which are commonly performed during below-ground inspection are discussed in the following paragraphs.

11.7.1 Soil resistivity The soil resistivity is predominantly measured using the Wenner four pin method. In this method, four equally spaced pins are inserted into the ground (Figure 11.13), or placed in a container filled with soil.60 An alternating current is applied between the two outer pins and the potential is measured between two inner pins. The resistance is calculated from the current and potential values, and is used to calculate the soil resistivity using Eqn. 11.14: rsoil ¼ 2pLRsoil

(Eqn. 11.14)

11.7 Below-ground inspection

a PIN C1

a PIN P1

745

a PIN P2

P1

P2

C1

C2

PIN C2

Soil Resistance Meter

FIGURE 11.13 Soil Resistivity Measurement.

60

Reproduced with permission from NACE International.

where rsoil is the soil resistivity (ohm-centimeters), L is the distance (length) between probes (centimeters), and Rsoil is the soil resistance (ohms) (instrument reading). For testing soil samples a soil box may be used. The standard providing the procedure for measuring soil resistivity using the Wenner four pin method is: •

ASTM G 57, ‘Standard Test Method for Field Measurement of Soil Resistivity Using the Wenner Four-Electrode Method’.

11.7.2 Visual inspection The main advantage of below-ground inspection is the ability to carry out a visual inspection. Visual inspection is carried out in at least two stages: before removal of protective coating and after removal of protective coating. In the first stage, the following observations are generally made: • • • •

Status of coating (good condition, discolored, disbonded, detached from surface, and any other noticeable changes) Type of defect (holiday, disbondment, bulging, or wrinkled) Pattern of defect (continuous, patch, random, isolated, and any other pattern) Adhesion of coating (excellent, good, fair, and bad)

Based on the condition of the coating and corrosion feature, a decision is made whether to further inspect by removing the coating or not. If the coating is in bad shape and corrosion features are visible

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CHAPTER 11 Monitoring – External Corrosion

or evident, then the coating is removed to visually inspect the surface beneath it. Common observations made and recorded include: • • • •

Presence of solids and other extraneous materials Presence of corrosion and its type (general corrosion, pitting corrosion, SCC, and other types of corrosion) Corrosion pattern (continuous, patch, random, and any other pattern) Corrosion characteristics (number of corrosion features per unit area as well as length, depth, and width of them)

If coating is removed the surface should be prepared and repair coating should be applied (see section 9.2.3) for details on repair coating).

11.7.3 Moisture content Determining moisture content of soil surrounding the infrastructure is important, because the presence of moisture is necessary for corrosion to take place. In addition, any cyclic variation in moisture content induces soil stress, which may accelerate the deterioration of a coating, and may accelerate the diffusion of oxygen into the soil. Soil around the coating should be collected to measure the moisture content. The following standards provide information on the effect of soil moisture on corrosion and on the procedure for measuring the moisture content of soil. • •

NACE Standard Practice SP 0502, ‘Pipeline External Corrosion Direct Assessment Methodology’. US Environmental Protection Agency (EPA)’s, AASHTO Method T265, ‘Standard Method of Test for Laboratory Determination of Moisture’.

11.7.4 pH pH is useful for determining the corrosivity of the environment, and to determine whether CP reaches the surface. The most relevant pH measurement is that of solution beneath the disbonded coating and of the solution immediately surrounding the oil and gas infrastructure. A pH value above 9 in the solution beneath the coating indicates that the CP current is reaching the surface. If the infrastructure is properly protected by CP, the pH in the solution surrounding its surface (typically within 1 cm) is higher than that of the solution some distance from it. Standards providing procedures for measuromg pH include: • •

ASTM G51, ‘Standard Test Method for Measuring pH of Soil for Use in Corrosion Testing’. ASTM D4972, ‘Standard Test Method for pH of Soils’.

11.7.5 Chemical analysis If a solution is present beneath the coating it will be useful to perform chemical analysis of it, to understand its corrosivity. In addition, it is beneficial to analyze a solution from some distance from the structure and compare the results. Some common analytes include sulfate, chloride, bicarbonate, and carbonate. Standards providing guidelines for performing chemical analysis include: • •

ASTM D516, ‘Standard Test Method for Sulfate Ion in Water’. EPA 376.1, ‘Standard Test Method for Soil Sulfide’.

11.7 Below-ground inspection

747

Table 11.11 General Relationship between Redox Potential and Microbial Activity61

• • • • •

Redox Potential, mV

Microbial Activity

Below 100 100 to 200 200 to 400 Above 400

Severe Moderate Slight None

ASTM D512, ‘Standard Test Methods for Chloride Ion in Water’. ASTM D513, ‘Standard Test Methods for Total and Dissolved Carbon Dioxide in Water (including measurement of carbonic acid, carbonate, and bicarbonate in water)’. ASTM D1126, ‘Standard Test Method for Hardness of Water’. ASTM D5907, ‘Standard Test Methods for Filterable Matter (Total Dissolved Solids) and Nonfilterable Matter (Total Suspended Solids) in Water’. ASTM D5542, ‘Solid Test Methods for Trace Anions in High Purity Water by Ion Chromatography’.

In addition, if any corrosion products are present on the surface, they should be collected and analyzed. Typical examples include iron carbonate, iron sulfide, and iron oxide.

11.7.6 Microbial analysis Section 4.9 discusses the influence of microbes on corrosion. Two types of analysis are carried out to determine the susceptibility of the infrastructure to microbiologically influenced corrosion (MIC): redox measurement and microbial analysis. The oxygen reduction potential (commonly referred to as redox potential) of platinum (Pt) is primarily used to detect conditions conducive to anaerobic bacterial activity. For this reason, the potential of Pt is measured against a standard reference electrode. The potential measured is used as a guide for determining microbial activity (Table 11.11)61 (see also section 8.3.17). However, such measurements are not rapid, so this procedure is commonly used only in areas where conditions are suspected to be favorable to microbial activity. Samples (water and/or soil) are also collected to test for the presence of microbes. Ideally a portion of sample collected for chemical analysis (see section 11.7.5) is used for microbial analysis. Typical microbes analyzed include SRB, APB, iron-oxidizing bacteria (IOB), and iron-reducing bacteria (IRB). Standards providing guidelines for performing microbial analysis include: •

NACE Standard TM0106, ‘Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion (MIC) on External Surfaces of Buried Pipelines’.

11.7.7 Corrosion characterization After the corrosion products and coatings are removed from the surface, its corrosion characterization is investigated. The number, types of corrosion (pitting corrosion and stress corrosion cracking), geometry (depth, width, and length), and pattern (cluster, isolated, and random) of the corrosion features are measured and recorded.

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References 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

20.

21.

22. 23. 24. 25.

Stearns DE, Belson MW, Lee RH. technical factors in testing pipe line coatings. Corrosion 1949;5(10):342. Olyphant M. Corona breakdown jeeping as a factor in pipeline coatings. Materials Performance 1965;4(9):8. NACE Standard Recommended Practice RP0274, High-voltage electrical inspection of pipeline coatings. Papavinasam S, Doiron A. External corrosion control of Northern pipelines: influence of construction conditions on the performance of coatings. Corrosion 2009, Paper # 4563. Houston, TX: NACE; 2009. NACE Standard Practice SP0502, Pipeline external corrosion direct assessment methodology, Table 2, ECDA Tool Selection Matrix, NACE International, Houston, TX, USA. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques, Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 200175,. ISBN: 1-57590-092-0. Peabody AW. Pipeline corrosion survey techniques. Materials Performance 1962;1(4):62. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques’, Peabody’s Control of Pipeline Corrosion. Figure 5.5, page 74, ISBN: 1-57590-092-0. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques’, Peabody’s Control of Pipeline Corrosion. Figure 5.4, page 73, ISBN: 1-57590-092-0. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Harvey DW. Maintaining integrity of buried pipelines. Materials Performance 1994;33(8):22. Argent CJ, Greenwood R, Bates RM. Pipelines coating defect location by above ground surveys. Industrial Corrosion May/June 1988:9–13. Borek H, Leeds JM. Practical comparison of above-ground techniques for coating defect delineation. Industrial Corrosion March/April 1988:14. Werner DP, Lukezich SJ, Hancock JR, Yen BC. Survey results on pipeline coatings selection and use. Materials Performance 1992;32(11):16. Mulvany. J. New pipeline defect surveying equipment for corrosion protection assessment. Materials Performance 1989;28(4):17. Slatter JD, Davidson MC, Grapiglia JP, Wong WT. DC voltage gradient technique to assess coating defects on buried pipelines. Materials Performance 1993;32(2):35. Solomon. I. Cost effective pipeline maintenance using modem coating surveys, 416; April 1989. Corrosion/ 89, Paper No. Shepherd W. Pipeline Coating Defect Surveying Using a Pulsed DC Technique. Anticorrosion 1991;(6):8. R.G. Wakelin, In situ evaluation of directional drill/bore coating quality directional drill/bore coating quality, PRCI Contract PR-262–9738 Report, October 998. Parker ME, Peattie EG. Pipe line corrosion and cathodic protection: a practical manual for corrosion engineers, technicians, and field personnel, Figure 4.2. Gulf Professional Publication; 1999. ISBN: 978-087201-149-640. Parker ME, Peattie EG. Pipe line corrosion and cathodic protection: a practical manual for corrosion engineers, technicians, and field personnel, Figure 4.3. Gulf Professional Publication; 1999. ISBN: 978-087201-149-641. Parker ME, Peattie EG. Pipe line corrosion and cathodic protection: a practical manual for corrosion engineers, technicians, and field personnel, Figure 4.4. Gulf Professional Publication; 1999. ISBN: 978-087201-149-642. Derived from J.L.Banach, Pipeline coatings – evaluation, repair, and impact on corrosion protection design and cost, CORROSION. Houston, Texas: NACE; 1987. Paper #29. Banch LJL. Part 1: Evaluating design and cost of pipe line coatings. Pipe Line Industry March 1988:62. Jack TR, Boven GV, Wilmott M, Sutherby RL, Worthingham RG. Cathodic protection potential penetration under disbonded pipeline. Coating Materials Performance 1994;33(8):17. Fotheringham I, Grace P. Directional drilling – what have they done to my coating? Journal of the Australasian Corrosion Association June 1997;22(3).

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26. Ballou JK, Howell RP, Liljeberg JW, Offermann PF. A proposed alternative method for measuring the electrical resistance of pipe line coatings. Corrosion December 1951:438. 27. Seager WH. The evaluation of pipeline coatings in terms of in situ electrical characteristics. Materials Performance 1980;19(6):9. 28. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques’, Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Figure 5.16, page 94, ISBN: 157590-092-0. 29. NACE Standard Test Method TM0102, measurement of protective coating electrical conductance on underground pipelines, NACE, Houston, TX. 30. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques, Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Table 5.2, p. 79, ISBN: 1-57590-092-0. 31. Gummow RW, Segall SM, Wakelin RG. Coating quality testing of directionally drilled pipe sections CORROSION 2000. Houston, TX: NACE; 2002. Paper #764. 32. Pope R. Attenuation of forced drainage effects on long uniform structures. Materials Performance 1981; 20(12):29. 33. Seager WH. The evaluation of pipeline coatings in terms of in-situ electrical characteristics. Materials Performance 1980;19(6):13. 34. Pearson ET. Test methods to determine the resistance of an insulating joint. Corrosion 1955;11(12):47. 35. NACE Standard Practice TM0109, Above-ground survey techniques for the evaluation of underground pipeline coating condition, NACE, Houston, TX. 36. Slatter JD, Davidson MC, Grapiglia JP, Wong WT. DC voltage gradient technique to assess coating defects on buried pipelines. Materials Performance 1993;32(2):35. 37. Flagler HM, Webb JB. The Pearson holiday detector, coating inspection on buried pipelines. Materials Protection 1967;6(7):33. 38. Matsushima I, Nunomura K. Use of simulated holidays for the evaluation of the method for leakage conductance measurement on underground and submerged pipelines. Materials Performance 1979;18(2):60. 39. Gray LGS, Danysh MJ, Bach K. Evaluation of organic coatings for corrosion protection by electrochemical impedance spectroscopy (EIS). NACE Northern Area Western Conference Proceedings February 1995. 40. Kendig MW, Jeanjaquet S, Lumsden J. Electrochemical Impedance of Coated Metal Undergoing Loss of Adhesion, Electrochemical Impedance: Analysis and Interpretation, ASTM STP 1188. In: Scully JR, Silverman DC, Kendig MW, editors. ASTM; 1993. p. 407–27. 41. Nekoksa G. discussions on the evaluation of pipeline coatings in terms of in situ electrical characteristics. Materials Performance 1981;20(2):57. 42. NACE SP 0502, Pipeline external corrosion direct assessment methodology. 43. NACE SP 0507, External corrosion direct assessment (ECDA) integrity data exchange (IDX) format, NACE, Houston, TX. 44. NACE SP 0207, Performing close interval surveys and dc surface potential gradient surveys on buried or submerged metallic pipelines, NACE, Houston, TX. 45. TransWave International Inc. TransWave’s Expert Risk Management System (TERMSÔ ). Information Package April, 1997. 46. Nagar RP, “Remoteness of Impressed Current Anode Ground Beds”, CORROSION 2010, Paper #10025, NACE International, Houston, TX (2010). 47. Snider DE, James SX. Real-time cathodic protection analysisIn Corrosion 90. Houston, TX: NACE; 1990. Paper # 413. 48. Hack JP, Scully JR. Defect area determination of organic coated steels in seawater using the break point frequency method. J Electrochem Soc 1991;138(1):33.

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49. Wilmot M, Van Boven G, Jack TR, Worthingham RG. evaluation of pipe line coatings using electrochemical impedance spectroscopy (EIS). Comparison between EIS response and cathodic disbondment testing. NACE CWRC Procedings; February 1995. 236. 50. Murray JN, Hack HP. Testing organic architectural coatings in astm synthetic seawater immersion conditions using EIS. Corrosion 1992;48(8):671–85. 51. Murariu AC, Birdeanu AV, Cojocaru R, Safta VI, Dehelean D, Botila L, Ciuca C. Chapter 2: Application of thermography in materials science and engineering’, in Infrared Thermography. ISBN 978-953-51-0242-7. In: Prakash RV, editor. Intech Europe. Rijeka, Croatia: University Campus STEP Ri; 2012. Slavka Krautzeka 83/A, 51000. 52. Papavinasam S, Attard M, Revie RW. Above-ground techniques for monitoring external pipeline coatings. Materials Performance 2010;49(4):44. 53. Snider DE, James SX. Real-time cathodic protection analysis. NACE Corrosion/90; April 1990. Paper No. 413. 54. ASTM G 57 (latest revision), standard test method for field measurement of soil resistivity using the Wenner four-electrode method, (West Conshohocken, PA: ASTM). 55. “Remotely Operated Vehicle Committee of the Marine Technology Society”. http://www.rov.org [accessed on 03.03.13]. 56. D.G. Stirling, Evaluation of coating condition using the elastic wave pig, BG plc Research & Technology. GRI Contract Number: 5095-270-3329. Report Period June 1995–April 1996. 57. NACE SP0102, In-line inspection of pipelines, NACE, Houston, TX. 58. NACE Publication 35100, In-line non-destructive inspection of pipelines, NACE, Houston, TX. 59. Uzelac NI. In-line inspection of gas transmission pipelines. Hart’s Pipeline Digest Focus Series 1998; 35(2):35. 60. Bianchetti RL. Chapter 5: Survey methods and evaluation techniques’, Peabody’s Control of Pipeline Corrosion. In: Bianchetti RL, editor. Houston, TX: NACE; 2001. Figure 5.14, page 86, ISBN: 1-57590-092-0. 61. Jack T, Willmott MJ, Sutherby RL, Worthingham RG. external corrosion of line pipe – a summary of research activities. Materials Performance 1996;35(3):18.

CHAPTER

Measurements

12

12.1 Introduction Chapter 4 discusses parameters which directly or indirectly influence corrosion. These parameters should be accounted for in evaluating the corrosion conditions, and corrective actions that should be taken to mitigate their influence. The measurements are normally collected for reasons other than corrosion control and corrosion professionals should obtain and use these data for effective corrosion control practice. This chapter discusses general types of measurements, parameters measured, importance of quality control during the measurement, and precautions when using these parameters in developing corrosion control strategies.

12.2 Types of measurement Several methods are available to measure different properties and they can be broadly classified into offline and online measurement.

12.2.1 Offline measurement Many physical and chemical properties change when the environmental conditions change. Therefore the most reliable method is to measure the properties under the operating conditions without contaminating the operating environment during and as a consequence of the measurement. However, measurement techniques have not advanced for making such measurements of many properties. Samples are often collected from the operating environment and taken to the laboratory for testing, i.e., the measurements are made offline. The reliability of offline measurement depends on several factors including sampling point, sampling procedure, changes to the property due to environmental change (e.g., flow, pressure, temperature, volume, flow, and chemical (aerial oxidation), conditions during transportation, competency of the laboratory, laboratory methodology, lag time between withdrawal of sample and laboratory analysis, and communication and coordination between laboratory and field operators).

12.2.1a Sampling point Ideally samples should be collected from multiple locations to obtain the trend within the system. But in most situations, only one sampling point will be available. The usefulness of the data depends on the location from which the sample is collected. The sampling point should represent the real Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00012-1 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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CHAPTER 12 Measurements

operating condition; preferentially the worst-case condition. For example, a sample collected from a stagnant zone in a flowing system may not represent the actual conditions of the system. Similarly, a sample collected for water analysis is not useful if the sample is not collected from the water phase. In some situations the appropriate sampling point may be inaccessible, operational requirements may not allow collection from an appropriate location, or frequent collection of samples at an appropriate location may not be economic. In any event, the point from which the sample is collected should be known and the relevance of that point to corrosion should be understood before using the data.

12.2.1b Sample collection The most critical aspect of offline measurement is the sample collection. It is impractical and impossible to collect the whole material for measurement, so a small, representative sample should be selected. Single sample or multiple samples over a fixed period may be collected. Collecting multiple samples, over a fixed period may provide better representation of the system. Further, sample collection becomes a challenge when the bulk material is inhomogeneous and large, as is the case in most situations in the oil and gas industry. For this reason, sample collection may often be the main source of error in offline measurements. Irrespective of these limitations, maximum care must be taken to ensure that the sample represents the properties of the bulk. Depending on the accuracy of the data required the sampling procedure: 1) Shall protect the sample from contacting external atmosphere. This procedure is the most task intensive and hence the most expensive. 2) May allow minimal exposure of sample to external atmosphere. 3) May make no effort to prevent exposure of sample to external atmosphere. This procedure is straightforward, easiest, and the cheapest. Figure 12.1 provides a schematic diagram of typical materials required for collecting samples.1 Often the samples should be collected under de-aerated conditions. For this reason, the container for collecting and shipping the samples is fitted with inlet and outlet ports, and is de-aerated before collection takes place. The sample container is then attached to the operating infrastructure using its access port. Accessories to collect and transport samples under operating pressure and temperature are available and are used in the oil and gas industry. Standards providing guidelines for sampling include: • •

American Petroleum Institute (API) Publication 852-3011, ‘Manual Sampling of Petroleum and Petroleum Products’. American Society for Testing and Materials (ASTM) D 4057, ‘Standard Practice for Manual Sampling of Petroleum and Petroleum Products’.

12.2.1c Property change during transportation When samples are moved from one environment to another it is inevitable that some of their properties change. Some common examples include entry of oxygen (anaerobic environment becoming aerobic), oxidation of chemical species, pH increase due to the liberation of dissolved acid gases, and liberation of dissolved solids from the liquid phase due to changes in pressure, temperature, volume, and flow. Some of these changes can be controlled and some cannot. Such changes should be minimized to the

12.2 Types of measurement

753

FIGURE 12.1 Schematic Diagram to Collect Samples for Offline Measurement.1 (Valve A is inlet to the sample container, valve B is outlet to the sample container, valve C is the outlet to inert gas, valve D is the inlet to the inert gas, and valve E is the access port to the oil and gas infrastructure. Depending upon the requirement and necessity all valves can be operated under pressure and temperature).

greatest extent possible during sample collection and transportation, and the potential influence of the change in the properties should be recognized when using the data for establishing corrosion conditions.

12.2.1d Competency of laboratory Offline measurements are typically performed in a laboratory which either may be owned by the oil and gas company or by a third party. Laboratories should conduct the test or analyze the samples carefully to produce consistent, high quality results. Many laboratories establish best practices based on experience and knowledge. The laboratories are not only required to ‘implement best practices’ but also required to ‘prove that they implement the best practices’. More and more companies recognize the value of such proof of implementation and implement rigorous approaches to maintaining quality. Such practices bring credibility to the laboratory, authenticate the results it produces, provide opportunities to evaluate and improve the performance, enable documentation of the activities, and facilitate establishment of consistency across the laboratory and laboratory personnel. ISO 17025 provides management and technical requirements for the competency of testing and calibration laboratories (Table 12.1).2 Accreditation to ISO 17025 is based on the ability of the laboratory to carry out specific tests using specific procedures, and may be used as one possible method to establish the competency of a laboratory to perform offline measurements.

12.2.1e Laboratory methodology A variety of laboratory methodologies are available to measure the properties. Figure 12.2 presents a typical sequence in performing a measurement in the laboratory.3 One or more of these steps may sometimes be left out, but in general each step is important and plays a key role – as described in the following paragraphs.

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CHAPTER 12 Measurements

Table 12.1 Requirements of ISO 17025 for Testing Laboratories2 Number

Management Requirement

Technical Requirement

1 2 3 4

Organization Management system Document control review of requests, tenders, and contracts

5 6 7 8 9

Subcontracting of tests and calibrations Purchasing services and supplies Service to customers Complaints Control of nonconforming testing and/or calibration work Improvement Corrective action Preventive action Control of records Internal audits Management reviews

General Personnel Accommodation and environmental conditions Test and calibration methods and method of validation Equipment Measurement of traceability Sampling handling testing and calibration items Assuring the quality of test and calibration results

10 11 12 13 14 15

Reporting results

i. Selection of laboratory methodology Several laboratory methodologies may be available to measure a given parameter. Therefore, selection of the most appropriate methodology may be difficult and it may require experience and intuition. The laboratory methodologies used in offline measurements are usually classified according to the type of measurement; i.e., gravimetric, volumetric, electroanalytical, spectroscopic, or miscellaneous. • •

In gravimetric methods the mass change is measured. In volumetric methods the volume change is measured. Selection of Laboratory Methodology Determination of Replicate Samples Preparation of Laboratory Samples Elimination of Interference Calibration and Measurement Computation of Results

FIGURE 12.2 Typical Sequence in a Laboratory Measurement.3

12.2 Types of measurement

• •

•

755

In electroanalytical methods, electrical or electrochemical properties such as potential, current, and quantity of electricity are measured. In spectroscopic methods, the interaction between electromagnetic radiation and the substance is measured. Common methods include X-ray, ultraviolet, visible, infrared, microwave, optical activity, refractive index, and mass spectroscopy. Miscellaneous methods include measurements of radioactive decay, heat of reaction, rate of reaction, and thermal conductivity.

A laboratory methodology is selected based on a compromise between accuracy, cost, and convenience. The accuracy of a laboratory methodology depends strongly on the sensing element used to measure a given parameter. In general, as the required accuracy increases, so does the time and money required to perform the measurement. If larger amounts of sample can be obtained from the field, then an accurate laboratory methodology which normally involves several steps may be used. On the other hand, if only a limited quantity of sample can be collected from the field or if the sample is not stable, then a laboratory methodology that yields a rapid result may be needed.

ii. Determination of replicate samples Laboratory measurements are normally performed using two identical samples of equal mass, volume, size, and shape; at the same time; using the same procedure; in the same way; and under the same conditions. For more accurate results, three to five samples are typically used. Measurements using a single sample may be performed if the same measurement is performed repeatedly at different time intervals using samples obtained from the same operating conditions and from the same location – otherwise measurements using only one sample should be avoided.

iii. Preparation of laboratory samples Depending on the laboratory methodology, type of measurement, and sample type, several steps may be used to prepare the sample. Such steps are specific, but general activities include grinding the sample to decrease the particle size, mixing with an appropriate solvent to ensure homogeneity (dissolution in solvents may involve heating, addition of acids, bases, oxidizing agents, reducing agents, or combination of any or all of these steps), processing the sample (e.g., ignition, heating, pressurization, and vaporization), addition of appropriate chemicals/elements to increase the accuracy of the measurement, and storing for various lengths of time before the measurement begins. None of these activities should change the property of the original sample. If changes are inevitable, then at least the influence of them on the property of the sample should be understood and reported.

iv. Elimination of interference The interaction between the analyte (the substance whose property is being measured) and the indicator substance should be unique and specific. However such unique and specific interaction seldom occurs. In addition to the analyte, other substances present in the sample may interact with the indicator substance to produce measurements that may increase or decrease the value of the analytes. Such substances are known as interfering species. The presence of interfering substances in the sample should be understood and a strategy should be developed to eliminate or minimize their effects. There is no specific hard and fast rule to eliminate interference; indeed overcoming this issue is not trivial and is the most demanding aspect of any measurement.

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v. Calibration and measurement The relationship between the property and the measured parameter can be expressed as: Ca ¼ k:Xa

(Eqn. 12.1)

where Ca is the property, e.g., concentration of the measured parameter, Xa is the value obtained in the measurement, and k is the proportionality constant. From Eqn. 12.1 it is obvious that the measured parameter should vary linearly with the property measured. During the calibration process, the value of k and the linear range of the relationship between Ca and Xa are established. The calibration process is usually empirical, except during gravimetric and coulometric measurements, in which k is computed using known physical constants.

vi. Computation of results Often the measured value is not the one that is displayed or reported; rather the measured value is computed to produce the final value. Normally the computation is a simple and straightforward task. The availability of modern calculators, computers, and microchips enable the automation of this process. However the assumptions made in converting the raw data collected during the measurement into processed data must be valid. The processed, displayed, or reported data should be in the range in which it is proportional to the measured value, Xa, i.e., Eqn. 12. 1 must be valid and applicable.

12.2.1f Measurement reliability It is impossible to perform offline measurements (and for that matter any measurements including corrosion monitoring discussed in Chapters 8 and 11) that are totally free of errors or uncertainties. The uncertainties combine to produce scatter in the results. Measurements are incomplete and are of no value without an estimate of their reliability, i.e., the uncertainties associated with the computed results. Measurement uncertainties may never be completely eliminated, so the true value of the property may always be unknown. Sometimes the species being analyzed, is intentionally added to spike its concentration and the ability of method to the increase in concentration is used to ascertain its reliability. However, it is important to estimate the magnitude of the errors so that the limits within which the true value of the reported or displayed value lies are known. It should be realized that it is not easy to estimate the reliability of measured data. Nevertheless this should be estimated, because without it the data itself may be almost useless. On the other hand, data that is known to be not especially accurate may still be useful if the level of uncertainty is well understood. Before analyzing the reliability of the data, the tolerance to error should be determined. Normally if the tolerance to error in the data is low, then the extent of the analysis required to determine reliability is high. On the other hand, if the tolerance to error in the data is relatively high then the effort to determine its reliability can be minimized. One should not spend more time in determining the reliability of the data than is actually required. For example, the pitting corrosion rate of carbon steel under certain conditions varies at a rate of about 1 mpy for a 1,000 ppm variation in chloride ion concentration. Therefore, a reliability of chloride ion concentration analysis in the range 1,000 ppm is sufficient for this purpose (see section 6.5). No simple, single rule exists that can be widely applied to estimate the reliability of data. Common approaches include: calibration of equipment using samples of known composition; comparison of data with those previously obtained using samples with same composition; use of

12.2 Types of measurement

757

several (typically 2 to 5) identical samples; and analysis of data using statistical methods. None of these options are perfect, so a certain amount of judgment should be exercised based on experience and knowledge.

i. Mean and median The most common approach to establish the reliability of a measurement is to use multiple samples. In this approach, the first step is to determine the mean or median. The mean is the arithmetic mean or standard mean (XM), obtained by summing all data generated and dividing the sum by the number of samples. The data should be generated using identical samples exposed to identical conditions and measured using an identical sequence (Eqn.12.2): PNM xi (Eqn. 12.2) XM ¼ i¼1 NM where xi is the individual value measured for each sample, and NM is the number of samples. For example, a measurement of six identical samples produced the following results: 9.4, 9.5, 9.6, 9.8, 10.1, and 10.3. The mean value for the data set is (Eqn.12.3): Mean ¼

9:4 þ 9:5 þ 9:6 þ 9:8 þ 10:1 þ 10:3 ¼ 9:8 6

(Eqn.12.3)

The median is the middle value of a set of data. To determine the median the data points are arranged in ascending or descending order. For an odd number of samples, the median is the value of the middle data point, and for an even number of samples, the median is the mean (or average) of the middle pair of data points. Under ideal conditions, the mean and median values are identical, but frequently they are not. For the same set of data in Eqn. 12.3, the median is 9.7 (Eqn. 12.4): 9:6 þ 9:8 ¼ 9:7 (Eqn.12.4) 2 Errors cause individual measurements performed under same conditions, i.e., using same size, volume, method, temperature, pressure, and flow, to deviate from the mean or median. The extent of error or uncertainty in the data is determined by the extent individual values deviate from mean or median. Errors in measurements can be broadly classified as three types: systematic or determinate, random or indeterminate, and gross. Median ¼

ii. Systematic or determinate error To define systematic error, one needs to understand ‘accuracy’. Accuracy is a measure of the closeness of the data to its true or accepted value. Figure 12.3 illustrates accuracy schematically.4 Determining the accuracy of a measurement is difficult because the true value may never be known, so for this reason an accepted value is commonly used. Systematic error moves the mean or average value of a measurement from the true or accepted value. Systematic error may be expressed as absolute error or relative error: •

The absolute error (EA) is a measure of the difference between the measured value (xi) and true or accepted value (xt) (Eqn. 12.5): E A ¼ xi

xt

(Eqn. 12.5)

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CHAPTER 12 Measurements

Low accuracy, low precision

Low accuracy, high precision

High accuracy, low precision

High accuracy, high precision

FIGURE 12.3 Difference between Accuracy and Precision in a Measurement.4 Reproduced with permission from Brooks/Cole, A Division of Cengage Learning.

Absolute error bears a sign: • •

A negative sign indicates that the measured value is smaller than true value and A positive sign indicates that the measured value is higher than true value

The relative error (ER) is the ratio of measured value to true value and it is expressed as (Eqn. 12.6):   xi xt ER ¼ 100 (Eqn. 12.6) xt Table 12.2 illustrates the absolute and relative errors for six measurements in determining the concentration of 20 ppm of an ionic species in solution. Systematic error may occur due to instrument, methodology, and personal error. Instrument error. Instrument error occurs due to variations that can affect the functionality of the instrument. Some common causes include temperature change, voltage fluctuation, variations in resistance, distortion of the container, error from original calibration, and contamination. Most instrument errors can be detected and corrected by frequently calibrating the instrument using a standard reference Table 12.2 Relative and Absolute Errors in Six Measurements of Aqueous Solution Containing 20 ppm of an Ionic Species Measured Value

Absolute Error

Relative Error (Percentage)

Remarks

19.4 19.5 19.6 19.8 20.1 20.3

0.6 0.5 0.4 0.2 þ0.1 þ0.3

3.0 2.5 2.0 1.0 þ0.5 þ1.5

Experimental value lower than actual value.

Experimental value higher than actual value.

12.2 Types of measurement

759

material. Standard reference materials may occur in different forms including minerals, gas mixtures, hydrocarbon mixtures, polymers, solutions of known concentration of chemicals, weight, and volume. The standard reference materials may be prepared in the laboratory or may be obtained from standardmaking organizations (e.g., ASTM standard reference materials), government agencies (e.g., National Institute of Standards and Technology (NIST) provides about 900 reference materials) and commercial suppliers. If standard materials are not available, a blank test may be performed using a solution without the sample. The value from this test may be used to correct the results from the actual sample. However this methodology may not be applicable for correcting instrumental error in all situations. Methodology error. Methodology error occurs due to the non-ideal physical or chemical behavior of the method. Some common causes include variation of chemical reaction and its rate, incompleteness of the reaction between analyte and the sensing element due to the presence of other interfering substances, non-specificity of the method, side reactions, and decomposition of the reactant due to the measurement process. Methodology error is often difficult to detect and correct, and is therefore the most serious of the three types of systematic error. Therefore a suitable method free from methodology error should be established for routine analysis. Personal error. Personal error occurs due to carelessness, lack of detailed knowledge of the measurement, limitation (e.g., color blindness of a person performing color-change titration), judgment, and prejudice of person performing the measurement. Some of these can be overcome by automation, proper training, and making sure that the person overcomes any bias to preserve the integrity of the measurement.

iii. Random or Indeterminate error To understand random error we should understand ‘precision’. Precision is a measure of closeness of data to other data that have been obtained in exactly the same way. Generally, precision is determined by repeating the measurement using several samples. There are two ways to repeat the measurement: • •

The same person performing the measurement using same equipment and by following the same procedure. The precision determined by this process is commonly known as ‘repeatability’. Different persons performing the measurement using similar equipment and by following the same procedure. The precision determined by this process is commonly known as ‘reproducibility’. In general, ‘reproducibility’ is lower than ‘repeatability’.

Precision is indicated by several statistical terms including standard deviation, variance, and coefficient of variance. All these terms indicate the variation of the data from the mean. Of these, the standard deviation is the most widely used. The standard deviation, sstd is given by (Eqn. 12.7): sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 2ffi PN M  m x i population i¼1 (Eqn. 12.7) sstd ¼ NM where mpopulation is the mean population. Figure 12.4 presents two sets of data that have same mean, but have differing standard deviations.5 The standard deviation of the measurements producing curve B is 2.5 times that of those producing curve A. Therefore, the precision in the measurements producing curve A is 2.5 times that of the measurements producing curve B. Thus standard deviation indicates the magnitude of random errors.

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CHAPTER 12 Measurements

Relative frequency

(A)

Relative frequency

(B)

Relative frequency

(C)

0.4 0.3 0.2 0.1 0 –6U –4U –2U 0 +2U +4U +6U Deviation from mean 0.4 0.3 0.2 0.1 0 –12U –8U –4U 0 +4U +8U +12U Deviation from mean 0.4 0.3 0.2 0.1 0 –

0 Deviation from mean

+

FIGURE 12.4 Frequency of Distribution for Measurements Containing (A) Four Random Uncertainties; (B) Ten Random Uncertainties; and (C) A Very Large Number of Random Uncertainties.5 Reproduced with permission from Brooks/Cole, A Division of Cengage Learning.

Random or indeterminate error causes imprecision, i.e., the measurement scatters more or less symmetrically around the mean (Figure 12.3). Random error is caused by several variables which are inevitable in any measurement. The individual variables cannot be quantified due to their smaller magnitude and due to the randomness of their occurrence. The cumulative effect of these variables normally causes repeat measurements to fluctuate randomly around the mean value. This can be illustrated by a very simple process of the calibration of a pipette (a small glass apparatus to withdraw, measure, and drain a solution for titration or other chemical reaction). The variation or randomness in this process includes: • •

Visual judgment of the level of the solution with respect to the marking on the pipette. Variation in the drainage time due to the variation in the angle at which the pipette is held.

12.2 Types of measurement

• •

761

Temperature fluctuations which may alter the volume of the pipette and viscosity of the liquid. Improper cleaning and drying of the pipette which may dilute the solution.

Figure 12.4 illustrates how small undetectable uncertainties produce detectable random errors. Consider a system with four small undetectable uncertainties and where the probability of occurrence of each uncertainty is equal. The several measurements of the system produce a data set similar to the one shown in Figure 12.4A; the x-axis of the figure displays the frequency of occurrence of five possible combinations (including measurement with zero error). Similarly, several measurements of system with ten small undetectable uncertainties produce a data set similar to the one shown in Figure 12.4B. Figure 12.4C presents the frequency of occurrence of measurements in a system affected by a very large number of individual errors. The common factor in all three figures is that the most frequent occurrence is zero deviation from the mean. The frequency of occurrence of extreme deviation from mean decreases progressively. Random errors are frequently represented by a Gaussian curve, i.e., they exhibit Gaussian or normal distribution behavior. Some common properties of Gaussian behavior include: • • •

The mean occurs at the middle, with highest frequency. The errors are symmetrically distributed on either side of the mean, i.e., both in the positive and negative directions. The frequency of occurrence of a value decreases exponentially as the magnitude of its deviation from the mean increases.

Figure 12.5 presents one example of a system exhibiting Gaussian behavior.6 In the figure the relative frequency of occurrence, y, is plotted as a function of deviation from the mean. Figure 12.5 can be mathematically represented (Eqn. 12.8): y¼

e

ð XM

mpopulation Þ 2s2

pffiffiffiffiffiffi s 2p

2

(Eqn. 12.8)

The standard mean (XM) is the average of data when the number of data points is less than 20. The population mean, mpopulation, is the average of the data when the number of data points is greater than 20 (Eqn. 12.9): PN M xi (Eqn. 12.9) mpopulation ¼ i 1 NM Notice that Eqns 12.2 and 12.9 are the same except for the magnitude of NM. When the value of N is 20 or above, the difference between standard mean and population mean is negligible.

iv. Gross error Gross error occurs occasionally and is also known as outlier. An outlier is a data point that differs significantly from the rest of the data in a set. Outliers cause significant effects on the mean value, but have a smaller effect on the median. The occurrence of an outlier is an indication of uncertainty.

12.2.1g Lag time Section 12.2.1c discusses changes in properties during transportation from the field to the lab. Once the samples arrive at the testing laboratory, they should be appropriately stored until ready for testing, and

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CHAPTER 12 Measurements

(A) 0.4

Relative frequency

–σA

A

+σA

0.3

0.2 B

σB 0.1

σB

–2σB

2σB –2σA

2σA

0 – 0 + Deviation from mean, x – µ

(B) 0.4

Relative frequency

–σ

+σ

0.3

0.2 A or B –2σ

+2σ

0.1 –3σ 0 –4σ

+3σ

–2σ

0 z = x –µ σ

2σ

4σ

FIGURE 12.5 Gaussian Curve6 Note: The standard deviation for curve B is twice that for curve A, that is, sB ¼ 2sA. (A) the x-axis is the deviation from the mean in the units of measurement. (B) The x-axis is the deviation from the mean in units of s. Thus, the two curves A and B are identical. Reproduced with permission from Brooks/Cole, A Division of Cengage Learning.

procedures for transferring them from the transportation container to the test container should be preestablished. The lag time between the sample collection and measurement should be minimized to the greatest extent possible. Laboratories perform several different types of measurements, so prior arrangements should be made so that the samples are analyzed as soon as they arrive. In any event, the lag time should be known and its influence should be considered before using data for corrosion control purposes.

12.2 Types of measurement

763

12.2.1h Communication Once the analysis is performed, the results are provided to the appropriate field operators. This may be in the form of a paper report, fax, phone call, email, or data entry in the company’s network. Many situations, data from different measurements are available within a company, or a certain group within it, but may not readily be available to the corrosion professional. It is the responsibility of the corrosion professional to be aware of the existence of such data and to coordinate with the appropriate laboratory and field personnel to obtain the data from appropriate sources.

12.2.2 Online measurement Online techniques make measurements without removing a sample from the operating system. Benefits of online measurement in addition to avoiding sample removal include automation, reduced time and effort for data collection, higher frequency of data collection, relatively high reliability of data, quicker response time, and better ability to understand process changes. Online techniques are commonly used to measure temperature, pressure, flow rate, chemical injection rate, moisture content, fluid level, pH, and dissolved gases. Some online measurements are manual and some can be automated. In manual measurements, the sensor may be permanently attached onto or placed into the structure, and an operator physically measures the parameter at predetermined time intervals. In automated online measurement, the data is collected by the instrumentation continuously or at predetermined time intervals. Automation enables the integration of several functions. In a simple system, the sensor and the control system are integrated so that the control system triggers the sensor to measure a parameter at predetermined intervals of time and records the data collected. In a complex system, multiple measurement systems are integrated leading to the establishment of a supervisory control and data acquisition (SCADA) system (see section 12.2.2f). Online measurement continuously evolves as new tools are developed, tested, proven, and trusted by both the operator and the regulator. Key components that enhance online measurement include access ports, sensors, actuators, electronics, automation, SCADA systems, reliability of the system, and communication tools. These components are discussed briefly in the following paragraphs.

12.2.2a Access port One of the primary requirements for making online measurements is the ability to safely and reliably place the sensor in the appropriate location of the infrastructure. This is relatively easy for measuring the external surface of the infrastructure, or the external environment as long as the sensor is secured against natural, intentional (theft), or unintentional (tripping or digging in the right of way) calamities. For measurements requiring access to the internal surface of the infrastructure or the internal environment it is important to reliably, swiftly, and safely place the sensor in the system. Under ideal conditions, locations for placing measuring devices are planned during the design stage; the devices are placed during construction, and are connected to instrumentation before operation. Ideally, an access fitting assemblies are available to place online measurement devices without shutting down the operation. These assemblies enable the placement of online measurement devices into systems operating as high as 6,000 psi (41 MPa) pressure. An access fitting assembly typically consists of a fitting body, a drilling machine, a sensor assembly, a plug assembly, a protective cover, a retriever, and a service valve.

764

CHAPTER 12 Measurements

FIGURE 12.6 Fitting Body of the Access Port.7 (A) Non-tee. (B) Tee.

The fitting body is welded onto the external surface of the infrastructure or bolted to a flange. It enables the insertion of measuring device inside the infrastructure operating while still under pressure. The fitting body may have two configurations: non-tee and tee (Figure 12.6).7 Once the fitting body is attached, the material is stress-relieved and pressure tested to ensure the integrity of the fitting body. Once the access fitting is placed, a hole is drilled using a drilling machine (Figure 12.7)7 to allow the sensor to be inserted. The sensor assembly normally consists of the sensor nut, sensor, nipple, and a shut-off valve. The sensor nut holds the sensor in place and the nut is secured onto the internal bore of the access fitting using an O-ring. The plug assembly is used to hold the sensor in position and to close the access fitting. The plug may be hollow or solid (Figure 12.8).7 The plug also provides primary sealing between it and the access port. In addition, O-rings are used to provide further sealing. The access fitting along with other accessories are protected from external mechanical damage, dust, dirt, and moisture using protective covers. The retriever and service valve is used to retrieve the sensor from

12.2 Types of measurement

765

FIGURE 12.7 Drilling Assembly to Place Corrosion Probes in Operating System.7

the infrastructure without depressurizing the operation. Sometimes safety concerns require that flow in the system be shut down during retrieval operations. In these cases, the system is not depressurized, so shut down and start up are very quick.

12.2.2b Sensors The sensors should reliably measure the parameter under the prevailing operating conditions. The environment in which the sensor is placed can affect its integrity, and lead to false readings. Hence, it must be compatible with the environment. It is important to understand the capability of the sensor, the nature of the operating environment, and the nature of the measurement required before selecting an appropriate sensor. In general the sensors must: • • • • •

Be robust so that they can withstand the operating pressure, temperature, and other environmental conditions in which they function. Be accurate, i.e., the sensor reading must be in the linear range of the measured parameter. Measure a particular parameter in the presence of other interfering species and parameters. Measure continuously or intermittently. Be capable of detecting threats before damage is caused, i.e., be a leading rather than a trailing indicator.

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CHAPTER 12 Measurements

FIGURE 12.8 Plug Assembly.7

• •

Be placed in a location in which the particular parameter should be measured. For example, a gas sensing element placed in an oil phase does not produce useful results. Have a long service life, i.e., the sensing element must be stable under normal operating conditions. The sensing element should be replaced before the end of its service life, otherwise the readings will slowly drift and the user will not know if this is due to an actual reading change or a sensor malfunction.

12.2 Types of measurement

•

•

767

Have a long shelf life, i.e., the sensing element must be stable from the time of manufacture and the time of installation. The sensor should be installed before the end of its shelf life. Not leach. Some sensors have good accuracy at the beginning, but the reading slowly drifts or their response time increases if the sensing element leaches out. Therefore such sensors require frequent calibration.

The sensors may be divided into different categories: •

•

•

One Time vs. Repeat Measurement Sensors: Depending on the nature of measurement, the sensing element may be used only once, i.e., one time measurement sensor, or may be used several times, i.e., repeat measurement sensor. One time sensors are useful to indicate if a particular parameter has reached a threshold. Contact vs. Remote Sensors: Contact sensors measure only when the parameter comes into contact with them, whereas remote sensors measure the parameter without physical contact. However technology has not yet advanced sufficiently to produce a reliable remote sensor for oil and gas infrastructure. Manual vs. Automatic Sensors: Manual sensors make measurements only if an operator prompts it to; whereas automatic sensors can be programmed to take measurements at predetermined intervals of time.

12.2.2c Actuators Online measurements may be integrated with actuators. An actuator is a device that controls an action, e.g., moving a part, shutting a valve, or stopping a motion. For example, an online pressure or temperature sensor may trigger an actuator to stop flow or shut down a valve when the pressure or temperature exceeds a threshold value. The sensor output may be electrical, electronic, hydraulic, or pneumatic. Various sensor and actuator combinations are used throughout the oil and gas industry. For example, trunk pipelines have mainline valve stations at various locations to isolate sections of pipelines during maintenance or emergencies. These valve stations may contain sensor-actuator combinations. When the sensor measures a temperature or pressure exceeding a predetermined threshold, the actuator is automatically activated to shut and isolate the relevant section.

12.2.2d Electronics Advancements in electronics have enabled the deployment of online measuring devices and their remote operation. Electronics were initially used as discrete components but they are now the key factor in the automation of several operations, including online measurement. In general, the implementation of electronic circuits is cost effective when compared with pneumatic and electromagnetic circuits. Microprocessors and microcomputers combined with software programs provide flexible, capable, and reliable online measurement systems. Some electronic components commonly used in online measurement are discussed in this section. Signals from most online sensors are received and stored in a tiny box commonly known as a controller. The controller can be deployed in the field for long-term and unattended measurement. An operator could physically visit the controller unit and download the data or the controller could transmit the data through a wired or wireless network.

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Online monitoring may sometimes be referred to as remote monitoring. The two categories of remote monitoring should be understood. In one category, the sensor is physically remote from the environment in which the measurement is made. Although this is an ideal method of measurement, sensor technology has not yet advanced sufficiently for this to be useful. In the other category, the sensor is physically located in the environment in which the measurement is to be made, and it passes the signal to the controller through a physical connection. The controller then transmits the signal to a remote site. Most of the remote monitoring techniques used in the oil and gas industry fall into this second category. It should be realized that almost all recent electronic and communication advances have been in the controller and the display units, with essentially no or little development in the sensor technology. The controller may consist of several units including data acquisition, pre-processing, and communication (Figure 12.9). These units may be physically identifiable or integrated into one unit. Additionally, some units may be present in the controller in the field or in the company’s centralized control unit (e.g., mother control unit). The data acquisition unit triggers the sensor to make a measurement, receives the data from the sensor, and stores the data for easy downloading. The data acquisition unit may be linked to several sensors of the same or different types. By using several data acquisition units and appropriate software, the controller interacts with several sensors simultaneously or sequentially. In some configurations, the controller does not store all data permanently in the data acquisition unit. The data is processed by the pre-processing unit based on logic, algorithms, and knowledge is stored in the database. Only those data which are relevant and important are acted upon and other data are discarded. The communication unit communicates the data from the data acquisition unit or from the preprocessing unit. The communication may be in the form displayed data, triggering of a condition warning (e.g., alarm), sending a report (e.g., email or signal), or taking an action (e.g., activating the actuator unit).

Sensors

Data Acquisition

Knowledge-base

Pre-processing

Communication

Display

Alarm

Report

FIGURE 12.9 Schematic Diagram of a Typical Central Controller.

Actuator

12.2 Types of measurement

769

12.2.2e Automation Some form of automation is used in every sector of the oil and gas industry. Its extent depends on the availability of reliable technology, and on economics. Some benefits of automation include: • • • •

Operation cost decreases due to decreased labor cost. Documents and data required for regulatory and other operational purposes are easily and reliability produced. Surveillance of oil and gas infrastructure improvements. The quantity and quality of available information increase so that better informed decisions can be made.

Automation in the oil and gas industry evolves as new online measurement techniques and other technologies are developed, tested, trusted, and accepted by the industry and regulators. Advancements in electronics accelerate the automation of measurements. Lease automatic custody transfer (LACT) is a good example of the successful integration of online measuring techniques and other operations. LACT is a process of transferring oil into a pipeline from storage tanks in an unattended manner. The LACT process includes the automatic determination of the quality and quantity of the oil. One of the key activities of this operation is online monitoring of the water and sediment contents of the oil using an automatic sampler, online capacitance probe, or other suitable online probe. Depending on the data obtained, the quality of the oil is established and a decision is automatically made to either fill the pipeline with oil or to send an alarm on oil purity. Before the establishment of the LACT process, the industry measured the quantity and quality of oil in a labor-intensive and timeconsuming manual process. Automation in the oil and gas industry will continue to evolve as new tools are developed and deployed. These advancements may take the form of improvements to existing techniques, development of new techniques with improved capacity and reliability, and development of new technologies with abilities that are not currently available or conceivable. In this context, it should be pointed out that most of the basic instrumentation and control equipment currently used in existing infrastructures in the oil and gas industry is primarily pneumatic-based, but technologies conducive for automation are electronic-based. Therefore, automation of online measuring techniques in the oil and gas industry will always lag behind the electronic revolution. Table 12.3 presents some examples of automatically controlled equipment used in the oil and gas industry.8

12.2.2f Supervisory control and data acquisition (SCADA) Supervisory control and data acquisition (SCADA) is a common name used in the oil and gas industry to represent a computer-controlled automation and logic system. It links several instruments and control devices which perform several functions including measurement, monitoring, sounding an alarm, testing, controlling (flow, pressure, and heater), and reporting. It provides the opportunity to monitor several units from a centralized location. A SCADA system may be used to monitor a few devices in a single production well, or to monitor a few thousand devices in many production wells or in a large refinery. The SCADA system can be programmed in ‘open loop’ or as ‘closed-loop’ or ‘hybrid’ configurations. In the ‘open loop’ configuration, it simply collects the data and provides the information to the operational personnel. In the ‘closed-loop’ configuration it collects the data, analyzes it, and initiates

770

CHAPTER 12 Measurements

Table 12.3 Examples of Automatically Controlled and Operated Equipment in the Oil and Gas Industry8 Procedure

Function

Techniques

Fluid flow Shut in operation Pressure Liquid level Liquid level quantity

Valve Valve Switch Valve Meter

Fluid-control or electrical control

Gas measurement

Meter

Temperature measurement Oil sampler Sediment and water (BS&W) Well head control Rod-pump control Gas lift control Water-treatment Addition of chemicals Water supply Oil in gas Gas in oil Oil in water

Meter Quantity and quality Quantity Valve Valve Valve Valve Injection pump Valve Quantity Quantity Quantity

Positive-volume meter, positive displacement meter, and inferential meter Positive displacement meter, gas-flow computer, gas turbine meters, and vortex meter

Capacitance

Laser liquid particle spectrometer Densometer Infrared absorbance

control actions automatically without human intervention. In the ‘hybrid’ configuration, the functionalities of both ‘open loop’ and ‘closed-loop’ configurations are integrated as required. A SCADA system is thus an overall process management system which integrates, consolidates, and optimizes several interrelated or closely related operational functions. Before the introduction of SCADA, several of these operational functions were carried out independently, without understanding the consequence of the operation for the downstream or upstream operations. For example, if a failure occurs in the gas processing facility, the SCADA system automatically shuts down the wells with high gas-to-oil (GOR) ratios. Thus SCADA, by providing timely and accurate operational information, maximizes the utilization of existing process equipment and minimizes the need for stand-by capacity. Although a SCADA system can include the corrosion monitoring discussed in Chapters 8 and 11, at present most SCADA systems only include process measurements.

12.2.2g Reliability of measurement All aspects of reliability discussed in section 12.2.1f are applicable for online measurement. Additional complications affecting the reliability of online measurements include: •

Variation of operating conditions; operating conditions of almost all sectors of the oil and gas industry vary routinely or randomly. The type of change in the operating conditions and its influence on the online measuring technique should be understood.

12.3 Measured properties

•

•

•

•

771

Accidental and systematic contamination of the sensor; often the environment in which the online sensor is placed may be contaminated with substances that can reduce the reliability of the online measurement. Lack of easy visual inspection; once placed, the online sensors are out of sight of the operator. Therefore they cannot be readily visually inspected to ensure that they have not undergone any physical changes. Using sensors beyond their service life; every sensor has an anticipated life expectancy. The sensors should be replaced or serviced before the expiration of their service life. Sometimes, operational conditions do not allow the replacement of online sensors on time, so valuable data cannot be collected, or the reliability of the data collected is poor. Communication systems; the reliability of online measurement also depends on the reliability of the communication system. Any changes in the communication system, e.g., software, protocol, or malfunctions affect online measurements.

12.2.2h Communication All the communication issues discussed for offline measurement (section 12.2.1h) are also applicable to online measurement. In general the transfer of data from online measurement occurs in two stages: • •

Transfer of data from the sensor to the central location through controllers. Transfer of data from the central location to the corrosion professionals.

It is the responsibility of the corrosion professional to take a proactive approach to accessing the data. This can routinely be done through downloadable webpage, email, fax, telephone, paper, or other suitable means.

12.3 Measured properties Several properties are measured for various purposes by different groups throughout the oil and gas industry. Some of these properties are required or useful to the corrosion professional, but the corrosion professionals are not the group in the company that measures them. By understanding the source of the measurement and by establishing the procedures to obtain these properties, the corrosion professional may take informed decisions without incurring huge additional expenditures. Chapter 4 discusses these properties and their influence on corrosion and this section discusses the methods of measuring these properties. Table 12.4 describes how these properties are measured and lists the groups that may possess the data.

12.3.1 Physical properties of materials Of the various physical properties of materials, corrosion professionals are mainly interested in yield strength, tensile strength, hardness, impact resistance, and fatigue resistance. Section 3.2.1 discusses the importance of these properties in relation to corrosion. Standards providing guidelines for measuring these physical properties include: • • •

ASTM A370, ‘Standard Test Methods and Definitions for Mechanical Testing of Steel Products’. ASTM E10, ‘Standard Test Method for Brinell Hardness of Metallic Materials’ ASTM E384, ‘Standard Test Method for Knoop and Vickers Hardness of Materials’.

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Table 12.4 Commonly Required ‘Measured’ Properties for Corrosion Control and Their Possible Sources

• • • • • • •

• • •

Properties

Type Of Measurements

Possible Sources

Physical properties of materials Chemical properties of materials Volume of oil Volume of gas

Design team Design team Operation team Operation team

Physical properties of oil Physical properties of gas Physical properties of water Flow Pressure Chemical properties of oil Chemical properties of gas Chemical properties of water Sand Fouling Soil properties

Offline Offline Online Online but correction factor is used to account for compressibility factor Online and offline Online and offline Online and offline Online Online Offline Offline Offline Online Online Offline

Environmental properties

Offline

Weather

Online

Operation team Operation team Operation team Flow assurance team Operation team Operation team Operation team Operation team Production team Operation team Government agricultural department Government environmental department Government environmental department

ASTM A833, ‘Standard Practice for Indentation Hardness of Metallic Materials by Comparison Hardness Testers’. ASTM E18, ‘Standard Test Methods for Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials’. ASTM E110, ‘Standard Test Method for Indentation Hardness of Metallic Materials by Portable Hardness Testers’. ASTM E448, ‘Standard Practice for Scleroscope Hardness Testing of Metallic Materials’. ASTM A1038, ‘Standard Test Method for Portable Hardness Testing by the Ultrasonic Contact Impedance Method’. ASTM A956, ‘Standard Test Method for Leeb Hardness Testing of Steel Products’. ASTM E140, ‘Standard Hardness Conversion Tables for Metals Relationship Among Brinell Hardness, Vickers Hardness, Rockwell Hardness, Superficial Hardness, Knoop Hardness, and Scleroscope Hardness’. ASTM E23, ‘Standard Test Methods for Notched Bar Impact Testing of Metallic Materials’. ASTM E2298, ‘Standard Test Method for Instrumented Impact Testing of Metallic Materials’. ASTM E468, ‘Standard Practice for Presentation of Constant Amplitude Fatigue Test Results for Metallic Materials’.

12.3 Measured properties

• •

773

ASTM E1949, ‘Standard Test Method for Ambient Temperature Fatigue Life of Metallic Bonded Resistance Strain Gages’. ASTM E8, ‘Standard Test Methods for Tension Testing of Metallic Materials’.

12.3.2 Chemical properties of materials Chapter 3 presents the characteristics of materials used in the oil and gas industry. Materials are selected based on several considerations, including corrosion. Chemistry plays a key role in the susceptibility of a material to corrosion. The responsibility for the analysis of materials used in construction is done by the design and fabrication teams of the company. Standards providing guidelines to analyze material chemistry include: • • • • • • • • • • • • • • • • • •

ASTM E32, ‘Standard Practices for Sampling Ferroalloys and Steel Additives for Determination of Chemical Composition’. ASTM E322, ‘Standard Test Method for X-Ray Emission Spectrometric Analysis of Low-Alloy Steels and Cast Irons’. ASTM E350, ‘Standard Test Methods for Chemical Analysis of Carbon Steel, Low-Alloy Steel, Silicon Electrical Steel, Ingot Iron, and Wrought Iron’. ASTM E351, ‘Standard Test Methods for Chemical Analysis of Cast Iron – All Types’. ASTM E352, ‘Standard Test Methods for Chemical Analysis of Tool Steels and Other Similar Medium- and High-Alloy Steels’. ASTM E353, ‘Standard Test Methods for Chemical Analysis of Stainless, Heat-Resisting, Maraging, and Other Similar Chromium-Nickel-Iron Alloys’. ASTM E354, ‘Standard Test Methods for Chemical Analysis of High Temperature, Electrical, Magnetic, and Other Similar Iron, Nickel, and Cobalt Alloys’. ASTM E363, ‘Standard Test Methods for Chemical Analysis of Chromium and Ferrochromium’. ASTM E367, ‘Standard Test Methods for Chemical Analysis of Ferroniobium’. ASTM E372, ‘Standard Test Method for Determination of Calcium and Magnesium in Magnesium Ferrosilicon’. ASTM E415, ‘Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel’. ASTM E485, ‘Standard Test Method for Optical Emission Vacuum Spectrometric Analysis of Blast Furnace Iron by the Point-to-Plane Technique’. ASTM E572, ‘Standard Test Method for Analysis of Stainless and Alloy Steels by X-Ray Fluorescence Spectrometry’. ASTM E1009, ‘Standard Practice for Evaluating an Optical Emission Vacuum Spectrometer to Analyze Carbon and Low-Alloy Steel’. ASTM E1010, ‘Standard Practice for Preparation of Disk Specimens of Steel and Iron for Spectrochemical Analysis by Remelting’. ASTM E1019, ‘Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques’. ASTM E1085, ‘Standard Test Method for Analysis of Low-Alloy Steels by X-Ray Fluorescence Spectrometry’. ASTM E1086, ‘Standard Test Method for Optical Emission Vacuum Spectrometric Analysis of Stainless Steel by the Point-to-Plane Excitation Technique’.

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ASTM E1806, ‘Standard Practice for Sampling Steel and Iron for Determination of Chemical Composition’. ASTM E1852, ‘Standard Test Method for Determination of Low Levels of Antimony in Carbon and Low-Alloy Steel by Graphite Furnace Atomic Absorption Spectrometry’. ASTM E1999, ‘Standard Test Method for Analysis of Cast Iron by Spark Atomic Emission Spectrometry’.

12.3.3 Volume of oil The volume is routinely measured by various sectors of the oil and gas industry, and the procedures for these measurements are well established. The guidelines for measuring the volume of oil and other liquid hydrocarbons include: • • • • • • • • • • • • • • • • • • • • • • • • •

API manual, ‘Petroleum Measurement Standards’ Chaps. 1, 5, and 6. API Specification 11N, ‘Specifications for LACT Equipment’. API Publication 852-25500, ‘Measurement and Calibration of Upright Cylindrical Tanks’. API Publication 852-25510, ‘Measurement and Calibration of Horizontal Tanks’. API Publication 852-25520, ‘Measurement and Calibration of Spheres and Spheroids’. API Publication 852-25530, ‘Measurement and Calibration of Barges’. API Publication 852-25540, ‘Measurement and Calibration of Tank Cars’. API Publication 852-25550, ‘Method for liquid calibration of tanks’. API Publication 852-25560, ‘Correcting Gauge Tables for Incrustation’. API Publication 852-25450, ‘Method of Gauging Petroleum and Petroleum Products’. API Publication 852-23150, ‘Proving Systems’. API Publication 852-30103, ‘Turbine Meters’. API Publication 852-30104, ‘Instrumentation Or Accessory Equipment for Liquid Hydrocarbon Metering Systems’. API Publication 852-30105, ‘Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems’. API Publication 852-30121, ‘Lact Systems’. API Publication 852-30125, ‘Metering Systems for Loading and Unloading Marine Bulk Carriers’. API Publication 852-30126, ‘Pipeline Metering Systems’. API Publication 852-30127, ‘Metering Viscous Hydrocarbons’. API Publication 852-11010, ‘Measurement of Petroleum Liquid Hydrocarbons by Positive Displacement Meter’. API Publication 852-30302, ‘Calculation of Liquid Petroleum Quantities Measure by Turbine Or Displacement Meters’. API Publication 852-30303, ‘Instructions for Calculating Liquid Petroleum Quantities Measured by Turbine or Displacement Meters’. API Publication 852-25340, ‘Charts and Statistical Methods for Petroleum Metering Systems’. API Publication 852-27150, ‘Volume Correction Factors’. API Publication 852-25410, ‘Standard Tables for Positive Displacement Meter Prover Tanks’. Astm D1250, ‘Petroleum Measurement Subsidiary’.

12.3 Measured properties

775

12.3.4 Volume of gas Measurements of the volume of a gas are not direct, because of its compressibility. The volume measured at a given temperature and pressure should be corrected to the volume at a standard temperature and pressure.10,11 The standards providing guidelines for measuring the volume of gas include: • • • • • • • • • • •

Gas Processors Suppliers Association (GPSA), Engineering Data Book.11 American Gas Association, Report # 3, ‘Orifice Constants’. API MPMS Chapter 14.3, ‘Natural Gas Fluids Measurement: Concentric, Square-Edged Orifice Meters’. American Meter Company, Handbook E-2, ‘Orifice Constants’. American Gas Association, NX-19, ‘Supercompressibility’. Pacific Energy Association, Ts-561 and Ts-461, ‘Super Compressibility’. API Publication 852-25654, ‘Propane Compressibility’. API Publication 852-25656, ‘Propylene Compressibility’. API Publication 852-30341, ‘Measuring, Sampling, Testing, and Base Conditions for Natural Gas Fluids’. API Publication 852-30343, ‘Orifice Metering of Natural Gas’. API Publication 852-30345, ‘Calculation of Gross Heating Value, Specific Gravity, and Compressibility of Natural Gas Mixtures from Compositional Analysis’.

12.3.5 Physical properties of oil The physical properties of oil determine its flow rate and other fluid properties. The physical properties measured include density, viscosity (determines the flow rate and hence indirectly influences corrosion), vapor pressure, water content, sediment content, filterability (measure of water retention property of crude oil), emulsion (an indirect measure of the water absorption tendency of crude oil), electrical conductivity, foaming tendency (in addition to changing the flow pattern, this may interfere with corrosion inhibitors) and flash point (although this does not directly affect corrosion, it determines if an oil sample can be transported in containers from the field to the laboratory. Certain countries have restrictions to the transportation of oil without flash point data). The standards providing guidelines for measuring the physical properties of oil include: • • • • • •

ASTM D71, ‘Standard Test Method for Relative Density of Solid Pitch and Asphalt (Displacement Method)’. ASTM D1217, ‘Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer’. ASTM D1480, ‘Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer’. ASTM D1481, ‘Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary Pycnometer’. ASTM D2320, ‘Standard Test Method for Density (Relative Density) of Solid Pitch (Pycnometer Method)’. ASTM D2638, ‘Standard Test Method for Real Density of Calcined Petroleum Coke by Helium Pycnometer’.

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CHAPTER 12 Measurements

ASTM D4292, ‘Standard Test Method for Determination of Vibrated Bulk Density of Calcined Petroleum Coke’. ASTM D4892, ‘Standard Test Method for Density of Solid Pitch (Helium Pycnometer Method)’. ASTM D5004, ‘Standard Test Method for Real Density of Calcined Petroleum Coke by Xylene Displacement’. ASTM D1298, ‘Standard Test Method for Density, Relative Density (Specific Gravity)’. API Publication 852-3018, ‘Hydrometer Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products’. API Publication 852-30182, ‘Pressure Hydrometer Test Method for Density Or Relative Density’. ASTM D1657, ‘Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer’. ASTM D4052, ‘Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter’. ASTM D5002, ‘Standard Test Method for Density and Relative Density of Crude Oils by Digital Density Analyzer’. ASTM D2624, ‘Standard Test Methods for Electrical Conductivity of Aviation and Distillate Fuels’. ASTM D4308, ‘Standard Test Method for Electrical Conductivity of Liquid Hydrocarbons by Precision Meter’. IP 274, ‘Conductivity Measurement in Light Oil Products’. ISO 6297, ‘Aviation and Distillate Fuels – Determination of Electrical Conductivity’. DIN 51412 T2, ‘Electrical Conductivity of Fuels’. ASTM D6794, ‘Standard Test Method for Measuring the Effect on Filterability of Engine Oils After Treatment with Various Amounts of Water and a Long (6-h) Heating Time’. ASTM D6795, ‘Standard Test Method for Measuring the Effect on Filterability of Engine Oils After Treatment with Water and Dry Ice and a Short (30-min) Heating Time’. ASTM D6450, ‘Standard Test Method for Flash Point by Continuously Closed Cup (CCCFP) Tester’. ASTM D92, ‘Standard Test Method for Flash and Fire Points by Cleveland Open Cup Tester’. ASTM D7094, ‘Standard Test Method for Flash Point by Modified Continuously Closed Cup (MCCCFP) Tester’. ASTM D7236- 07, ‘Standard Test Method for Flash Point by Small Scale Closed Cup Tester (Ramp Method)’. ASTM D93, ‘Standard Test Methods for Flash Point by Pensky-Martens Closed Cup Tester’. ASTM D56, ‘Standard Test Method for Flash Point by Tag Closed Cup Tester’. ASTM D3828, ‘Standard Test Methods for Flash Point by Small Scale Closed Cup Tester’. IP 36, ‘Determination of Flash and Fire Points’. ISO 2592, ‘Determination of Flash and Fire Points’. DIN 51376, ‘Flash and Fire Points by Cleveland Open Cup Tester’. DIN 51411, ‘Testing of Liquid Mineral Oil Hydrocarbons; Determination of Saybolt Color’. JIS K 2265, ‘Determination of Flash Points’. JIS K 2580, ‘Petroleum Products – Determination of Color’. AFNOR T60–118, ‘Cleveland Flash Point Tester’. AFNOR M07–003, ‘Determination of the Saybolt Color of Refined Petroleum Products’.

12.3 Measured properties

• • • • • • • • • • • • • • • • •

• • • • • • • • • • • • •

777

ASTM D2711, ‘Standard Test Method for Demulsibility Characteristics of Lubricating Oils’. ASTM D3519, ‘Standard Test Method for Foam in Aqueous Media (Blender Test)’. ASTM D3601, ‘Standard Test Method for Foam in Aqueous Media (Bottle Test)’. ASTM D892, ‘Standard Test Method for Foaming Characteristics of Lubricating Oils’. ASTM D6082, ‘Standard Test Method for High Temperature Foaming Characteristics of Lubricating Oils’. IP 146, ‘Foaming Characteristics of Lubricating Oils’. ISO 6247, ‘Determination of Foaming Characteristics of Lubricating Oils’. DIN 51566, ‘Foaming Characteristics of Lubricating Oils’. JIS K 2518, ‘Lubricating oils – Determination of Foaming Characteristics’. ASTM D6377, ‘Standard Test Method for Determination of Vapor Pressure of Crude Oil: VPCRx (Expansion Method)’. ASTM D4953, ‘Standard Test Method for Vapor Pressure of Gasoline and Gasoline-Oxygenate Blends (Dry Method)’. ASTM D6897, ‘Standard Test Method for Vapor Pressure of Liquefied Petroleum Gases (LPG) (Expansion Method)’. ASTM D5190, ‘Standard Test Method for Vapor Pressure of Petroleum Products (Automatic Method)’. ASTM D5191, ‘Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method)’. ASTM D5482, ‘Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method – Atmospheric)’. ASTM D323, ‘Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method)’. ASTM D6378, ‘Standard Test Method for Determination of Vapor Pressure (VPX) of Petroleum Products, Hydrocarbons, and Hydrocarbon-Oxygenate Mixtures (Triple Expansion Method)’. IP 394, ‘Vapor Pressure Tester’. IP 69, ‘Reid Vapor Pressure of Petroleum Products’. ISO 3007, ‘Determination Of Vapor Pressure – Reid Method’. DIN 51754, ‘Determination of Vapor Pressure; Reid Method’. JIS K 2258, ‘Determination of Vapor Pressure – Part 1: Reid Method’. AFNOR M07–079, ‘Vapor Pressure of Petroleum Products’. AFNOR M41–007, ‘Vapor Pressure – Reid Vapor Pressure of Petroleum Products’. ASTM D4683, ‘Standard Test Method for Measuring Viscosity of New and Used Engine Oils at High Shear Rate and High Temperature by Tapered Bearing Simulator Viscometer at 150 C’. ASTM D5481, ‘Standard Test Method for Measuring Apparent Viscosity at High Temperature and High Shear Rate by Multicell Capillary Viscometer’. ASTM D1092, ‘Standard Test Method for Measuring Apparent Viscosity of Lubricating Greases’. ASTM D4684, ‘Standard Test Method for Determination of Yield Stress and Apparent Viscosity of Engine Oils at Low Temperature’. ASTM D3236, ‘Standard Test Method for Apparent Viscosity of Hot Melt Adhesives and Coating Materials’. ASTM D2669, ‘Standard Test Method for Apparent Viscosity of Petroleum Waxes Compounded with Additives (Hot Melts)’.

778

• • • • • • • • • • • • • • • • • • • • • • • • • • •

CHAPTER 12 Measurements

ASTM D6896, ‘Standard Test Method for Determination of Yield Stress and Apparent Viscosity of Used Engine Oils at Low Temperature’. ASTM D2983, ‘Standard Test Method for Low Temperature Viscosity of Lubricants Measured by Brookfield Viscometer’. ASTM D5133, ‘Standard Test Method for Low Temperature, Low Shear Rate, Viscosity/ Temperature Dependence of Lubricating Oils Using a Temperature-Scanning Technique’. ASTM D7279, ‘Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids by Automated Houillon Viscometer’. ASTM D6616, ‘Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids by Automated Houillon Viscometer’. ASTM D2532, ‘Standard Test Method for Viscosity and Viscosity Change After Standing at Low Temperature of Aircraft Turbine Lubricants’. ASTM D445, ‘Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids (and Calculation of Dynamic Viscosity)’. ASTM D4486, ‘Standard Test Method for Kinematic Viscosity of Volatile and Reactive Liquids’. ASTM D88, ‘Standard Test Method for Saybolt Viscosity’. ASTM D6821, ‘Standard Test Method for Low Temperature Viscosity of Drive Line Lubricants in a Constant Shear Stress Viscometer’. ASTM D6895, ‘Standard Test Method for Rotational Viscosity of Heavy Duty Diesel Drain Oils at 100 C’. ASTM D2161, ‘Standard Practice for Conversion of Kinematic Viscosity to Saybolt Universal Viscosity or to Saybolt Furol Viscosity’. ASTM D5018, ‘Standard Test Method for Shear Viscosity of Coal Tar and Petroleum Pitches’. ASTM D7110, ‘Standard Test Method for Determining the Viscosity-Temperature Relationship of Used and Soot-Containing Engine Oils at Low Temperatures’. IP 267, ‘The Measurement of European Low Temperature Brookfield Viscosity’. IP 71-1, ‘Petroleum Products – Transparent and Opaque Liquids – Determination of Kinematic Viscosity and Calculation of Dynamic Viscosity’. ISO 9262, ‘The Measurement of European Low Temperature Brookfield Viscosity’. ISO 3104, ‘Transparent and Opaque Liquids – Determination of Kinematic Viscosity and Calculation of Dynamic Viscosity’. DIN 51562, ‘Determination of Kinematic Viscosity Using the Ubbelohde Microviscometer’. JIS K 2283, ‘Determination of Kinematic Viscosity and Calculation of Viscosity Index from Kinematic Viscosity’. AFNOR T42-011, ‘Brookfield Viscosity’. AFNOR T60-100, ‘Kinematic Viscosity’. ASTM D4928, ‘Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration’. ASTM D6304, ‘Standard Test Method for Determination of Water in Petroleum Products, Lubricating Oils, and Additives by Coulometric Karl Fischer Titration’. IP 386, ‘Water Content (Karl Fischer) in Crude Oil’. ISO 10337, ‘Determination of water – Coulometric Karl Fischer titration method’. ASTM D 4006, ‘Standard Test Method for Water in Crude Oil by Distillation’.

12.3 Measured properties

• • • • • • • • • • • • • • • • • • • • • • • • • • • • •

779

ASTM D95, ‘Standard Test Method for Water in Petroleum Products and Bituminous Materials by Distillation’. IP 358, ‘Water in Crude Oil by Distillation’. IP 74, ‘Water in Petroleum Products by Distillation’. ISO 3733, ‘Water by Distillation’. DIN 51582, ‘Water Content in Petroleum & Bitumen – Dean & Stark Distillation Method (Extended)’. JIS K 2275, ‘Moisture Test Method for Crude Oil and Petroleum Products’. AFNOR T60-113, ‘Determination of Water Content. Distillation Method’. ASTM 4377, ‘Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration’. IP 356, ‘Water in Crude Oil by Karl Fisher’. ASTM D6896, ‘Standard Test Method for Determination of Yield Stress and Apparent Viscosity of Used Engine Oils at Low Temperature’. ASTM D4176, ‘Standard Test Method for Free Water and Particulate Contamination in Distillate Fuels (Visual Inspection Procedures)’. ASTM D4860, ‘Standard Test Method for Free Water and Particulate Contamination in Middle Distillate Fuels (Clear and Bright Numerical Rating)’. ASTM D1094, ‘Standard Test Method for Water Reaction of Aviation Fuels’. ASTM D4049, ‘Standard Test Method for Determining the Resistance of Lubricating Grease to Water Spray’. IP 289, ‘Determination of Water Reaction of Aviation Fuels’. ISO 6250, ‘Determination of the Water Reaction of Aviation Fuels’. DIN 51415, ‘Test on the Behavior of Aviation Fuels in the Presence of Water’. AFNOR M07-050, ‘Water Reaction’. ASTM D1796, ‘Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge Method (Laboratory Procedure)’. ASTM D4007-11, ‘Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure)’. IP 75, ‘Water and Sediment in Fuel Oils by Centrifuge’. IP 359, ‘Water and Sediment in Crude Oil by Centrifuge Method’. ISO 3734, ‘Determination of Water and Sediment in Residual Fuel Oils – Centrifuge Method’. DIN 51793, ‘Precipitation Number of Lubricating Oils’. AFNOR M07–020, ‘Precipitation Number of Fuel Oils – Water and Sediments – Centrifuge Method’. ASTM D7261, ‘Standard Test Method for Determining Water Separation Characteristics of Diesel Fuels by Portable Separometer’. ASTM D3948, ‘Standard Test Method for Determining Water Separation Characteristics of Aviation Turbine Fuels by Portable Separometer’. ASTM D1401, ‘Standard Test Method for Water Separability of Petroleum Oils and Synthetic Fluids’. ASTM D7224, ‘Standard Test Method for Determining Water Separation Characteristics of Kerosine-Type Aviation Turbine Fuels Containing Additives by Portable Separometer’.

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• • • • • • • • • • • •

CHAPTER 12 Measurements

IP 412, ‘Petroleum Products – Determination of Water Separability of Petroleum Oils and Synthetic Fluids’. ISO 6614, ‘Determination of Water Separability of Petroleum Oils and Synthetic Fluids’. AFNOR T60-125, ‘Water Separability of Petroleum Oils and Synthetic Fluids – Half Automated’. ASTM D4056, ‘Standard Test Method for Estimation of Solubility of Water in Hydrocarbon and Aliphatic Ester Lubricants’. ASTM D1364, ‘Standard Test Method for Water in Volatile Solvents (Karl Fischer Reagent Titration Method)’. ASTM D3240, ‘Standard Test Method for Undissolved Water in Aviation Turbine Fuels’. ASTM D1264, ‘Standard Test Method for Determining the Water Washout Characteristics of Lubricating Greases’. API Publication 852-25650, ‘Ethylene Density’. API Publication 852-25640, ‘Guidelines for the Use of the International System of Units (SI) in the Petroleum and Allied Industries’. API Publication 852-30401, ‘Guidelines for Marine Cargo Inspection’. API Standard 2543, ‘Method of Measuring the Temperature of Petroleum and Petroleum Products’. ASTM G205, ‘Standard Guide for Determining the Corrosivity of Crude Oils’.

12.3.6 Physical properties of gas The physical properties of gases influence corrosion by influencing the flow. In determining the effect of gas, the critical aspect is to understand its compressibility. Section 12.3.4 discusses this. The standards providing guidelines for measuring the physical properties of gases include: • • •

Gas Processors Suppliers Association (GPSA), Engineering Data Book.11 ASTM D1070, ‘Standard Test Methods for Relative Density of Gaseous Fuels’. ASTM D3588, ‘Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels’.

12.3.7 Physical properties of water Similarly to the physical properties of oil, the physical properties of water are critical to corrosion. The physical properties normally measured include viscosity, density, and conductivity. The conductivity values may also be considered as a measure of total dissolved electrolytes or concentration of ionic species. The standards providing guidelines for measuring the physical properties of water include: • • • • •

ASTM D445, ‘Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids (and Calculation of Dynamic Viscosity)’. ASTM D5391, ‘Standard Test Method for Electrical Conductivity and Resistivity of a Flowing High Purity Water Sample’. ASTM D1125, ‘Standard Test Methods for Electrical Conductivity and Resistivity of Water’. ASTM D6504, ‘Standard Practice for Online Determination of Cation Conductivity in High Purity Water’. ASTM D4189, ‘Standard Test Method for Silt Density Index (SDI) of Water’.

12.3 Measured properties

781

12.3.8 Flow9 The volumes of liquid (oil and water) and gas are used to calculate the mass flow rate and the flow velocity using other physical parameters (pressure, temperature, density, and viscosity). However, velocity of multiphase flow is difficult to measure because the flow velocities of all phases are not the same, and further they are not often constant. Therefore, the influence of multiphase flow on corrosion is normally understood through the calculation of flow regimes. Although acoustic and radiography techniques have been used to measure certain flow regimes (e.g., slug flow), they are usually calculated from the physical properties of fluids (density, viscosity, and flow rate). Chapter 4 details methods for calculating flow velocity and flow regimes. The flow regime may indicate potential problem locations and the frequency at which these problems may occur. Standards providing guidelines for measuring flow include: • •

API RP 14E. ‘Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems’. NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’.

12.3.9 Pressure Most oil and gas industry infrastructure operates under pressure, therefore this is measured routinely, frequently, and at many locations. It is a simple measurement using standard equipment. Pressure does not directly affect the corrosion rate, but it does so indirectly by influencing the flow rate and flow regime. The methods used to measure pressure are too numerous to list exhaustively, so just a few are listed below: • • • • •

ASME B40.100, ‘Pressure Gauges and Gauge Attachments’. ASME Performance Test Code (PTC) 19.2, ‘Pressure Measurement’. ASTM F2070, ‘Standard Specification for Transducers, Pressure and Differential, Pressure, Electrical, and Fiber-Optic’. DIN-EN 472, ‘Pressure Gauge – Vocabulary’. EN 837, ‘Pressure Gauges’.

12.3.10 Temperature Similarly to pressure, temperature is measured at several locations in the infrastructure and numerous techniques are available to do this. The temperature is measured to control the process and flow. Remote thermography may sometimes be used to measure the temperature profile of hot surfaces (e.g., fluid catalytic cracking units), especially to understand the thermal insulation characteristics of refractive coatings. Another example where temperature is measured for the purpose of corrosion control is to establish the dew point. Wet corrosion takes place at temperatures below the dew point due to condensation of the liquid water phase. Standards providing procedures to measure temperature include: • • •

ASTM G 84, ‘Standard Practice for Measurement of Time-of-Wetness on Surfaces Exposed to Wetting Conditions as in Atmospheric Corrosion Testing’. API Publication 852-25430, ‘Method of measuring the temperature of petroleum and petroleum products’. NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’ (Thermography Technique).

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12.3.11 Chemical properties of oil10–13 Several chemicals present in the oil influence corrosion at higher temperatures. Therefore measurements of the chemical properties of oil are critically important for refinery operations. For production and transportation operations operating at lower temperatures, these chemical properties are not important; for them only light hydrocarbon analysis and water cut are the only relevant issues. The chemical properties of oil which influence corrosion include water content, sediment content, acid number (normally used as a measure of naphthenic acid content; the higher the value, the higher the corrosion tendency), acidity (the higher the acidity, the higher the corrosion rate), tendency to adhere onto solid (the higher the adhesion of oil, the lower the probability of corrosion), air release (an indirect measure of the ability of oil to retain corrosive gases; the higher the air release, the higher the potential for carrying corrosive gases), liquid petroleum gases and propane content (alters the relative density and vapor pressure, consequently affecting the flow characteristics), ash content (an increase in ash content increases the probability of corrosion and erosion), asphaltenes (higher asphaltene content normally decreases the corrosivity of oil), hydrogen peroxide content (provides an indication of the oxidizing constituents of crude oil), nitrogen content (presence of nitrogen in the crude oil inhibits the corrosion; higher nitrogen contents lessen the corrosivity of crude oil), trace metals (in general, the higher the metal content, the higher the probability of corrosion), and corrosivity. The standards providing guidelines for measuring chemical properties of oil include: • • • • • • • • • • • • • • • • •

ASTM D7038, ‘Standard Test Method for Determination of Sludging and Corrosion Tendencies of Inhibited Mineral Oils’. ASTM D4931, ‘Standard Test Method for Gross Moisture in Green Petroleum Coke’. ASTM D473, ‘Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method’. ASTM D4807, ‘Standard Test Method for Sediment in Crude Oil by Membrane Filtration’. ASTM D2273, ‘Standard Test Method for Trace Sediment in Lubricating Oils’. ASTM D4870, ‘Standard Test Method for Determination of Total Sediment in Residual Fuels’. ASTM D2709, ‘Standard Test Method for Water and Sediment in Middle Distillate Fuels by Centrifuge’. IP 53, ‘Sediment in Crude Oils and Fuel Oils by the Extraction Method’. IP 375, ‘Petroleum Products – Total Sediment in Residual Fuel Oils – Part 1: Determination by Hot Filtration’. ISO 3735, ‘Crude Petroleum and Fuel Oils – Determination of Sediment – Extraction Method’. ISO 10307, ‘Petroleum Products – Total Sediment in Residual Fuel Oils’. DIN 51789, ‘Sediment’. AFNOR M07-063, ‘Petroleum Products. Insoluble Content of Liquid Fuels’. ASTM D4310, ‘Standard Test Method for Determination of Sludging and Corrosion Tendencies of Inhibited Mineral Oils’. ASTM D3707, ‘Standard Test Method for Storage Stability of Water-in-Oil Emulsions by the Oven Test Method’. ASTM D3709, ‘Standard Test Method for Stability of Water-in-Oil Emulsions Under Low to Ambient Temperature Cycling Conditions’. API Publication 852-30201, ‘Determination of Sediment in Crude Oils and Fuel Oils by the Extraction Method’.

12.3 Measured properties

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • •

783

API Publication 852-30202, ‘Determination of Water in Crude Oil by the Distillation Method’. API Publication 852-30203, ‘Determination of Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure)’. ASTM D974, ‘Standard Test Method for Acid and Base Number by Color Indicator Titration’. IP 139, ‘Acid and Base Number by Color Indicator Titration’. ISO 6618, ‘Petroleum Products and Lubricants – Determination of Acid Or Base Number – Color Indicator Titration Method’. DIN 51558T1, ‘Testing of Mineral Oils; Determination of the Neutralization Number, Color indicator titration’. (NOTE this is from DIN 51558–1). JIS K2501, ‘Petroleum Products and Lublicants – Determination of Neutralization Number’. AFNOR T60-112, ‘Acid Number by Color Indicator Titration’. ASTM D664- 11a, ‘Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration’. IP177, ‘Total Acid Number’. ISO 6619, ‘Petroleum Products and Lubricants – Neutralization Number – Potentiometric Titration Method’. JIS K2501, ‘Petroleum Products and Lublicants – Determination of Neutralization Number’. ASTM D3339, ‘Standard Test Method for Acid Number of Petroleum Products by Semi-Micro Color Indicator Titration’. IP 431, ‘Petroleum Products – Determination of Acid Number – Semi-Micro Color Indicator Titration Method’. ISO 7537, ‘Petroleum Products – Determination of Acid Number – Semi-Micro Color Indicator Titration Method’. ASTM D5770, ‘Standard Test Method for Semiquantitative Micro Determination of Acid Number of Lubricating Oils During Oxidation Testing’. ASTM D3242, ‘Standard Test Method for Acidity in Aviation Turbine Fuel’. IP 354, ‘Total Acidity of Aviation Turbine Fuel – Color Indicator Titration Method’. DIN D51558 T3, Acidity of aviation turbine fuel (ATF)’. ASTM D1093, ‘Standard Test Method for Acidity of Hydrocarbon Liquids and Their Distillation Residues’. ASTM D2510, ‘Standard Test Method for Adhesion of Solid Film Lubricants’. ASTM D3427, ‘Standard Test Method for Air Release Properties of Petroleum Oils’. IP 313, ‘Determination of Air Release Value of Hydraulic, Turbine and Lubricating Oils’. ISO 9120, ‘Petroleum and Related Products – Determination of Air Release Properties of Steam Turbine and Other Oils – Impinger Method’. AFNOR E48–614, ‘Air Release Properties of Oils Impinger Method’. ASTM D2163, ‘Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography’. ASTM D2415, ‘Standard Test Method for Ash in Coal Tar and Pitch’. ASTM D4422, ‘Standard Test Method for Ash in Analysis of Petroleum Coke’. ASTM D482, ‘Standard Test Method for Ash from Petroleum Products’. IP 4, ‘Determination of Ash’. ISO 6245, ‘Petroleum Products – Determination of Ash’. JIS K 2272, ‘Crude Oil and Petroleum Products – Determination of Ash and Sulfated Ash’.

784

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CHAPTER 12 Measurements

AFNOR M07–045, ‘Ash from Petroleum Products’. ASTM D874, ‘Standard Test Method for Sulfated Ash from Lubricating Oils and Additives’. IP 163, ‘Sulfated Ash’. ISO 3987, ‘Petroleum products – Lubricating oils and additives – Determination of sulfated ash – Corrigendum’. DIN 51575, ‘Testing of mineral oils - Determination of sulfated ash’. AFNOR T60-143, ‘Ash from Lubricating Oils’. ASTM D6560, ‘Standard Test Method for Determination of Asphaltenes (Heptane Insolubles) in Crude Petroleum and Petroleum Products’. ASTM D808, ‘Standard Test Method for Chlorine in New and Used Petroleum Products (High Pressure Decomposition Device Method)’. ASTM D5384, ‘Standard Test Methods for Chlorine in Used Petroleum Products (Field Test Kit Method)’. ASTM D4929, ‘Standard Test Methods for Determination of Organic Chloride Content in Crude Oil’. ASTM D2420, ‘Standard Test Method for Hydrogen Sulfide in LP Gases (Lead Acetate Method)’. IP 401, ‘Liquefied Petroleum Gases – Detection of Hydrogen Sulfide – Lead Acetate Method’. ISO 8819, ‘Liquefied Petroleum Gases – Detection of Hydrogen Sulfide – Lead Acetate Method’. DIN 51855 T3, ‘Testing of Gaseous Fuels and Other Gases – Determination of the Content of Sulfur Compounds’. AFNOR M41-11, ‘H2S in LPG’. ASTM D6021, ‘Standard Test Method for Measurement of Total Hydrogen Sulfide in Residual Fuels by Multiple Headspace Extraction and Sulfur Specific Detection’. ASTM D5705, ‘Standard Test Method for Measurement of Hydrogen Sulfide in the Vapor Phase above Residual Fuel Oils’. ASTM D6447, ‘Standard Test Method for Hydroperoxide Number of Aviation Turbine Fuels by Voltammetric Analysis’. ASTM D4627, ‘Standard Test Method for Iron Chip Corrosion for Water-Dilutable Metalworking Fluids’. ASTM D3831, ‘Standard Test Method for Manganese in Gasoline By Atomic Absorption Spectroscopy’. ASTM D3227, ‘Standard Test Method for (Thiol Mercaptan) Sulfur in Gasoline, Kerosine, Aviation Turbine, and Distillate Fuels (Potentiometric Method)’. IP 342, ‘Determination of Thiol (Mercaptan) Sulfur in Light and Middle Distillate Fuels -Potentiometric Method’. ISO 3012, ‘Petroleum Products – Determination of Thiol (Mercaptan) Sulfur in Light and Middle Distillate Fuels – Potentiometric Method’. JIS K 2276, ‘Petroleum Products – Testing Methods for Aviation Fuels’. AFNOR M07-022, ‘Determination of Mercaptan Sulfur in Volatile Fuels and Distillates’. ASTM D3605, ‘Standard Test Method for Trace Metals in Gas Turbine Fuels by Atomic Absorption and Flame Emission Spectroscopy’. ASTM D4628, ‘Standard Test Method for Analysis of Barium, Calcium, Magnesium, and Zinc in Unused Lubricating Oils by Atomic Absorption Spectrometry’.

12.3 Measured properties

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785

IP 413, ‘Petroleum Products – Low Levels of Vanadium in Liquid Fuels – Determination by Flameless Atomic Absorption Spectrometry After Ashing’. IP 308, ‘Determination of Barium, Calcium, Magnesium and Zinc in Unused Lubricating Oils – Atomic Absorption Method’. ISO 8691, ‘Petroleum Products – Low Levels of Vanadium in Liquid Fuels – Determination by Flameless Atomic Absorption Spectrometry After Ashing’. DIN 51790 T3, ‘Metals by Atomic Absorption (AAS)’. DIN 51391 T1, ‘Testing of Lubricants – Determination of the Content of Additive Elements’. ASTM D5184, ‘Standard Test Methods for Determination of Aluminum and Silicon in Fuel Oils by Ashing, Fusion, Inductively Coupled Plasma Atomic Emission Spectrometry, and Atomic Absorption Spectrometry’. ASTM D5863, ‘Standard Test Methods for Determination of Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry’. ASTM D5056, ‘Standard Test Method for Trace Metals in Petroleum Coke by Atomic Absorption’. IP 377, ‘Petroleum Products – Determination of Aluminum and Silicon in Fuel Oils – Inductively Coupled Plasma Emission and Atomic Absorption Spectroscopy Method’. ISO 10478, ‘Petroleum Products – Determination of Aluminum and Silicon in Fuel Oils – Inductively Coupled Plasma Emission and Atomic Absorption Spectroscopy Methods’. DIN 51416, ‘Aluminum and Silicon in Fuels’. ASTM D7111, ‘Standard Test Method for Determination of Trace Elements in Middle Distillate Fuels by Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES)’. ASTM D4951, ‘Standard Test Method for Determination of Additive Elements in Lubricating Oils by Inductively Coupled Plasma Atomic Emission Spectrometry’. ASTM D5185, ‘Standard Test Method for Determination of Additive Elements, Wear Metals, and Contaminants in Used Lubricating Oils and Determination of Selected Elements in Base Oils by Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES)’. ASTM D7303, ‘Standard Test Method for Determination of Metals in Lubricating Greases by Inductively Coupled Plasma Atomic Emission Spectrometry’. ASTM D5708, ‘Standard Test Methods for Determination of Nickel, Vanadium, and Iron in Crude Oils and Residual Fuels by Inductively Coupled Plasma (ICP) Atomic Emission Spectrometry’. ASTM D7040, ‘Standard Test Method for Determination of Low Levels of Phosphorus in ILSAC GF 4 and Similar Grade Engine Oils by Inductively Coupled Plasma Atomic Emission Spectrometry’. ASTM D5600, ‘Standard Test Method for Trace Metals in Petroleum Coke by Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES)’. ASTM D6376, ‘Standard Test Method for Determination of Trace Metals in Petroleum Coke by Wavelength Dispersive X-Ray Fluorescence Spectroscopy’. ASTM D6443, ‘Test Method for Determination of Calcium, Chlorine, Copper, Magnesium, Phosphorus, Sulfur, and Zinc in Unused Lubricating Oils and Additives by Wavelength Dispersive X-ray Fluorescence Spectrometry (Mathematical Correction Procedure)’. ASTM D6481, ‘Standard Test Method for Determination of Phosphorus, Sulfur, Calcium, and Zinc in Lubrication Oils by Energy Dispersive X-ray Fluorescence Spectroscopy’.

786

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•

• • • • • • •

• • • • • • • • • • • • • • • •

CHAPTER 12 Measurements

ASTM D6595, ‘Standard Test Method for Determination of Wear Metals and Contaminants in Used Lubricating Oils or Used Hydraulic Fluids by Rotating Disc Electrode Atomic Emission Spectrometer’. ASTM D4927, ‘Standard Test Methods for Elemental Analysis of Lubricant and Additive Components – Barium, Calcium, Phosphorus, Sulfur, and Zinc by Wavelength Dispersive X-Ray Fluorescence Spectroscopy’. IP 407, ‘Barium, Calcium, Phosphorous, Sulfur and Zinc Wavelength Dispersive X-ray’. DIN 51391 T2, ‘Testing of Lubricants; Determination of the Content of Additive Elements; Analysis by Wavelength Dispersive X-Ray Spectrometry (XRS)’. ASTM D3230, ‘Standard Test Method for Salts in Crude Oil (Electrometric Method)’. ASTM D6470, ‘Standard Test Method for Salt in Crude Oils (Potentiometric Method)’. ASTM D7318, ‘Standard Test Method for Existent Inorganic Sulfate in Ethanol by Potentiometric Titration’. ASTM D7319, ‘Standard Test Method for Determination of Existent and Potential Sulfate and Inorganic Chloride in Fuel Ethanol by Direct Injection Suppressed Ion Chromatography’. ASTM D7328, ‘Standard Test Method for Determination of Existent and Potential Inorganic Sulfate and Total Inorganic Chloride in Fuel Ethanol by Ion Chromatography Using Aqueous Sample Injection’. ASTM D1662-08 ‘Standard Test Method for Active Sulfur in Cutting Oils’. ASTM D4952, ‘Standard Test Method for Qualitative Analysis for Active Sulfur Species in Fuels and Solvents (Doctor Test)’. IP 30, ‘Detection of Mercaptans, Hydrogen Sulfide, Elemental Sulfur and Peroxides - Doctor Test Method’. ISO 5275, ‘Petroleum Products and Hydrocarbon Solvents – Detection of Thiols and Other Sulfur Species – Doctor Test’. ASTM D129, ‘Standard Test Method for Sulfur in Petroleum Products (General High Pressure Decomposition Device Method)’. ASTM D1266, ‘Standard Test Method for Sulfur in Petroleum Products (Lamp Method)’. IP 61, ‘Determination of Sulfur – High Pressure Combustion Method’. IP 107, ‘Determination of Sulfur – Lamp Combustion Method’. DIN 51577, ‘Sulfur, Bomb method’. AFNOR T60–109, ‘Oxidation Characteristics of Inhibited Mineral Oils’. AFNOR M07–031, ‘Liquid Fuels – Determination of Sulfur in Liquid Petroleum Products - Lamp Method’. ASTM D1552, ‘Standard Test Method for Sulfur in Petroleum Products (High Temperature Method)’. AFNOR M07–025, ‘Combustible liquids. Determination of sulfur content. High temperature combustion’. ASTM D4045, ‘Standard Test Method for Sulfur in Petroleum Products by Hydrogenolysis and Rateometric Colorimetry’. ASTM D2784, ‘Standard Test Method for Sulfur in Liquefied Petroleum Gases (Oxy-Hydrogen Burner or Lamp)’. ASTM D7039, ‘Standard Test Method for Sulfur in Gasoline and Diesel Fuel by Monochromatic Wavelength Dispersive X-Ray Fluorescence Spectrometry’.

12.3 Measured properties

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787

ASTM D7220, ‘Standard Test Method for Sulfur in Automotive, Heating, and Jet Fuels by Monochromatic Energy Dispersive X-ray Fluorescence Spectrometry’. ASTM D6334, ‘Standard Test Method for Sulfur in Gasoline by Wavelength Dispersive X-Ray Fluorescence’. ASTM D7041, ‘Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels, and Oils by Online Gas Chromatography with Flame Photometric Detection’. ASTM D5623, ‘Standard Test Method for Sulfur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulfur Selective Detection’. ASTM D6920, ‘Standard Test Method for Total Sulfur in Naphthas, Distillates, Reformulated Gasolines, Diesels, Biodiesels, and Motor Fuels by Oxidative Combustion and Electrochemical Detection’. ASTM D7212, ‘Standard Test Method for Low Sulfur in Automotive Fuels by Energy Dispersive X-ray Fluorescence Spectrometry Using a Low-Background Proportional Counter’. ASTM D5453, ‘Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence’. ASTM D6667, ‘Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence’. ASTM D2622, ‘Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry’. ASTM D4294, ‘Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy Dispersive X-Ray Fluorescence Spectrometry’. IP 336, ‘Petroleum Products – Determination of Sulfur Content – Energy Dispersive X-Ray Fluorescence Method (ISO 8754: 1992)’. ISO 8754, ‘Petroleum Products – Determination of Sulfur Content – Energy Dispersive X-Ray Fluorescence Spectrometry’. DIN 51400 T6, ‘Testing of Mineral Oils and Fuels – Determination of Sulfur Content (Total Sulfur)’. JIS K 2541, ‘Crude Oil and Petroleum Products – Determination of Sulfur Content’. AFNOR M07-053, ‘Sulfur Determination by Energy Dispersive X-Ray Fluorescence’. ASTM D3120, ‘Standard Test Method for Trace Quantities of Sulfur in Light Liquid Petroleum Hydrocarbons by Oxidative Microcoulometry’. ASTM D3246, ‘Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry’. AFNOR M07-027, ‘Sulfur by High Temperature’. ASTM D3228, ‘Standard Test Method for Total Nitrogen in Lubricating Oils and Fuel Oils by Modified Kjeldahl Method’. ASTM D130, ‘Standard Test Method for Corrosiveness to Copper from Petroleum Products by Copper Strip Test’. ASTM D849, ‘Standard Test Method for Copper Strip Corrosion by Industrial Aromatic Hydrocarbons’. ASTM D1838, ‘Standard Test Method for Copper Strip Corrosion by LP Gases’. ASTM D4048, ‘Standard Test Method for Detection of Copper Corrosion from Lubricating Grease’.

788

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CHAPTER 12 Measurements

ASTM D7095, ‘Standard Test Method for Rapid Determination of Corrosiveness to Copper from Petroleum Products Using a Disposable Copper Foil Strip’. ASTM D2649, ‘Standard Test Method for Corrosion Characteristics of Solid Film Lubricants’. ASTM D6594, ‘Standard Test Method for Evaluation of Corrosiveness of Diesel Engine Oil at 135 C’. ASTM D4636, ‘Standard Test Method for Corrosiveness and Oxidation Stability of Hydraulic Oils, Aircraft Turbine Engine Lubricants, and Other Highly Refined Oils’. ASTM D6547, ‘Standard Test Method for Corrosiveness of Lubricating Fluid to Bimetallic Couple’. ASTM D1743, ‘Standard Test Method for Determining Corrosion Preventive Properties of Lubricating Greases’. ASTM D5969, ‘Standard Test Method for Corrosion Preventive Properties of Lubricating Greases in Presence of Dilute Synthetic Sea Water Environments’. ASTM D6138, ‘Standard Test Method for Determination of Corrosion Preventive Properties of Lubricating Greases Under Dynamic Wet Conditions (Emcor Test)’. ASTM D6557, ‘Standard Test Method for Evaluation of Rust Preventive Characteristics of Automotive Engine Oils’. ASTM D665, ‘Standard Test Method for Rust-Preventing Characteristics of Inhibited Mineral Oil in the Presence of Water’. ASTM D3603, ‘Standard Test Method for Rust-Preventing Characteristics of Steam Turbine Oil in the Presence of Water (Horizontal Disk Method)’. IP 135, ‘Rust-Preventing Characteristics of Inhibited Mineral Oil in the Presence of Water’. ISO 7120, ‘Petroleum Products and Lubricants – Petroleum Oils and Other Fluids – Determination of Rust-Preventing Characteristics in the Presence of Water’. DIN 51585, ‘Rust’. JIS K 2510, ‘Lubricants – Determination of Rust-Preventing Characteristics’. AFNOR T60-151, ‘Assessment of Rust-Preventing Characteristics of Turbine Oil in the Presence of Water’. ASTM D6973, ‘Standard Test Method for Indicating Wear Characteristics of Petroleum Hydraulic Fluids in a High Pressure Constant Volume Vane Pump’. ASTM D7043, ‘Standard Test Method for Indicating Wear Characteristics of Petroleum and NonPetroleum Hydraulic Fluids in a Constant Volume Vane Pump’. ASTM D4172, ‘Standard Test Method for Wear Preventive Characteristics of Lubricating Fluid (Four Ball Method)’. ASTM D3704, ‘Standard Test Method for Wear Preventive Properties of Lubricating Greases Using the (Falex) Block on Ring Test Machine in Oscillating Motion’. ASTM D2266, ‘Standard Test Method for Wear Preventive Characteristics of Lubricating Grease (Four Ball Method)’. ASTM D2981, ‘Standard Test Method for Wear Life of Solid Film Lubricants in Oscillating Motion’. ASTM D4998, ‘Standard Test Method for Evaluating Wear Characteristics of Tractor Hydraulic Fluids’. IP 239, ‘Determination of Extreme Pressure and Antiwear Properties of Lubricants – Four Ball Machine Method’.

12.3 Measured properties

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789

ISO 11008, ‘Four Ball Method’. DIN 51350, ‘Testing Of Lubricants – Testing in the Four Ball Tester’.

12.3.12 Chemical properties of gas The gaseous phase is not corrosive, but when gases such as CO2, H2S, and O2 dissolve in the liquid water phase, they influence the corrosivity of the aqueous phase. The concentration of gas in the solution is directly proportional to its partial pressure in the gas phase (Henry’s law). For this reason the measurement of gases in the gas phase is useful. Standards providing guidelines for measuring gas compositions include: • • •

ASTM D1945, ‘Standard Test Method for Analysis of Natural Gas by Gas Chromatography’. ASTM F307, ‘Standard Practice for Sampling Pressurized Gas for Gas Analysis’. NACE 3T199, ‘Techniques for Monitoring Corrosion and Related Parameters in Field Applications’.

12.3.13 Chemical properties of water14–16 Inorganic constituents, organic acids, and dissolved gases do not directly influence corrosion until and unless they dissolve in the aqueous phase. Thus, the chemical composition of water is the primary factor in determining the corrosion tendency. The properties influencing the corrosivity of water include anions, cations, pH,17 inorganic substances, organic substances, dissolved gases (e.g., oxygen), dissolved solids, turbidity (a measure of suspended solids) and deposits. Standards providing guidelines for measuring chemical composition of water include: • • • • • • • • • • • • • • • • • •

ASTM D1293, ‘Standard Test Methods for pH of Water’. ASTM D5464, ‘Standard Test Method for pH Measurement of Water of Low Conductivity’. ASTM E70, ‘Standard Test Method for pH of Aqueous Solutions with the Glass Electrode’. ASTM D5128, ‘Standard Test Method for On-Line pH Measurement of Water of Low Conductivity’. ASTM D6764, ‘Standard Guide for Collection of Water Temperature, Dissolved-Oxygen Concentrations, Specific Electrical Conductance, and pH Data from Open Channels’. ASTM D6569, ‘Standard Test Method for On-Line Measurement of pH’. ASTM D6423, ‘Standard Test Method for Determination of pHe of Ethanol, Denatured Fuel Ethanol, and Fuel Ethanol’. ASTM D511, ‘Standard Test Methods for Calcium and Magnesium in Water’. ASTM D512, ‘Standard Test Methods for Chloride Ion in Water’. ASTM D513, ‘Standard Test Methods for Total and Dissolved Carbon Dioxide in Water’. ASTM D516, ‘Standard Test Method for Sulfate Ion in Water’. ASTM D4130, ‘Standard Test Method for Sulfate Ion in Brackish Water, Seawater, and Brines’. ASTM D857, ‘Standard Test Method for Aluminum in Water’. ASTM D858, ‘Standard Test Methods for Manganese in Water’. ASTM D859, ‘Standard Test Method for Silica in Water’. ASTM D888, ‘Standard Test Methods for Dissolved Oxygen in Water’. ASTM D1067, ‘Standard Test Methods for Acidity or Alkalinity of Water’. ASTM D1068, ‘Standard Test Methods for Iron in Water’.

790

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CHAPTER 12 Measurements

ASTM D1126, ‘Standard Test Method for Hardness in Water’. ASTM D1179, ‘Standard Test Methods for Fluoride Ion in Water’. ASTM D1246, ‘Standard Test Method for Bromide Ion in Water’. ASTM D1253, ‘Standard Test Method for Residual Chlorine in Water’. ASTM D1292, ‘Standard Test Method for Odor in Water’. ASTM D1426, ‘Standard Test Methods for Ammonia Nitrogen in Water’. ASTM D1429, ‘Standard Test Methods for Specific Gravity of Water and Brine’. ASTM D1687, ‘Standard Test Methods for Chromium in Water’. ASTM D1688, ‘Standard Test Methods for Copper in Water’. ASTM D1691, ‘Standard Test Methods for Zinc in Water’. ASTM D1886, ‘Standard Test Methods for Nickel in Water’. ASTM D1971, ‘Standard Practices for Digestion of Water Samples for Determination of Metals by Flame Atomic Absorption, Graphite Furnace Atomic Absorption, Plasma Emission Spectroscopy, or Plasma Mass Spectrometer’. ASTM D1976, ‘Standard Test Method for Elements in Water by Inductively Coupled Argon Plasma Atomic Emission Spectroscopy’. ASTM D2972, ‘Standard Test Methods for Arsenic in Water’. ASTM D3082, ‘Standard Test Method for Boron in Water’. ASTM D3223, ‘Standard Test Method for Total Mercury in Water’. ASTM D3352, ‘Standard Test Method for Strontium Ion in Brackish Water, Seawater, and Brines’. ASTM D3920, ‘Standard Test Method for Strontium in Water’. ASTM D3372, ‘Standard Test Method for Molybdenum in Water’. ASTM D3373, ‘Standard Test Method for Vanadium in Water’. ASTM D3557, ‘Standard Test Methods for Cadmium in Water’. ASTM D3558, ‘Standard Test Methods for Cobalt in Water’. ASTM D3559, ‘Standard Test Methods for Lead in Water’. ASTM D3561, ‘Standard Test Method for Lithium, Potassium, and Sodium Ions in Brackish Water, Seawater, and Brines by Atomic Absorption Spectrophotometry’. ASTM D3590, ‘Standard Test Methods for Total Kjeldahl Nitrogen in Water’. ASTM D3645, ‘Standard Test Methods for Beryllium in Water’. ASTM D3651, ‘Standard Test Method for Barium in Brackish Water, Seawater, and Brines’. ASTM D3986, ‘Standard Test Method for Barium in Brines, Seawater, and Brackish Water by Direct-Current Argon Plasma Atomic Emission Spectroscopy’. ASTM D3697, ‘Standard Test Method for Antimony in Water’. ASTM D3859, ‘Standard Test Methods for Selenium in Water’. ASTM D3866, ‘Standard Test Methods for Silver in Water’. ASTM D3867, ‘Standard Test Methods for Nitrite-Nitrate in Water’. ASTM D3868, ‘Standard Test Method for Fluoride Ions in Brackish Water, Seawater, and Brines’. ASTM D3869, ‘Standard Test Methods for Iodide and Bromide Ions in Brackish Water, Seawater, and Brines’. ASTM D3875, ‘Standard Test Method for Alkalinity in Brackish Water, Seawater, and Brines’. ASTM D3919, ‘Standard Practice for Measuring Trace Elements in Water by Graphite Furnace Atomic Absorption Spectrophotometry’.

12.3 Measured properties

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ASTM D4190, ‘Standard Test Method for Elements in Water by Direct-Current Argon Plasma Atomic Emission Spectroscopy’. ASTM D4191, ‘Standard Test Method for Sodium in Water by Atomic Absorption Spectrophotometry’. ASTM D4192, ‘Standard Test Method for Potassium in Water by Atomic Absorption Spectrophotometry’. ASTM D4309, ‘Standard Practice for Sample Digestion Using Closed Vessel Microwave Heating Technique for the Determination of Total Metals in Water’. ASTM D4327, ‘Standard Test Method for Anions in Water by Chemically Suppressed Ion Chromatography’. ASTM D4328, ‘Standard Practice for Calculation of Supersaturation of Barium Sulfate, Strontium Sulfate, and Calcium Sulfate Dihydrate (Gypsum) in Brackish Water, Seawater, and Brines’. ASTM D4382, ‘Standard Test Method for Barium in Water, Atomic Absorption Spectrophotometry, Graphite Furnace’. ASTM D4458, ‘Standard Test Method for Chloride Ions in Brackish Water, Seawater, and Brines’. ASTM D4638, ‘Standard Guide for Preparation of Biological Samples for Inorganic Chemical Analysis’. ASTM D4658, ‘Standard Test Method for Sulfide Ion in Water’. ASTM D4691, ‘Standard Practice for Measuring Elements in Water by Flame Atomic Absorption Spectrophotometry’. ASTM D5257, ‘Standard Test Method for Dissolved Hexavalent Chromium in Water by Ion Chromatography’. ASTM D5463, ‘Standard Guide for Use of Test Kits to Measure Inorganic Constituents in Water’. ASTM D5673, ‘Standard Test Method for Elements in Water by Inductively Coupled Plasma Mass Spectrometry’. ASTM D5907, ‘Standard Test Methods for Filterable Matter (Total Dissolved Solids) and Nonfilterable Matter (Total Suspended Solids) in Water’. ASTM D6501, ‘Standard Test Method for Phosphonate in Brines’. ASTM D6508, ‘Standard Test Method for Determination of Dissolved Inorganic Anions in Aqueous Matrices Using Capillary Ion Electrophoresis and Chromate Electrolyte’. ASTM D6581, ‘Standard Test Methods for Bromate, Bromide, Chlorate, and Chlorite in Drinking Water by Suppressed Ion Chromatography’. ASTM D6800, ‘Standard Practice for Preparation of Water Samples Using Reductive Precipitation Preconcentration Technique for ICP-MS Analysis of Trace Metals’. ASTM D6850, ‘Standard Guide for Quality Control of Screening Methods in Water’. ASTM D6919, ‘Standard Test Method for Determination of Dissolved Alkali and Alkaline Earth Cations and Ammonium in Water and Wastewater by Ion Chromatography’. ASTM D6994, ‘Standard Test Method for Determination of Metal Cyanide Complexes in Wastewater, Surface Water, Groundwater and Drinking Water Using Anion Exchange Chromatography with Ultra Violet Detection’. ASTM D4189, ‘Standard Test Method for Silt Density Index (SDI) of Water’. ASTM D1252, ‘Standard Test Methods for Chemical Oxygen Demand (Dichromate Oxygen Demand) of Water’.

792

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CHAPTER 12 Measurements

ASTM D1783, ‘Standard Test Methods for Phenolic Compounds in Water’. ASTM D2036, ‘Standard Test Methods for Cyanides in Water’. ASTM D6696, ‘Standard Guide for Understanding Cyanide Species’. ASTM D2580, ‘Standard Test Method for Phenols in Water by Gas-Liquid Chromatography’. ASTM D2908, ‘Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous Injection Gas Chromatography’. ASTM D3325, ‘Standard Practice for Preservation of Waterborne Oil Samples’. ASTM D3326, ‘Standard Practice for Preparation of Samples for Identification of Waterborne Oils’. ASTM D3415, ‘Standard Practice for Identification of Waterborne Oils’. ASTM D4489, ‘Standard Practices for Sampling of Waterborne Oils’. ASTM D3328, ‘Standard Test Methods for Comparison of Waterborne Petroleum Oils by Gas Chromatography’. ASTM D3414, ‘Standard Test Method for Comparison of Waterborne Petroleum Oils by Infrared Spectroscopy’. ASTM D3650, ‘Standard Test Method for Comparison of Waterborne Petroleum Oils By Fluorescence Analysis’. ASTM D3695, ‘Standard Test Method for Volatile Alcohols in Water by Direct Aqueous Injection Gas Chromatography’. ASTM D3871, ‘Standard Test Method for Purgeable Organic Compounds in Water Using Headspace Sampling’. ASTM D3921, ‘Standard Test Method for Oil and Grease and Petroleum Hydrocarbons in Water’. ASTM D3973, ‘Standard Test Method for Low-Molecular Weight Halogenated Hydrocarbons in Water’. ASTM D4128, ‘Standard Guide for Identification and Quantitation of Organic Compounds in Water by Combined Gas Chromatography and Electron Impact Mass Spectrometry’. ASTM D4129, ‘Standard Test Method for Total and Organic Carbon in Water by High Temperature Oxidation and by Coulometric Detection’. ASTM D4165, ‘Standard Test Method for Cyanogen Chloride in Water’. ASTM D4193, ‘Standard Test Method for Thiocyanate in Water’. ASTM D4282, ‘Standard Test Method for Determination of Free Cyanide in Water and Wastewater by Microdiffusion’. ASTM D4374, ‘Standard Test Methods for Cyanides in Water-Automated Methods for Total Cyanide, Weak Acid Dissociable Cyanide, and Thiocyanate’. ASTM D4763, ‘Standard Practice for Identification of Chemicals in Water by Fluorescence Spectroscopy’. ASTM D4839, ‘Standard Test Method for Total Carbon and Organic Carbon in Water by Ultraviolet, or Persulfate Oxidation, or Both, and Infrared Detection’. ASTM D5175, ‘Standard Test Method for Organohalide Pesticides and Polychlorinated Biphenyls in Water by Microextraction and Gas Chromatography’. ASTM D5176, ‘Standard Test Method for Total Chemically Bound Nitrogen in Water by Pyrolysis and Chemiluminescence Detection’. ASTM D5241, ‘Standard Practice for Micro Extraction of Water for Analysis of Volatile and Semi-Volatile Organic Compounds in Water’.

12.3 Measured properties

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•

793

ASTM D5315, ‘Standard Test Method for Determination of N-Methyl-Carbamoyloximes and N-Methylcarbamates in Water by Direct Aqueous Injection High Performance Liquid Chromatography (HPLC) with Post-Column Derivatization’. ASTM D5316, ‘Standard Test Method for 1,2-Dibromoethane and 1,2-Dibromo3-Chloropropane in Water by Microextraction and Gas Chromatography’. ASTM D5317, ‘Standard Test Method for Determination of Chlorinated Organic Acid Compounds in Water by Gas Chromatography with an Electron Capture Detector’. ASTM D5412, ‘Standard Test Method for Quantification of Complex Polycyclic Aromatic Hydrocarbon Mixtures or Petroleum Oils in Water’. ASTM D5739, ‘Standard Practice for Oil Spill Source Identification by Gas Chromatography and Positive Ion Electron Impact Low Resolution Mass Spectrometry’. ASTM D5788, ‘Standard Guide for Spiking Organics into Aqueous Samples’. ASTM D5790, ‘Standard Test Method for Measurement of Purgeable Organic Compounds in Water by Capillary Column Gas Chromatography/Mass Spectrometry’. ASTM D6520, ‘Standard Practice for the Solid Phase Micro Extraction (SPME) of Water and its Headspace for the Analysis of Volatile and Semi-Volatile Organic Compounds’. ASTM D5904, ‘Standard Test Method for Total Carbon, Inorganic Carbon, and Organic Carbon in Water by Ultraviolet, Persulfate Oxidation, and Membrane Conductivity Detection’. ASTM D6238, ‘Standard Test Method for Total Oxygen Demand in Water’. ASTM D6888, ‘Standard Test Method for Available Cyanide with Ligand Displacement and Flow Injection Analysis (FIA) Utilizing Gas Diffusion Separation and Amperometric Detection’. ASTM D7237, ‘Standard Test Method for Free Cyanide with FIA Utilizing Gas Diffusion Separation and Amperometric Detection’. ASTM D7284, ‘Standard Test Method for Total Cyanide in Water by Micro Distillation followed by Flow Injection Analysis with Gas Diffusion Separation and Amperometric Detection’. ASTM D7365, ‘Standard Practice for Sampling, Preservation and Mitigating Interferences in Water Samples for Analysis of Cyanide’. ASTM D7511, ‘Standard Test Method for Total Cyanide by Segmented Flow Injection Analysis, In-Line Ultraviolet Digestion and Amperometric Detection’. ASTM D6889, ‘Standard Practice for Fast Screening for Volatile Organic Compounds in Water Using Solid Phase Microextraction (SPME)’. ASTM D7065, ‘Standard Test Method for Determination of Nonylphenol, Bisphenol A, p-tertOctylphenol, Nonylphenol Monoethoxylate and Nonylphenol Diethoxylate in Environmental Waters by Gas Chromatography Mass Spectrometry’. ASTM D7066, ‘Standard Test Method for dimer/trimer of chlorotrifluoroethylene (S-316) Recoverable Oil and Grease and Nonpolar Material by Infrared Determination’. ASTM D7363, ‘Standard Test Method for Determination of Parent and Alkyl Polycyclic Aromatics in Sediment Pore Water Using Solid Phase Microextraction and Gas Chromatography/ Mass Spectrometry in Selected Ion Monitoring Mode’. ASTM D7485, ‘Standard Test Method for Determination of Nonylphenol, p-tert-Octylphenol, Nonylphenol Monoethoxylate and Nonylphenol Diethoxylate in Environmental Waters by Liquid Chromatography/Tandem Mass Spectrometry’. ASTM D7573, ‘Standard Test Method for Total Carbon and Organic Carbon in Water by High Temperature Catalytic Combustion and Infrared Detection’.

794

• • •

• •

• •

•

• • •

• • • •

CHAPTER 12 Measurements

ASTM D7574, ‘Standard Test Method for Determination of Bisphenol A in Environmental Waters by Liquid Chromatography/Tandem Mass Spectrometry’. ASTM D7575, ‘Standard Test Method for Solvent-Free Membrane Recoverable Oil and Grease by Infrared Determination’. ASTM D7597, ‘Standard Test Method for Determination of Diisopropyl Methylphosphonate, Ethyl Hydrogen Dimethylamidophosphate, Ethyl Methylphosphonic Acid, Isopropyl Methylphosphonic Acid, Methylphosphonic Acid and Pinacolyl Methylphosphonic Acid in Water by Liquid Chro’. ASTM D7598, ‘Standard Test Method for Determination of Thiodiglycol in Water by Single Reaction Monitoring Liquid Chromatography/Tandem Mass Spectrometry’. ASTM D7599, ‘Standard Test Method for Determination of Diethanolamine, Triethanolamine, N-Methyldiethanolamine and N-Ethyldiethanolamine in Water by Single Reaction Monitoring Liquid Chromatography/Tandem Mass Spectroscopy’. ASTM D7600, ‘Standard Test Method for Determination of Aldicarb, Carbofuran, Oxamyl and Methomyl by Liquid Chromatography/Tandem Mass Spectrometry’. ASTM D7644, ‘Standard Test Method for Determination of Bromadiolone, Brodifacoum, Diphacinone and Warfarin in Water by Liquid Chromatography/Tandem Mass Spectrometry (LC/ MS/MS)’. ASTM D7645, ‘Standard Test Method for Determination of Aldicarb, Aldicarb Sulfone, Aldicarb Sulfoxide, Carbofuran, Methomyl, Oxamyl and Thiofanox in Water by Liquid Chromatography/ Tandem Mass Spectrometry (LC/MS/MS)’. ASTM D7678, ‘Standard Test Method for Total Petroleum Hydrocarbons (TPH) in Water and Wastewater with Solvent Extraction using Mid-IR Laser Spectroscopy’. ASTM D7730, ‘Standard Test Method for Determination of Dioctyl Sulfosuccinate in Sea Water by Liquid Chromatography/Tandem Mass Spectrometry (LC/MS/MS)’. ASTM D7731, ‘Standard Test Method for Determination of Dipropylene Glycol Monobutyl Ether and Ethylene Glycol Monobutyl Ether in Sea 2Water by Liquid Chromatography/Tandem Mass Spectrometry (LC/MS/MS)’. ASTM D4025, ‘Standard Practice for Reporting Results of Examination and Analysis of Deposits Formed from Water for Subsurface Injection’. ASTM D4127, ‘Standard Terminology Used with Ion-Selective Electrodes’. ASTM D4520, ‘Standard Practice for Determining Water Injectivity Through the Use of On-Site Floods’. NACE Standard RP0192, ‘Monitoring Corrosion in Oil and Gas Production with Iron Counts’.

12.3.14 Sand measurement18–20 An analysis of reservoir rocks of conventional and unconventional (e.g., oilsands) oil sources indicates that sand production is inevitable. The presence of sand may result in erosion, erosion-influenced corrosion (EIC), corrosion-influenced erosion (CIE), sand settling (leading to underdeposit corrosion) and loss of inhibitor effectiveness (see Chapter 5). Therefore, sand measurement is important, especially in oil and gas production and gas transmission pipelines. There are many sand monitoring devices, but commonly acoustic and electrical resistant (ER) probes are used. No standard methodology has been developed for monitoring sand.

12.3 Measured properties

795

12.3.15 Fouling The accumulation of scales, wax, asphaltenes, and biofilms is commonly known as fouling. Fouling reduces heat exchanging properties, increases pressure drop and increases the probability of underdeposit corrosion as well as microbiologically influenced corrosion (MIC). Loss of heat exchanging property of heat-exchangers and pressure drops in piping and pipelines are commonly used to measure the extent of fouling. Standards that describe fouling measuring techniques include: • •

NACE Standard RP0189 (latest revision). ‘Online Monitoring of Cooling Waters’. NACE Standard TM0286 (latest revision). ‘Cooling Water Test Unit Incorporating Heat Transfer Surfaces’.

12.3.16 Soil properties Many oil and gas infrastructure are buried under the soil, so naturally the physical and chemical properties of the soil influence external corrosion. From the perspective of corrosion control, obtaining all information on the soil is tedious and may even be counterproductive. One US study indicated that soil characteristics are so divergent that even generalities based on soil data must be drawn with care.21 The Canadian Energy Pipeline Association (CEPA)’s stress corrosion cracking report – in its second edition – reduced the dependency on soil data in addressing SCC.22 In spite of these facts, if certain soil properties are required, it may be prudent to obtain such data elsewhere. For example, government departments that deal with agriculture collect and store soil characteristics, and appropriate data may be obtained from these departments. In the USA, the Department of Agriculture initially classified the soil into several basic types (Figure 12.10).21 Several properties of soil may be obtained from sources

FIGURE 12.10 USA Classification of Soils.23

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similar to the Department of Agriculture. With respect to corrosion, the most relevant soil properties include oxygen level, CO2 level, water content, pH, electrical conductivity, and microbial species. The standards providing guidelines for measuring soil properties with respect to corrosion include: • • • • • • •

ASTM G187, ‘Standard Test Method for Measurement of Soil Resistivity Using the TwoElectrode Soil Box Method’. ASTM G57, ‘Standard Test Method for Field Measurement of Soil Resistivity Using the Wenner Four-Electrode Method’. ASTM G51, ‘Standard Test Method for Measuring pH of Soil for Use in Corrosion Testing’. ASTM D6780, ‘Standard Test Method for Water Content and Density of Soil in Place by Time Domain Reflectometry (TDR)’. ASTM G200, ‘Standard Test Method for Measurement of Oxidation-Reduction Potential (ORP) of Soil’. ASTM G162, ‘Standard Practice for Conducting and Evaluating Laboratory Corrosion Tests in Soils’. NACE TM0106, ‘Detection, Testing, and Evaluation of MIC on External Surfaces of Buried Pipelines’.

12.3.17 Environmental properties Almost all oil and gas infrastructures are exposed to environmental conditions above-ground during construction and some are above-ground during operation. Above-ground environmental conditions

FIGURE 12.11 Ultraviolet (UV) Index.24 (Obtained from Environmental Canada).

12.4 Precautions in using measured data for corrosion control

797

may affect these infrastructures. Environmental properties are too numerous for the corrosion professionals to collect, but much data is collected by government agencies for other purposes and may be obtained from these agencies. For example, in Canada, Environmental Canada collects much data on an hourly, daily, monthly, yearly, and seasonal basis. With respect to corrosion, the most relevant environmental data are temperature, UV index, rainfall, and snowfall. Figures 12.11 through 12.14 present typical data that can be obtained from environmental departments of government agencies.

12.4 Precautions in using measured data for corrosion control Unlike the data which are collected solely for corrosion control purposes, the data for the parameters discussed in section 12.3 are collected for reasons other than corrosion and by operators who may not have corrosion knowledge. Therefore it is the responsibility of the corrosion professional to be knowledgeable of such data, to be aware of locations where such data are stored, to obtain them, to consider the influence of the techniques used to measure these properties and the frequency at which they are collected, and to analyze the accuracy of the data before using them for corrosion control

FIGURE 12.12 Daily Average Temperature Recorded by Environmental Canada in Norman Wells, NorthWest Territory, Canada.24

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CHAPTER 12 Measurements

FIGURE 12.13 Daily Rainfall Recorded by Environmental Canada in Norman Wells, NorthWest Territory, Canada.24

FIGURE 12.14 Daily Snowfall Recorded by Environmental Canada in Norman Wells, NorthWest Territories, Canada.24

References

799

purposes. Access to the data may be difficult, the data may be voluminous, and the task of analyzing them may be horrendous, yet the result of such efforts may be beneficial in establishing efficient corrosion control practice. Typical questions a corrosion professional should ask before using the data include: 1. Does this data influence corrosion? If the answer is ‘no’ there is no point on using it. 2. Is this data collected by somebody in the company? If not, is it possible to start collecting the data? 3. Is the data collected using standard methodologies? 4. Is the data collected by online or offline measurement techniques? 5. How frequently is the data is collected? Is the frequency enough for corrosion control purposes? If the frequency is too low, is it possible to increase it? 6. Where is the data, i.e., its location? 7. Is the format suitable for easy usage for corrosion control? 8. What is the reliability of the data? This step is the most critical step in determining whether to use the data or not. 9. What is the protocol to routinely obtain the data? 10. How does the data change the scenario of corrosion control, i.e., does this data provide clarity or explanation for the corrosion observed? 11. How will this data integrate with other data collected for corrosion control?

References 1. Papavinasam S, Doiron A, Wu E, Revie RW. Determination of inhibitory and corrosive properties of condensates. Gas Research Institute (GRI)/Pipeline Research Council International (PRCI), GRI January 2005. 8705. 2. J. Collier and S. Papavinasam, ‘Establishing a state-of-the-art corrosion laboratory: a journey towards ISO/ IEC 17025’, NACE Northern Area Eastern Conference, Ottawa, Ontario, Canada, Oct. 15–18, 2011. 3. Skoog DA, West DM, Holler FJ. Fundamentals of analytical chemistry. Adopted from Figure 1.1. Thomson Learning Academic Resource Center 1996:3. ISBN: 0-03-005938-0. 4. Skoog DA, West DM, Holler FJ. Fundamentals of analytical chemistry. Adopted from Figure 2.2. Thomson Learning Academic Resource Center 1996:14. ISBN: 0-03–005938-0. 5. Skoog DA, West DM, Holler FJ. Fundamentals of analytical chemistry. Adopted from Figure 3.1. Thomson Learning Academic Resource Center 1996:22. ISBN: 0-03-005938-0. 6. Skoog DA, West DM, Holler FJ. Fundamentals of analytical chemistry. Adopted from Figure 3.4. Thomson Learning Academic Resource Center 1996:26. ISBN: 0-03-005938-0. 7. Corrosion monitoring and control systems, Caproco (1987) Limited, ‘Applications and use of the caproco high pressure access system for corrosion and process monitoring control’ January 1998, 4615 Eleniak Road, Edmonton, Alberta, T6B 2N1. 8. Smith HV. Chapter 12: Oil and gas separators. In: Petroleum Engineering Handbook. Society of Petroleum Engineers; 1987. ISBN: 1-55563-010-3. 9. Dean SW. Velocity-accelerated corrosion testing and predictions – an overview. Materials Performance 1990;29(9):61. 10. Gaverick L, editor. Corrosion in the petrochemical industry. Materials Park, OH: ASM International; 1994.

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11. Gas Processors Suppliers Association (GPSA) Engineering Data Book, 13th Edition, ASIN: B000USKIKE, Publisher GPSA, 6526 E, 60th Street, Tulsa, OK, USA, 74145. 12. Gutzeit J. Napthenic acid corrosion in oil refineries. Materials Performance 1977;16(10):47. 13. White RA, Ehmke EF. Materials selection for refineries and associated facilities. Houston, TX: NACE; 1991. 14. Degremont SA. Water treatment handbook (translated from French into English by Language Consultants (France) Limited). New York, NY: Halsted Press; 1979. 15. Drew principles of industrial water treatment. Boonton, NJ: Drew Industrial Div., Ashland Chemical Co; 1995. 16. The NALCO. Water Handbook. In: Kemmer FN, editor. 2nd ed. New York, NY: McGraw-Hill Book Co; 1988. 17. Ives DJG, Janz GJ. Reference electrodes – theory and practice. New York, NY: Academic Press; 1961. Reprinted by NACE with permission of Academic Press in 1996, Loc No. 60–16910. 18. Salama MM. Performance of sand monitors. CORROSION/2000, Paper No. 00085. NACE International, Houston: TX, USA; 2000. 19. Brown GK. Solids and sand monitoring – an overview. CORROSION/2000, Paper No. 00091. NACE International, Houston: TX, USA; 2000. 20. Shirazi SA, McLaury BS, and Ali MM. ‘Sand monitor evaluation in multiphase flow’, CORROSION/2000, Paper No. 00084, NACE International, Houston, TX, USA (2000). 21. Ricker RE. ‘Analysis of pipeline steel corrosion data from NBS (NIST) studies conducted between 1922–1940 and relevance to pipeline management’, NISTIR 7415, National Institute of Standards and Technology, Gaithersburg, MD 20899, USA. 22. Canadian Energy Pipeline Association (CEPA) stress corrosion cracking recommended practices. 2nd ed. Calgary: Alberta, Canada; Dec. 2007. 23. Ricker RE. ‘Analysis of pipeline steel corrosion data from NBS (NIST) studies conducted between 1922–1940 and relevance to pipeline management’, Figure 3, May, 2007 NISTIR 7415, National Institute of Standards and Technology, Gaithersburg, MD 20899, USA. 24. Obtained from Environment Canada – Data Archives, Environment Canada, 4905 Dufferin Street, Toronto, Ontario CANADA M3H 5T4.

CHAPTER

Maintenance

13

13.1 Introduction The International Air Transport Association (IATA) defines maintenance as ‘those actions required for restoring or maintaining an item in serviceable condition, including servicing, repair, modification, overhaul, inspection, and determination of condition’.1 All measures (such as selection of appropriate materials that can withstand corrosion in a given environment, development of an appropriate model to predict the behavior of the system, implementation of mitigation strategies to control corrosion, and monitoring of the system to ensure that corrosion is under control) would fail if a good maintenance strategy was not developed and implemented. Maintenance is a key activity in all sectors of the oil and gas network, and is routinely carried out; yet it is often the first to suffer when cost-cutting measures are implemented. In this regard, three common misconceptions about maintenance should be recognized and overcome in implementing a good control corrosion program: •

•

•

Misconception 1: Maintenance is associated with equipment • Maintenance is not associated with equipment or infrastructure alone, but is associated with at least five interdependent entities: equipment, workforce, data, communication, and associated activities (e.g., laboratory support, workforce that performs the activity). Misconception 2: Maintenance is carried out during operation • Maintenance is not only performed during operation, but also is performed in all stages of a project including design, construction, commissioning, normal operation, changes to normal operation, scheduled shutdown (downtime), refurbishment, modification, non-scheduled shutdown (due to emergency or failure), and abandonment. Misconception 3: Maintenance is an expenditure • Maintenance is not expenditure but a preventive cost-saver for the future.

A comprehensive and effective program requires maintenance of five interdependent entities: • • •

The equipment is the piece of apparatus or infrastructure that should be kept in good working condition. The workforce is the personnel who develop, deploy, and perform the necessary activities. Historical operational data provides guidelines on the past history and information to guide future action.

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00013-3 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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A communication strategy disseminates appropriate information among various groups within and outside the company. Associated activities that provide support to the company or industry.

This chapter describes general characteristics of these entities.

13.2 Equipment The equipment may be as small as a handheld, battery-operated data-logger, or as large as a pipeline or a unit in the refinery. Table 13.1 presents some typical equipment used in the oil and gas industry and their typical maintenance schedules.2,3 It should be noted that the information in this table is only an illustration of a few pieces of equipment in use, and is not an exhaustive list of equipment to be maintained. Equipment is designed so that it will operate unattended reliably for a certain duration, after which it should be cleaned, overhauled, repaired, and warn-out parts replaced. In addition, certain equipment may require periodic and continuous maintenance, e.g., ensuring that lubricating oil is present at the prescribed level in an engine, or corrosion inhibitor is present at the prescribed level in a continuous inhibitor storage tank. The maintenance of equipment is necessary to assure continued effective operation. Intervals for such maintenance activities depend on the equipment manufacturer’s recommendation and operational conditions of the equipment. The reliability of the maintenance of the equipment depends on the availability of facilities and personnel. If there is reason to believe that they will not be adequate, then such equipment must be designed for lesser maintenance frequency. Such designs will of course increase the cost of initial installation. However, designs which omit maintenance activities have higher levels of risk. For example, when designing a cathodic protection (CP) system, a sacrificial galvanic anode CP system rather than an impressed current CP system is preferred in situations where maintenance activities cannot be conducted frequently. However, it should be recognized that a galvanic anode system also requires maintenance, e.g., replacement of anodes after they are consumed. For these reasons, it is important to treat maintenance of equipment as an essential and integral activity of using it. This section discusses types of maintenance, stages for implementing maintenance, activities during maintenance, and extent of maintenance.

13.2.1 Types of maintenance A good program develops a structured approach to determine the maintenance requirement of an infrastructure. Depending on the proactive level of organization, maintenance can be broadly classified into: continuous, predictive, condition-based, preventive, ad hoc, and corrective.

13.2.1a Continuous maintenance Certain equipment requires continuous maintenance. Typical examples of such kind of activities include maintenance of corrosion inhibitor in the tank, fuels and lubricants in an engine, and water or coolant levels in coolers and chillers. Lack of such maintenance activities may make the equipment fail immediately or in a short period of time. Therefore such maintenance activities are carried out daily, weekly, monthly, or at other pre-determined intervals of time, by dedicated persons.

13.2 Equipment

803

Table 13.1 Some Equipment Used in the Oil and Gas Industry and their Typical Maintenance Schedule2,3

Equipment

Typical Maintenance Schedule

Battery

Biweekly

Solar electric power system

Biweekly

Wind-powered generator

Monthly

Rectifier

Bimonthly

Junction box

Bimonthly

Thermoelectric generator

Annual

Rectifier Junction box

Annual Annual

Isolation flange Sacrificial anode

Annual Biannual

Rectifier

Biannual

Thermogenerator

Biannual

CP station

Biannual

Impressed current anode

Biannual

Electrical bond

Annual

Corrosion inhibitor level

Weekly

Corrosion inhibitor injection

Monthly

Typical Activities During Maintenance • Check fluid level • Recharge or replace • Inspect and if necessary replace solar cell and storage battery • Lubricate the bearings and mounting swivel • Clean or replace brushes and slips rings • Check and correct electrical parameters of rectifier; grounding, cables and fuses • Check and correct electrical parameters, current and voltage • Replace fuel filter and clean fuel orifice • Check external coating • Check and correct cables, connectors, and coatings • Check and adjust efficiency • Check and adjust current drainage • Check and correct dielectric, oil, humidity, and contamination • Check fluid level that lubricates the shaft • Check and adjust electrical continuity • Check and adjust current drainage • Clean groundbed • Check and adjust tension and current • Check and refill inhibitor fluid level • Check injection pump and nozzle

Used In Several applications Cathodic protection

Cathodic protection

Cathodic protection

Cathodic protection

Cathodic protection Cathodic protection Cathodic protection Cathodic protection Cathodic protection Cathodic protection

Cathodic protection Cathodic protection Cathodic protection

Cathodic protection Corrosion inhibitor Corrosion inhibitor

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13.2.1b Predictive maintenance In this process the maintenance is pre-planned so that the infrastructure is maintained in its proper operational condition. The maintenance schedule is mostly based on modeling (discussed in Chapters 6 and 10), and may sometimes be based on data from monitoring techniques (discussed in Chapters 8 and 11). In order to implement a predictive maintenance schedule a thorough knowledge of the functionality of the infrastructure and history of operation is necessary. If a predictive maintenance program is implemented, theoretically, failures should never occur, because it takes a very conservative approach to protecting the infrastructure. Consequentially, maintenance costs and frequency are high.

13.2.1c Condition-based maintenance In condition-based maintenance, the schedule of maintenance activities is not pre-planned, but is determined based on the actual current condition of the infrastructure. This program relies heavily on the data from monitoring, inspection (discussed in Chapters 8 and 11), and measurement (discussed in Chapter 12) activities, but may also use models to determine the initial frequency at which the monitoring data should be collected. In addition, the data is analyzed and interpreted by knowledgeable personnel before a decision on maintenance is taken. This program requires a thorough knowledge and understanding of the information derived from the data so that maintenance activities are implemented as soon as possible or delayed as for as long as possible. The success of the program depends on the ability of the monitoring techniques to produce information, not only in the locations where monitoring occurs, but also in the entire system. For this reason, several sensors, monitoring techniques, and measuring techniques are required. Though the cost of monitoring is higher in this program, cost saving occurs due to the deferral of unnecessary maintenance activities.

13.2.1d Preventive maintenance Whereas predictive maintenance depends on the ability of a model, and condition-based maintenance depends on the monitoring data, the preventive maintenance combines a judicial ratio of both approaches. In this program, monitoring activities are pre-scheduled based on operators’ knowledge and predictive models, and decisions are taken on the timing of maintenance program based on the monitoring data. In this program, the cost of maintenance increases both due to the cost of collecting data to run the model and the cost of monitoring. However, cost savings may occur if the maintenance program is deferred based on information on the current condition of the infrastructure.

13.2.1e Ad hoc maintenance In this maintenance method, no systematic strategy or guideline is used to schedule the maintenance activities. Though this approach is very rarely used for critical structures or equipment, it may sometimes be used for non-critical structures or equipment.

13.2.1f Corrective maintenance All the maintenance methods discussed in the previous sections are proactive processes, i.e., the maintenance activities are carried out for the continued operation of the infrastructure. However if an incident or accident happens, then corrective maintenance activities should be undertaken immediately. The corrective maintenance activity should also include an evaluation of the failure mechanism, and implementation of steps to ensure that such an incident or accident does not recur in the

13.2 Equipment

805

infrastructure, or in any other infrastructure operating under similar conditions. Corrective maintenance in a structure that has failed may trigger the execution of preventive maintenance activities in similar infrastructures.

13.2.2 Stages for implementation of maintenance Maintenance activities are integral to corrosion control and should be considered and implemented at every stage of the operation. This section discusses how they are carried out, from design stage to abandonment stage.

13.2.2a Design stage Ideally, maintenance activities should be considered and implemented at the design stage. As discussed in Chapter 14, materials are normally selected at this stage. When considering the materials or corrosion control strategy, the balance between the ability of the material to withstand the operating conditions and its ability to maintain it during operation should be considered. Normally, when a corrosion resistant alloy (CRA) is selected, or an advanced corrosion control strategy is specifed (e.g., cathodic protection system with larger anode bed), the frequency of maintenance activities decreases. Although such measures increase capital expenditure (CAPEX), operational expenditure (OPEX) decreases. The reverse is also true, i.e., if a material is selected or a corrosion control strategy is designed to minimize CAPEX, then OPEX increases due to higher frequency of maintenance activities during service. The most cost-effective and risk-minimizing solution is to balance both CAPEX and OPEX at the design stage. This should involve identification of the extent and frequency of maintenance during service.

13.2.2b Construction stage If facilities or accessories to carry out maintenance activities are not installed, or installed improperly during construction, this will cause additional expenditure during service. Therefore, it is important that facilities and accessories to perform maintenance are properly installed. All dirt and construction materials must be removed and the infrastructure should be cleaned. Once construction is completed, the structure is normally filled with nitrogen or any other suitable inert gas until operation starts. During the turn-key process, the construction team hands over the infrastructure to the operations team. During this process, the proper installation of accessories to perform maintenance activities is verified and documented. The baseline conditions of the infrastructure are obtained, so that the change in its properties can be tracked during service. The first maintenance schedule is established based on the condition of the infrastructure and on documents provided by the construction team. Infrastructure consists of several pieces of equipment and gadgets. The equipment manufacturers’ manuals should be collected and documented. They provide guidelines for operating the equipment, as well as the type and frequency of maintenance to be performed. Based on these manuals, and on experience in using similar equipment, the standard operating procedure (SOP) should be developed for operators to follow during service. In addition, the lock-out tag-out (LOTO) process of the equipment should also be established. LOTO is required if the equipment exceeds its regular maintenance period, is suspected to be malfunctioning, and when it is moved from one location to another. This procedure ensures that the equipment is not used unless it is in its optimal operational condition.

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13.2.2c Start-up One of the key activities during start-up is hydrotesting, which ensures that the structure is fit for operation (see section 11.6 for more details). After hydrotesting, the water is removed, and the structure is cleaned, dried, and refilled with inert gas if operation is not due to start immediately. Water remaining from hydrotesting is one of the main causes of internal corrosion in operations which do not normally handle water, e.g., dry gas pipelines. Such pipelines also assume that the probability of corrosion is low as there is no water during operation. However if the water from hydrotesting is not removed it will cause corrosion. During start-up, several facilities and equipment are started simultaneously. As a consequence, the probability of the system exceeding its normal operating limits before reaching steady-state is high. For example, if the infrastructure is externally protected by a coating with a temperature limit of 80 C (176 F), and if during start-up the temperature exceeds this limit even for a short duration, the coating may be damaged on day one of operation. In one incident, the temperature exceeded the coating limit only for four hours during start-up, and this resulted in the recoating an entire section of pipeline.4

13.2.2d Normal operation Most maintenance activities are traditionally performed at pre-determined intervals (e.g., during scheduled shutdown – see section 13.2.2f). Figure 13.1 presents a typical decision process for determining a maintenance schedule during normal operation.5 As can be seen from the figure, it depends on three different aspects: policy and regulation, current field conditions, and historical learning. The primary decision regarding maintenance is based on corporate standards, corporate plan, regulatory requirement, and system audit (which may be performed by in-house personnel or by a third party). The second decision is based on current operating conditions of the system as obtained from monitoring, inspection, and maintenance activities already carried out. The quality control (QC) of each and every activity should be exercised before taking a decision based on the information. The

Incident Learning

Corporate Standards

Corporate Plan

Regulations

System Audit

Mitigation data

Mitigation QC

Monitoring data

Monitoring QC

Inspection data

Inspection QC

Repair activities

Repair QC

Plan Maintenance

FIGURE 13.1 Typical Decision Flow Chart to Determine Maintenance Schedule in a Company.5

Analysis of all activities

Historical Data

13.2 Equipment

807

third decision is based on historical data. As illustrated in Figure 13.1, all these activities are interrelated, so that learning improves maintenance activities continuously.

13.2.2e Changes to normal operation Operational changes may require infrastructure to operate at conditions for which it was not designed, or for well beyond their design period. When this situation occurs, it is important that the maintenance program is re-evaluated and a new maintenance schedule is established. Some operations may be tolerable beyond design conditions for a short period of time, but others may not. In some conditions, changing the materials may allow extending the operational envelope. In either case, it is prudent to collect and analyze appropriate parameters possible before and after the changes to the operational conditions, so that the impact of the changes to the maintenance program is understood.

13.2.2f Scheduled shutdown No equipment or infrastructure operates 24/7 for an indefinite period of time. During service, they undergo a normal shutdown or downtime period. Almost all maintenance activities for equipment operating under normal conditions are planned during the scheduled shutdown. Figure 13.2 presents a typical cycle during a planned maintenance activity.5 It should be noted that maintenance is a continuous cycle, with observations made and lessons learned being used to improve the process.

13.2.2g Refurbishment During service, the equipment or infrastructure may undergo refurbishment to restore proper functionality. This kind of maintenance is required because the original equipment or component is damaged due to corrosion, wear, or tear. During this process, it is important to ensure that the original functionality or capability is not lost. Special attention should be paid to ensure that new materials or components are compatible with existing ones. One common effect of adding new parts is galvanic corrosion caused by dissimilar metals. The corrosion engineer should ensure that such a situation does not occur during refurbishment.

13.2.2h Modification Also during service, the equipment or infrastructure may undergo modification to change its functionality, with the addition or removal of new parts or capabilities. When adding new parts it is important to ensure that they are compatible with existing parts, i.e., galvanic corrosion does not occur as discussed in section 13.2.2g. On the other hand, when removing existing parts it is important to ensure that the capability for corrosion control is not lost. In one incident, a side stream of a pipe in

Plan Improve

Schedule

Analyze

Implement

FIGURE 13.2 Maintenance Activities During Normal Operations.5

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which the corrosion coupons were present was removed. Consequently the ability to monitor corrosion was lost due to the system modification.

13.2.2i Non-scheduled shutdown Almost all maintenance activities discussed in sections 13.2.2a through 13.2.2h are pre-scheduled, so that the operator is in control of the activity. But when a non-scheduled shutdown occurs due to a failure, an emergency situation prevails. Under such conditions, the focus is mainly on making the system operational as quickly as possible. Most of the time, the influence of maintenance on corrosion is not considered. However once the system is back in operation, a careful review of the maintenance activities should be conducted to ensure that activities performed during emergency situation will not accelerate, cause, or influence corrosion in the future.

13.2.2j Abandonment The infrastructure may be abandoned for varies reasons, including loss of production, better alternatives, or no further need for that feature. The infrastructure should be maintained even during this condition for at least two reasons. •

•

Continuous corrosion in the abandoned state may lead to leakage of ingredients into the environment. In many parts of the world, regulations require that abandoned infrastructure does not cause any environmental issues. Sometimes the abandoned infrastructure may be required again for operation. If it is properly maintained during the abandoned state, the cost and effort to bring it to operational conditions may be relatively low.

A simple procedure to abandon an infrastructure is to thoroughly clean its internal surface to ensure that no corrosive substance is left behind and to fill it with nitrogen or other inert gas. Normally no further maintenance activities are required to protect the internal surface. Depending on the condition of the coating and the environment, the external surface of underground infrastructure should be protected by CP; in most parts of the world regulations require that the CP continues during the abandoned state.

13.2.3 Activities during maintenance Maintenance of equipment or infrastructure should be an integral part of the design stage. The maintenance program discussed in section 13.2.2 is in a way an ideal situation. Often, maintenance activities may be forgotten for a long time and suddenly the corrosion engineer/team may be asked to carry them out. Such action may be triggered by a failure in a similar system within the company or within the industry. If the maintenance program is not a part of the operational philosophy of a company, it may be difficult to know where to start. This section discusses the sequence of activities typically carried out to develop and implement a maintenance program.

13.2.3a Structure details The first step before any maintenance activity can be planned is to obtain the blue-print or original drawing of the structure. It may be an asset registry, engineering drawing, as-built drawing, or any other appropriate drawing. This drawing may provide critical information about the structure, and may help to prioritize places where the maintenance activities should be carried out.

13.2 Equipment

809

13.2.3b Service history The next step is to understand the history of operation, maintenance, and incidents, if any, of the structure. The more information on historical operating conditions is obtained, the easier it is to develop appropriate maintenance activities. Depending on how the data is maintained within the company, collection may be straightforward or impossible. Even when no formal process is followed, sometimes informally talking with experienced people may provide valuable historical service information about the structure.

13.2.3c Corrosion data Chapters 8 and 11 detail various techniques for monitoring internal and external corrosion respectively. In addition to collecting structure details and service history, any corrosion data recorded in previous years is valuable. These data could be from monitoring, inspection, or laboratory tests. Depending on the data collection and storage policy (see section 13.4 for more information on data management) such data may or may not be available. When using data collected from previous years, their validity and accuracy should be evaluated. A general maintenance program can be developed from the structure details, the service history, and the corrosion data. Sometimes none of this information is available; in which case the maintenance program should be very conservative, e.g., the frequency of maintenance activities should be high at the beginning and then be progressively decreased as more data is collected and analyzed to gain confidence about the state of the infrastructure.

13.2.3d Expert opinion In the absence of any useful information, it may be prudent to consult a subject matter expert (SME) to develop a maintenance program. In any event some data is needed. Using the data, current operating conditions, and past experience, the SME may provide a starting point. The SME need not be an outside consultant, but could be a senior in-house person who has been associated with the infrastructure for a long period of time.

13.2.3e Trend Based on all available data, knowledge, and expertise, a trend of the behavior of the infrastructure should be developed. The models discussed in Chapters 6 and 10 may be used for this purpose. Such a trend analysis may be useful to schedule the maintenance activity and to determine the consequence of not performing maintenance.

13.2.3f Structure availability Once the trend of the behavior of the structure is established, the availability of the structure for maintenance activities should be determined. As discussed in section 13.2.2e, it will not be in use all the time. Operational requirements render the structure being idle at some point. To the greatest extent possible, all maintenance activities should be planned during this downtime period.

13.2.3g Loss of productivity Sometimes it may be impossible to delay the maintenance activities until the downtime period. Under this condition, a suitable period should be determined in consultation with operational personnel so that the loss of production is kept to a minimum. In general, operation personnel will not wish to force

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a shutdown for maintenance unless the consequence of not doing it is communicated to them properly and in advance.

13.2.3h Scheduling The maintenance schedule should be established from all the activities discussed in sections 13.2.3a through 13.2.3g. It may be prudent to first distribute a tentative schedule to all concerned personnel and seek their input and concurrence before finalizing it. Sometimes it may be difficult to obtain agreement from all concerned personnel and the process of consultation may be lengthy, but such a practice will help to schedule the maintenance activity at the least inconvenient time for all. It will also be necessary to communicate that failure due to corrosion may occur unless maintenance activities are carried out sooner.

13.2.3i Purchasing accessories Almost all maintenance activities require additional equipment and spare parts. It is important to ensure that all the accessories required to carry out the maintenance activity are (or will be) available before finalizing the schedule. The worst case scenario is to pause all activities to perform maintenance, only to find out that the required accessories are not available.

13.2.3j Human resources Performing maintenance activities require additional resources over those normally present within the corrosion team. These resources may be in-house personnel, or people from outside the company. It is important to schedule and secure their availability. Sometimes the schedule and plan of maintenance activities need to be adjusted due to the human resources available. In some companies, all maintenance activities are carried out by a third party. In that case it is the responsibility of the third party to secure resources as per the schedule established. In addition, it is important to double check that the maintenance crew consists of people with right skills, training, and experience. It is also prudent to appoint one responsible person to oversee the overall implementation of a particular maintenance activity.

13.2.3k Environmental factors Maintenance activities produce substances or waste that should be properly disposed of. It is important to understand – before the activity starts – the types of waste that may be produced, their environmental consequence, and the environmental regulations to follow in their disposal. Proper disposal procedures should be established for the maintenance crew to follow, both during and after maintenance activities.

13.2.3l Health, safety, and security The maintenance activities must be performed in a healthy, safe, and secure environment. Most companies have a written policy on health, safety, and security of operation. It is important for the corrosion engineer to implement it appropriately during maintenance activities. During maintenance, several pieces of equipment and accessories may be moved in and out of the facility. All activities should be properly coordinated, so that the health and safety of the personnel, property, and infrastructure are not compromised. In some parts of the world, the reliability of the personnel is prescreened for security reasons. Sometimes obtaining the reliability status may take longer, especially if they are from a third party company.

13.2 Equipment

811

13.2.3m Training and orientation The maintenance crew is assembled based on their knowledge, experience, and training, but they may not be familiar with the company. Therefore, it is imperative to orient the maintenance crew with respect to the facility, equipment, or company. Some companies require all personnel performing maintenance activities to undergo mandatory training and orientation before they start the work. This may not be directly related to the activity with which the maintenance crew is involved, but may be related to the operating procedures of the facility that the maintenance crew must follow. This safety training and orientation may be offered onsite or online, and some companies may require orientation every day.

13.2.3n Implementation Whatever be the extent of planning, experience of crew, and training, there may always be some deviation from the set procedure during implementation of maintenance activities. No one solution fits all; whatever is most practical and cost-effective without compromising integrity should be implemented. The processes identified in sections 13.2.3a through 13.2.3m may be used as guidelines during the implementation of maintenance activities. If the workers who perform the actual work do not understand the situation and develop a quick solution, the maintenance activity may not produce the desired result. Therefore, it is important to let the workers carry out the work systematically and in their own way; perhaps a daily briefing may be held to discuss any deviations, the reasons for them, and to develop alternative implementation procedures.

13.2.3o Quality assurance It is also important to establish how the quality of the work will be assured. Ultimately the manager in charge (see section 13.2.3j) is responsible for the overall quality of the work performed. This includes making sure that the maintenance activities ensure integrity of the structure, do not result in any failure down the road, and do not receive any complaints from other operations. The project officer in charge should demonstrate the integrity of the work performed, rather than demonstrating that ‘due diligence’ was exercised during the implementation.

13.2.3p Side effects Sometimes maintenance activity may produce unintended negative side effects. Such side effects are too numerous to list, but two commonly occurring examples are: • •

The cathodic protection current source was switched off for maintenance but is not switched on after the work was completed. Pipes in which monitoring techniques are installed are rotated by 180 . Consequently the monitoring probe originally placed at the bottom of the pipe, i.e., at the 6 o’clock position where water accumulates, is now in the 12 o’clock position.

Therefore, the conditions of the infrastructure or equipment before the maintenance activity should be understood and should be returned back to their original conditions after the maintenance activity.

13.2.3q Lessons learned As illustrated in Figure 13.2, maintenance is a continuous cycle. Therefore, after the project is completed, the process should be analyzed and opportunities to improve the process, if any, should be

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identified, and should be used to improve the process the next time. A general meeting of the whole project team, informal feedback, formal feedback or any other suitable process may help to identify such opportunities.

13.2.4 Extent of maintenance Sections 13.2.1 and 13.2.2 discuss various aspects of maintenance. Before fully fledged execution of these activities, the required extent of maintenance should be determined. If the structure, e.g., production pipeline, is required only for a very short period of time, e.g., a depleting well, the extent of its maintenance can be minimal. Maintenance activities should merely ensure that the production system operates without incident until the well stops producing. In this situation, increasing the concentration of corrosion inhibitors to reduce the corrosion rate may be a better option than replacing a section of pipeline. On the other hand, a trunk pipeline carrying crude oil to a refinery has a longer life span. Any failure of such infrastructure causes cascading effects downstream, so their maintenance activities should have long lasting effects.

13.3 Workforce People are the driving workforce behind the oil and gas industry. They are involved in each and every step of the process. Their functionality includes, but is not limited to conceptualizing a design, writing process and performance specifications, writing contracts, purchasing the parts required for construction (both hardware and software), overseeing the construction, performing the tasks, supervising the construction, establishing the quality, managing the project and operation, troubleshooting the problems, maintaining the equipment -– and the list goes on and on. One common issue with oil and gas industry – and for that matter in most other industries as well – is the concept of ‘downsizing’, which results in less and less ‘qualified’ personnel being hired to perform more and more ‘sophisticated’ work. The following quotes summarize the state of the workforce in the oil and gas industry:6 •

•

•

•

‘The oil and gas industry workforce is old: a ‘young’ worker is about 43, and an ‘old’ worker is 55. Their average age is about 50 and their average retirement age is 55; therefore, it is obvious that the industry faces a major skills crisis in the next 5 to 10 years, as more than half the experienced workforce will leave the industry’.7 ‘People with all skills are retiring, including professional engineers, technologists and technicians. We are all aware of the ‘missing generation’ in the oil and gas industry. The workers who trained in the 1960s and 1970s are approaching retirement; but the new, younger generation attracted to the industry by the recent boom are still too young to replace the retirees. Replacement takes time: it takes about three years for new staff to become familiar with the industry, and about a further 10 years to gain a professional discipline’.8 ‘Fewer people are entering the (oil and gas) business – for example in the US, enrolment in Petroleum Engineering programs shrank from 11,000 in 1993 to 1700 last year (2008). Seventeen universities closed their programs over the same period’.6 ‘We need to convince young people that a technical career in this industry is both stimulating and worthwhile’.9

13.3 Workforce

•

•

813

‘There has never been a time when our industry so needs outstanding talent. Older professionals will need to be replaced in a few years. At the same time we have seen a drop in the number of students taking science based programs’.10 ‘Faced with one of the biggest periods of expansion in its history, the global oil and gas industry is already being held back by its failure to attract, recruit and retain highly skilled staff. This is true from rig workers to senior scientists and engineers. Through short-term thinking and a belief that required staff can be bought, the oil and gas industry has stretched its resource base to breaking point’.6

The oil and gas industry functions within the constraints of the availability of the right workforce. Yet it is important that the people involved in the various stages should understand the impact of their action or inaction on corrosion. A typical process of constructing a piece of equipment or infrastructure consists of the following steps: • • • •

• •

The need for and the functionality of the equipment or infrastructure are identified. Various options for executing the function are considered and the optimum design in terms of functionality, budget, and current and future requirements is selected. A prototype is built and tested to establish that the design will meet the operational requirements. Testing of prototype establishes most of the functionalities of the equipment but not all. Design change and retesting of the prototype are carried out to further establish confidence in the design, the maintenance interval of the equipment, and the blue-print for the construction of actual equipment. Based on the prototype the equipment is built and commissioned. Finally, the equipment is operated, maintained, repaired, refurbished and finally abandoned (or disposed of).

Personnel involved in all these steps consider several aspects and make critical decisions. The success of the equipment or infrastructure depends entirely on these decisions. The people involved can be broadly classified into those who are involved in the design and construction stage, and those involved in the operating stage; the former deals with CAPEX and the latter deals with OPEX. Many of the corrosion issues faced during operation would be avoided or vastly reduced if the people involved in the design and construction of a piece of equipment or infrastructure are knowledgeable about corrosion. Typical persons involved in the design and construction stages are described in the following section:

Conceptual Designer:

The conceptual designer writes a document that indicates operational requirements, such as high pressure operation, high temperature operation, onshore or offshore, crossing a stream or river, environmental condition (e.g., handling acid gases), transportability, environmentally suitability, and anticipated life. (Continued)

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dContinued Specification Engineer:

Materials Engineer:

Design Engineer:

Purchase Officer:

Sales Person:

Workman:

Quality Engineer:

Finance Manager:

The specification engineer describes specifications based on conceptual designer’s document. This person specifies the attributes of the material required for the process, the operating window, corrosion mitigation strategies, monitoring location and techniques, and maintenance schedule. He/she develops this document based on experience from an existing system or from knowledge gained from operating pilot tests. Failure by the specification writer to describe corrosion performance may lead to premature failure, even if the equipment operates under specified environment. A materials engineer recommends appropriate materials (both metals and nonmetals), their thicknesses, their thermal treatments, surface treatments, and joining material requirements. The options available for the materials engineer may be overwhelming, as the number of materials and their finish is ever-increasing. They should sort through the options to select cost-effective materials that can meet the operational requirements for the entire duration of the project. He/she should have a thorough knowledge of corrosion and corrosion control. A design engineer prescribes the equipment or infrastructure based on the conceptual and material engineers, documents. They prescribe the material and finish requirements. The specification engineer may specify the material type (e.g., stainless steel), whereas the design engineer may specify the actual material to be used (e.g., ASTM A213, Type 316L). The design engineer normally produces the blue-print of the equipment or infrastructure. He/she also prescribes corrosion protection strategies, joining requirements, and other specific requirements. The purchase officer buys or coordinates the purchase of materials as per the design engineer’s prescription. Depending on market availability and on the needs of the project, the purchase officer buys materials from one or several sources. It is the responsibility of the purchase officer to ensure that all materials meet the design engineer’s prescription and are compatible with one another. The material suppliers’ sales person sells appropriate materials. The purchase officer interacts with the supplier’s sales person. This person always comes up with materials with new and improved performance. When new or improved materials are to be used, their effect on the entire life of the project should be considered. For example, high strength materials may be susceptible to stress-corrosion cracking. If the design engineer’s prescription does not indicate mechanical properties such as grain direction, cracking threshold, fracture toughness, and corrosion properties, it is most likely that the purchase officer will buy improved materials without considering the overall implications. Workmen construct the equipment or infrastructure. The success of any project lies in their hands. Depending on the type of the project, several persons will be hired and trained to carry out the work. The quality engineer ensures the quality of the work. The quality engineer reviews the drawings (blue-print), the material specification, and the design to validate that they meet the requirements, and inspects the jobs on site to ensure that they are performed properly and that the materials used meet the specifications. The finance manager controls the project expenditure according to the approved budget. All projects or activities require their approval. It is important for this person to understand the concept of CAPEX vs. OPEX. If enough funds are not available for CAPEX during design and construction stage and the work is compromised, it will increase OPEX during operation, sometimes exponentially.

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815

The jobs identified in the proceeding paragraphs are just a few examples to illustrate the variety of personnel involved and their backgrounds. Depending on the project, some or many of the functions may be performed by a single person or a group of persons who work as an integrated team. Such integrated teams may involve people who are cross-trained to perform several tasks. If the individual worker or group of workers do not have basic corrosion knowledge, or pay no attention to the aspects of corrosion, or if there is no one individually identified (normally the materials engineer) to implement corrosion control strategies, corrosion issues may escalate during operation. Once construction has been completed, the equipment or the infrastructure is delivered to the operational personnel. Typical roles involved in operating the equipment are described in the following section. Turn-key Engineer:

Operations Engineer:

Integrity Manager:

Maintenance Manager (Regular):

Maintenance Manager (Non-regular):

The turn-key engineer delivers the finished product to the operating personnel. He also coordinates, supervises, and conducts operations to demonstrate that the equipment is delivered in good condition. The activities include hydrotesting, dehydration after hydrotesting, and filling the infrastructure with inert gas. It is also this engineer’s responsibility to ensure that the equipment or infrastructure is not subjected to any adverse conditions during the turn-over process. This engineer should also be the point of contact for obtaining all documents prepared and used during the design and construction of the equipment or infrastructure. The operations engineer takes care of day-to-day operation of the equipment or infrastructure. It is this engineer’s responsibility to obtain the equipment and relevant documents from the turn-key engineer. He ensures that the equipment functions properly and meets its intended purpose. He/she also interacts with the integrity manager and maintenance (regular) manager to ensure that the equipment or infrastructure is serviced and maintained as per the prescribed procedure and as per the schedule. The operations engineer should have good knowledge of corrosion. The integrity manager ensures the integrity of the equipment or infrastructure. Depending on the situation, the integrity manager analyses and manages risk from corrosion, operational (e.g., hydrate formation, wax deposition) mechanical or third party damage (natural (e.g., hurricane) or man-made), geotechnical (e.g., scope movement, telluric current), structural, and other sources. Among the operations personnel, the integrity engineer normally has the best knowledge of corrosion. Depending on the industry sector, the size of the infrastructure, and on the extent of maintenance required, there may be one or more designated maintenance managers. This person should oversee the regular maintenance of the equipment or infrastructure, and should document the activities in collaboration with the integrity manager and operations engineer. If the infrastructure is undergoing major repair or rehabilitation, a temporary maintenance manager may be appointed to oversee these activities. Usually the regular maintenance manager’s function includes this responsibility. However if the project is large or if there is no regular maintenance manager, such a person may be appointed. The non-regular maintenance manager defines, conducts, and documents the maintenance activities, in consultation with integrity, maintenance, and regular maintenance managers. (Continued)

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dContinued Purchase Officer:

Manager During Change:

Compliance Engineer:

During operations, several parts and accessories are required. The purchase officer buys, stocks, and inventories them and supplies them to the maintenance crews as required. During operation, the infrastructure may undergo several changes. It is important to manage corrosion control during these changes. The manager during change ensures that change does not impact the integrity of the infrastructure, develops procedures for the change, implements an effective management of change (MOC) process, maintains integrity of the equipment or infrastructure during change, and documents the maintenance records. Several sectors of the industry are governed by different regulatory bodies. The compliance engineer keeps abreast of regulations, ensures that the activities are in compliance with appropriate regulations, evaluates the impact of any noncompliance, and submits documents to regulatory bodies to meet compliance requirements.

As discussed in the design and construction section, the personnel involved in the operations may differ from company to company, or from sector to sector. Depending on the nature of the activity, a single person may perform multiple functions, or a single function may be performed by multiple persons. The crew that was involved in the design and construction stage may also be involved in operation. Whatever the situation, it is important that the persons involved are knowledgeable about corrosion. It should also be realized that the corrosion knowledge of persons performing different functions may be different. Figure 13.3 provides the general spectrum of corrosion knowledge of various persons. This information was developed from informal discussions with various personnel in the industry. Though the information is not based on a scientific survey, it illustrates the diverse range of people involved in corrosion control.

13.3.1 Capacity The first and foremost requirement for implementing corrosion control is to have sufficient persons available to carry out the activities. The oil and gas industry is mature and has a long history; in spite of this no industry guidelines exist to prescribe work-to-people ratios. It would be most useful if some guidelines were available that indicated ‘x’ number of persons would be required to control external corrosion of ‘y’ length of pipeline with less than ‘z’ number of incidents per year or ‘x’ number of persons would be required to produce ‘y’ amount of oil with no incidents due to internal corrosion. Each company, each facility, and each operation is unique. Technological advancements and the availability of electronic gadgets reduce the reliance on human activity; yet humans play a vital role in the oil and gas infrastructure. Therefore, it is important to recognize that if the capacity of workforce is not sufficient, the quality of work suffers. Figure 13.4 illustrates the relationship between the capacity of the workforce and quality of work.

13.3.2 Education It is one thing to have adequate workforce, but another thing to ensure that the workforce knows the basic concepts of corrosion. Educational institutes play a key role in teaching the workforce

817

C on Corrosion Knowledge (High = 5 and Low =0) ce Sp p tu ec al ifi ca D es tio ig n M ne E at ng r er in ia ee ls En r D es gi ne ig n En er Pu g rc ha inne se r Sa Offi ce le r s Q Pe ua r so lit y En n gi ne er W Fi o rk na m nc an e Tu M rn a na -K ey ge O pe r E ra ng tio M in ee ai ns nt M r In En en ai t e gi nt an gr ne en ity ce er an M M ce an an ag M ag an er er ag ( R M er eg an (N ul ag on ar er ) -R d e ur C gu om in la g r) pl C ia ha nc n e ge En gi ne er O th er s

13.3 Workforce

5

4

3

2

1

0

Persons Involved *This figure is not a representation of actual corrosion knowledge of various persons, but an illustration of diverse corrosion knowledge of personnel involved.

FIGURE 13.3 Typical Level of Corrosion Knowledge.)

these fundamental concepts. Corrosion is a multi-disciplinary subject and is being taught to some extent as a part of engineering and science courses. Common engineering courses covering corrosion include material, chemical, environmental, pipeline, mechanical, civil, electrical, metallurgical, and design, and common science courses covering corrosion include chemistry, physics, and environmental science. These courses provide students with the chemical, physical, and engineering principles behind corrosion and corrosion control. The extent of corrosion knowledge which the students graduating from these courses have depends on the length of the course and on the details taught in the course. Figure 13.5 provides a corrosion education pyramid, illustrating the depth and knowledge the person acquires based on different levels of education.11 It is important to offer educational courses focused specifically on corrosion. Table 13.2 lists a few institutes providing specialized degrees in corrosion. This list is neither exhaustive nor exclusive, but it does illustrate the type of corrosion education opportunities available.

CHAPTER 13 Maintenance

Medium

Not-Possible Non-Sustainable

Non-sustainable

Not-ideal

Not-good

Not-preferable

Ideal

Not-preferable

Unacceptable

Low

Quality of Work

High

818

Insufficient

Low

Sufficient

Capacity of Workforce

FIGURE 13.4 Correlation Between Capacity of Workforce and Quality of Work.

Ideal Picture of a Workforce Schooled in Corrosion

Corrosion Education Method

Expert

Academic institutions granting professional degrees Corrosion scientist

Specialist Aware

Knowledgeable

Corrosion engineer Aeronautical, electrical, materials, mechanical, metallurgy, electrical, or chemical engineer and designer Material specifier (architect, builder, designer), maintainer, supervisor, etc. Technologist, plant/equipment inspector, maintainer, manufacturer

FIGURE 13.5 Corrosion Education Pyramid.11

Professional societies and academic and private organizations offering supplemental learning in the form of short courses and distance learning programs Graduates of community colleges and trade schools, professional societies and private organizations offering inhouse and extramural courses, online short courses, and skills training with certification

Table 13.2 Specialized Corrosion Degree Courses Offered by Academic Institutes for Oil and Gas Industry) Course

Length

Degree

Focus

Academic Institute

Corrosion Engineering Corrosion Control Engineering Corrosion: Impact, Principles, and Practical Solutions Corrosion Control

4 year 1 to 2 years

B. Eng. M.Sc.

All aspects All aspects

13 weeks

Distance learning and web-based

General corrosion

4 months (3 hours per week) 4 months

Some course materials on oil and gas pipelines

University of Akron, USA The University of Manchester, UK Corrosion doctors at Royal Military College, Kingston, Canada Carleton University, Ottawa, Canada

1 week 3 days

Short course

Cathodic protection

2.5 days (6 hours/day)

Short course

Corrosion courses

2.5 days (6 hours/day)

Short course

Pipeline basic, intermediate, and advanced, as well as coatings Pipelines, internal corrosion of oil and gas infrastructure, and external corrosion of oil and gas infrastructure

Corrosion and Corrosion Control

)

Oil and gas pipelines

University of Calgary, Calgary, Canada

Pipeline corrosion control

Central Electrochemical Research Institute, India Purdue University, West Lafayette, IN, USA Appalachian University, Boone, NC, USA

This is not an exclusive list, but an illustration of the type of corrosion courses related to oil and gas industry

Oklahoma State University, Stillwater, OK, USA

13.3 Workforce

Pipeline corrosion and its control Underground corrosion Underground corrosion

Optional course for bachelor’s or master’s student Optional course for bachelor’s and master’s students Short course

819

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13.3.3 Training Irrespective of their level of education, it is important to ensure that the relevant person is capable of carrying out the particular corrosion control task. This may be as simple as recording a corrosion potential reading, or as complicated as designing a cathodic protection system. To ensure that the person is capable, has the skill-set and knowledge to carry out a specific task, some kind of formal training or examination may be necessary. The training or examination may be written, oral, simulation, hands-on, practical, or real field work. Such training or examination teaches the person the differences between ‘what does theory say’ and ‘what is possible in real world application’ and prepares the person for real-life situations. Professional associations (such as The National Association of Corrosion Engineers (NACE) International) provide specific corrosion training courses. These are short (typically five days or less) and provide participants with specific knowledge. Increasingly, regulators require the workforce to qualify in such training programs before they can perform specific corrosion control tasks. Personnel, especially new recruits, should also be trained in the company’s corrosion control policy. Further, some equipment manufacturers offer specific training and qualification programs with respect to their equipment. Such training programs are useful because each equipment is unique, and it helps the operator to become familiar with the particular piece of equipment, manufacturer’s manual, and procedures for operating and maintaining it. Standards providing guidelines on operator training include: •

CSA Z662, ‘Annex N: Pipeline Integrity Management Program’.

13.3.4 Experience Whatever a person’s level of education and training; another important aspect in developing knowledge is experience. Many persons gain valuable corrosion control knowledge from hands-on experience, which cannot come purely from education and training. ‘Experience converts boys into men’;12 ‘When a person says that (s)he has 35 years of experience it should be 35 years of learning new things continuously, not 35 years of doing same thing 35 times’.13 With experience and motivation people evolve and function at different levels of agility (Table 13.3).14 An experienced person usually is correct, concise, complete, clear, comprehensive, consistent, certain, logical, unbiased, unambiguous, and independent.15 A person attains such a level based on experience with continuous learning in his or her field of expertise.

13.3.5 Knowledge Knowledge is a property acquired from several sources including education, training, experience, motivation, and one’s own wisdom. Knowledge has three levels:16 • • •

Skill-based: This level of knowledge reacts to an event according to the pre-programmed or pretrained manner. Rule-based: This level of knowledge reacts to an event according to preset rules and does not function outside of pre-defined situation. Reason-based: This level of knowledge is the highest level of human intelligence and can handle unfamiliar situations of which there are no precedence or preset rules.

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Table 13.3 Stages of Development or Levels of Agility of People14 Stage

Percentage)

Attributes

Pre-expert

10

Expert

45

Achiever

35

Catalyst

5

Co-creator

4

Synergist

1

• May function in three orientations: B Explorer e transforms from infant stage to toddler stage with capability to exhibit simple goal-oriented behavior B Enthusiast e acts on impulses (unable to clearly distinguish between imagination and reality) B Operator e regulates impulses, grasps the logic of rules and roles, and conceives and carries out small plans and schemes • Tactical, problem solving orientation • Believes that leaders are respected and followed by others because of their authority and expertise • Strategic outcome orientation • Believes that leaders motivate others by making it challenging and satisfying to contribute to larger objectives • Visionary, facilitative orientation • Believes that leaders articulate an innovative, inspiring vision and bring together the right people to transform the vision into reality • Empowers others and actively facilitates their development • Oriented toward shared purpose and collaboration • Believes leadership is ultimately a service to others • Collaborates with other leaders to develop a shared vision that each experiences as deeply purposeful • Holistic orientation • Experiences leadership as participation in a palpable life purpose that benefits others while serving as a vehicle for personal transformation

)

Based on analysis of 384 managers in USA

In general, experienced people in the oil and gas industry function at the rule-based level of knowledge. This person understands and overcomes industrial, regulatory, organizational, and cultural barriers to promote, manage, and implement corrosion control measures. In some parts of the oil and gas industry such persons are recognized as subject matter experts (SMEs). Some virtues of knowledgeable people include:17 • • • • •

They understand why the solution they propose will find a favorable response and will be implemented. They recognize who the enablers of corrosion control measures are, and who may create barriers. They clarify the magnitude of corrosion issues, risks associated with corrosion, and benefit of implementing appropriate measures. They pick the appropriate timing to propose corrosion solutions to obtain an organization’s focus without distractions. They create an appropriate platform to implement the measures.

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They recognize and manage the risks in the implementation process by breaking the steps into manageable sizes. They engage the right personnel, address doubts, handle teasers, and reach team consensus.

Regulations providing guidelines on knowledge and qualification requirements of personnel include: • • • •

CSA Z662, ‘Annex N: Pipeline Integrity Management Program’. National Energy Board Onshore Pipeline Regulations (Canada), Section 46, Operator Qualification Office of Pipeline Safety (OPS), USA, CFR 49, Part 192, Subpart N: Qualification of Pipeline Personnel (Sections 192.801 to 192.809) Office of Pipeline Safety (OPS), USA, CFR 49, Part 192, Subpart N: Supervisor Knowledge Requirement (Section 192.915)

13.3.6 Quality In general, material performance depends on the material quality and human quality:18,19 • •

Material quality depends on the quality of material itself and its time-dependent deterioration (i.e., corrosion) in the given environment under the prevailing operating conditions. Human quality is irreversibly proportional to human error. Human quality may also be known as ‘functional quality’, ‘human factor’, or ‘human and organizational error’.

Thus, materials performance can be improved by improving the quality of materials and the quality of work carried out by human beings. Methods to improve and account for quality of material are discussed in Chapters 2, 3, 5, 6, 9, and 10. The human quality can be improved by decreasing human errors. Studies and experience have identified that human errors can cause costly corrosion failures.20 A survey on the performance of marine and non-marine structures concluded that more than 80% of their failures may have been caused by human error.21 Another survey on military infrastructure indicated that more than 60% of failures may be due to human error.22 Table 13.4 summarizes types of human errors based on an analysis of 800 cases of structural failure in which 504 people were killed, Table 13.4 Types of Human Errors Causing Structural Failures23 Types of Human Error

Percentage of Occurrence

Insufficient knowledge Underestimating the influence Ignorance, carelessness, and negligence Forgetfulness Relying on others without sufficient control Being in unknown situation Imprecise definition of responsibilities Choice of bad quality Others

36 16 14 13 9 7 1 1 3

13.3 Workforce

823

592 people injured, and millions of dollars of damage occurred.23 These errors may be broadly classified into ‘commission errors’ or ‘omission errors’: • •

Commission errors occur due to wrong actions carried out by an individual. Omission errors occur due to an individual not taking proper action.

One approach to avoid human error is to automate the process or activity. A workforce, i.e., people, is superior to machines, equipment, and infrastructure in terms of knowledge, logic, and analysis. If they function properly, the quality of work is maintained and premature failure does not occur. But when carrying out the same process/action repeatedly humans tend to make mistakes, therefore more or more processes are automated. As discussed in section 13.2.2e, knowledge, processes or activities based on skill-based knowledge and, to some extent, rule-based knowledge are suitable for automation. Humans develop, interact, and control the automation. Therefore, consideration should be given to human intervention and human error even for automated processes. Human beings function in a complex way, behave in a vastly different manner, make decisions that may be unpredictable, and do not react well to criticism and to cataloging the way they may commit mistakes.24 Therefore, quantifying human errors is difficult and may be impossible. Equation 13.1 presents a simple definition of quantifying human error: HEP ¼

NOE NoOFE

(Eqn. 13.1)

where HEP is the percentage of human error, NOE is the number of errors, and NoOFE is the number of opportunities for error. From Eqn. 13.1 it is obvious that human error can be minimized by reducing the opportunities for error to occur. Human error may be reduced by regulatory, organizational, procedural, and individual measures. Regulatory: Many sectors of the oil and gas industry are regulated. The regulators may require that certain measures are taken to ensure the integrity of the infrastructure, and such regulations may prescribe certain measures to reduce human error. Such regulations may prescribe guidelines for the qualification and responsibilities of various personnel and chain of command between them. They may also require that the personnel responsible for various elements of integrity management program are identified and documented. Such regulatory guidelines ensure that the people are aware of their responsibilities and the consequence of not following regulations. These guidelines to a large extent reduce both commission and omission errors. Some regulations that provide guidelines include: • •

US Code of Federal Regulations (CFR), Title 49, ‘Transportation’, Parts 192–195. CSA Z662, ‘Oil and Gas Pipeline Systems’.

Organizational: Human errors can be reduced by effective organizational structure. A few quotes regarding failures that resulted from lack of good organizational oversight follow:25 •

•

‘Had the accident pipeline not been weakened by external damage, it likely would have been able to withstand the pressure that occurred on the day of the rupture, and the accident would not have happened. The company inadequately inspected excavation and consequently failed to identify and repair the damage done to the pipeline’. ‘The in-line pipeline inspection data provided to the company, along with the excavation activity the company knew occurred in 1993 and 1994, were sufficient to justify the excavation and

824

•

•

• • •

• • • • • •

CHAPTER 13 Maintenance

examination of the pipeline in the area of reported anomalies, but the company did not perform the work and thus did not identify the true extent of the damage’. ‘If the Supervisory Control and Data Acquisition (SCADA) system computers had remained responsive to the commands of the controllers, the controller operating the accident pipeline probably would have been able to initiate actions that would have prevented the pressure increase that ruptured the pipeline’. ‘Had the SCADA database revisions that were performed shortly before the accident been performed and thoroughly tested on an off-line system instead of the primary online SCADA system, errors resulting from those revisions may have been identified and repaired before they could affect the operation of the pipeline’. ‘The company failed to test, under approximate operating conditions, all safety devices associated with the product facility before activating the facility’. ‘The company failed to investigate and correct the conditions leading to the repeated unintended closing of the inlet block valve’. ‘Had the company investigated the failure of relief valve to operate consistently and prevent closure of the inlet block valve, it would have discovered that the valve was improperly configured, and it could have taken steps to correct the condition that may have prevented the pressure surge that ruptured the pipeline’. ‘Failed to ensure that qualified personnel perform internal corrosion control procedures’. ‘Transported corrosive gas without taking proper preventive and mitigation steps’. ‘Failed to communicate to appropriate personnel when excessive water content was in the gas stream’. ‘Failed to perform necessary tests for corrosion’. ‘Failed to follow procedures for continuing surveillance of its facilities’. ‘Failed to take action to minimize the possibility of a failure following a similar incident’.

To avoid such kinds of failures, and to minimize human errors, the organization must develop and implement a systematic, comprehensive, and proactive process to maintain safety and integrity. Such a process must include a written document describing the corrosion policy, organizational structure, and responsibility of persons. Depending on the oil and gas sector and on the company, the policy may vary. Some typical policy statements may be: no leak irrespective of cost; no harm to employee; no harm to environment; no harm to public; meet regulatory requirements; meet stake-holder requirements; or no loss of production or operation. The policy document must describe the objectives and practices of corrosion control; how corrosion policy integrates with other policies of the organization; how committed the organization is to complying with the requirements of the policy; the framework for establishing, implementing, and reviewing the objectives; how the policy is communicated; how everybody in the organization is brought into the policy; and how it will be periodically reviewed and improved. The policy document may be in the form of chart indicating the chain of command, identifying key functions, and responsibilities of various positions. Procedural: Developing organizational policy is relatively easy, but implementing it may be difficult. For this purpose a procedural document is useful. This describes how the policy is to be implemented and ensures that policy does the job it is intended for. The procedural document is a distinct, comprehensive, and detailed written procedure. It details the procedure for each activity;

13.4 Data

825

identifying the purpose of the procedure, roles and responsibilities, competencies and experience of appropriate person, flow of work, timing, frequency of action, documentation of the process, documentation of deviation if any, and maintenance of records. Table 13.5 provides examples of procedurebased documents.26 Individual: The success of each and every activity depends solely on the individual who puts their hands on the job. Whatever other measures taken, unless the individuals are motivated27 and execute the work properly, the integrity of operation is compromised. Individual behavior is challenging to control. The mood of the individual may vary. In a way, the status and mood of the person at the time of executing the work influences the quality of the job. A calm skilled person with enough time to perform the job normally does a better job than a hurried, unskilled person with less time. It is important that the supervisor takes time as frequently as possible to talk to, listen to, babysit, understand, groom, coach, tutor, appreciate, recognize, and empower individuals. Ideally the supervisor should meet with the project team every week to share what he did the previous week, to listen to what other team members did the previous week, tell what he plans to do next week, and listen to what they plan to do next week. These meetings do not last long if everybody is on track with their work and if there are no major issues. From the body language of the person and from the manner in which they present the work, it is usually possible to understand the state or mood of the person; those who did not do the work usually talks a lot, or complains, and meeting them individually may help to understand the real issues bothering them. Work related issues may be addressed mutually, but some personal issues may be beyond the scope of the employer. The confidence that somebody is there to support may motivate the individual to focus on the work to the extent that is possible in spite of other distracting issues.

13.4 Data Many corrosion control activities require or produce data. Depending on the operation, voluminous quantities of data may be produced. The questions then concern the type of data to collect, at what frequency, where to store them, how to store them, how to retrieve them, how to analyze them, and how to integrate them into useful information.28 Some data collected, on the other hand, need not be stored at all and may be discarded after initial analysis. Corrosion control activities may also require data collected by other personnel within or outside the company. Such data, when available to the corrosion engineer on time, in a user-friendly format, and without excessive additional cost, will be valuable in decisions about mitigation, monitoring, or maintenance activities. This section discusses data collection, data collection modes, data verification, databases, data structure, data processing, data output and display, and data storage.

13.4.1 Collection One quote with respect to data collection is ‘Let us collect everything – are you nuts? Everything big is not necessarily better. Establish data collection based on data that provides most useful information, ability to analyze the data, corrosion feature growth, remaining life of the infrastructure, and cost– benefit analysis’.29

Procedure Outline

Generic

Specific (e.g., Coating applicator approval process)

1

Purpose

• Approval of applicator to apply coating

2 3

Scope Responsibilities

• Why this document is required • What does it apply to • Who (what positions) are all involved in the job? (What are the activities/ competencies required?)

4

Activities

• What is to be done

5

Approval

• Who approves it

6

Documentation

• What is to be documented (signature)

7

Records

8

Frequency of activity

9 10

References Supporting documents

• Where is the document stored • How often should this activity be carried out • Previous similar activities • Standards, in-house procedure, and any other relevant material

• All coating work and vendors • Coating engineer (knowledge of coating; specifies the coating requirement and describe the application requirement) • Procurement department (calls for tender to identify suitable applicator and executes contract) • Supervisor (able to manage persons of different competencies; schedules the project activity and is the point of contact for both the applicator and the in-house personnel during the project execution stage)) • Project department (to provide support when the coating applicator does the job; the kind of support should be identified at the contract stage and the support should be coordinated through the supervisor during the project execution stage)) • Identification of coating need, pre-qualification of applicator, tender process, review and approval of vendor; and documentation • Coating engineer in consultation with project team (identified in section #3) • Evidence that all responsible persons (identified in section #3) have been bought into the activity, i.e., signed document • As an example, electronically stored in (identification of folder) or paper copy is stored in (identification of location) • How often should this activity be carried out • Previous similar activities • Standards, in-house procedure, and any other relevant materials

) They do not function at the approval stage, but should be involved in the approval process so that when the contract comes in to perform the job they are able to execute their responsibilities

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Section

826

Table 13.5 An Example of a Procedural Document26

13.4 Data

827

Data collection is the most tedious, difficult, and expensive activity. Some typical issues include: • • • • •

Availability: data of interest is not collected or collected infrequently or randomly, and records of data incomplete or inaccurate or inaccessible; Location: data may be in the office, in the field, in an offsite facility, or in a virtual server; Form: data may be in a paper form, in a database, in a spreadsheet, or in a software format that is no longer supported; Format: the same data may be stored in more than one location in different formats; Change: reference point changes (e.g., a pipeline being referenced as isolated may no longer be isolated if buildings are built nearby; and variation in the data itself) and property change (e.g., inhibitor to control corrosion may be changed over time, but the data indicates only a generic name. Therefore the effect of different corrosion inhibitors cannot be ascertained).

A simplified approach for collecting data should be devised and executed. Otherwise the data collection activity may never be successful. Before starting to search for data, three criteria should be identified: • • •

What are the most important data? How accurate should they be? Are they collected by another group within the company?

It would be wonderful to collect as much data as technically required, but the cost of collection them and support within the organization should first be established. For this reason, the most important data needed should be identified first, and this should be prioritized. Development of a scheme for evaluating of each dataset will be useful. With this scheme only sufficient data is collected to make informed and reasonable decisions on the integrity of the infrastructure. The scheme may also consider collecting the data in a modular fashion so that overall decisions can be taken with minimal data. As people, organizations, and corrosion engineers become knowledgeable and see value in collecting the data they will support the collection of additional data. Once the type of data to be collected is identified and prioritized, the required accuracy should be established. For example, if the data collected is the concentration of a corrosive species, it may not be necessary to determine it to the fourth decimal point on a milligram scale. A range of concentration will be sufficient, as long as the variation is within the boundary established. As discussed in Chapter 4, the pitting corrosion rate of carbon steel, in some situations, varies between 0 and 100 mpy for variation of chloride ion concentration between 10,000 to 120,000 ppm. Therefore, it is sufficient to collect the data on chloride ion in the  1000 ppm level of accuracy. Once the type of data and its accuracy are established, it is cost-effective if an in-house search is first conducted to determine the availability of the data. Ideally, the data required is already being collected; for example a corrosion engineer needs temperature data and in most companies, this may be collected by operating purposes. If the appropriate person in the operations team is aware of the importance of the data they collect, they may share them. They may even be willing to spend additional time to collect the data in the format and frequency required by the corrosion team. Such an arrangement may enable collection of useful data without extensive operational changes and without extensive addition cost and effort. Of course if the data required is not being collected by anybody, then arrangement should be made to collect the data for the purpose of corrosion control.

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13.4.2 Collection modes Modes in which the data are collected include: • • •

•

•

•

•

Manual random: The data is collected manually by an operator if the person accesses the infrastructure for some reason. No frequency is established for such collection. Manual regular: The data is collected manually by an operator at preset intervals of time. Historically, most data were collected in this way. Automatic random: The sample or data is collected automatically by machine without the intervention of an operator, but the frequency at which the data is collected is not established. In this mode, the sample may be collected automatically but may be processed manually. Automatic regular: The sample or data is collected automatically by machine or equipment at preset intervals without operator intervention. Most automatic devices can easily be set up to collect data regularly, but they have limitations in terms of data storage, collection frequency, and capacity. If these devices are not properly maintained (e.g., data downloaded regularly to free space), they will stop collecting data. Online random: The data is collected and processed online-as it is collected. This mode is slightly more advanced than the automatic random mode, because the data point is processed instantaneously. Online regular: The data is collected and processed online and in real time at preset intervals of time. As in the case of the automatic regular mode, if the machine is not maintained properly it will stop collecting data. Online continuous: The data is collected and processed online - as it collected. This mode is the most sophisticated and best method of collecting data, but it generates large amounts of data. For this reason, the data may be immediately processed and only abnormal data is stored.

13.4.3 Verification Section 12.4 discusses the precautions to be taken before using data collected by others for corrosion control purposes. It is important that the accuracy of data should be verified before processing them. In general the data may be verified at three levels:30 •

•

•

The data are simply entered either manually by those who collect the data or automatically by the equipment that collect the data. The data may be spot checked by the operator, supervisor, or equipment. This method is simple, low cost, but has some errors associated with it. Depending on the accuracy of data required these errors may be tolerable. The data are reviewed by a third party – normally a person entering the data in the database or a designated review person – before being entered into the database. The reviewer may be employed within the company or outside. In this process, if necessary, the doubtful data are sent back to the person collecting them for verification and clarification. This process vastly improves data quality, but may be time consuming. The data are thoroughly reviewed and debated by a peer group before they are entered into the database. This is the highest level of verification and is the most costly. This type of verification is performed for entering data into a database that are used for design purposes, e.g., a material property database, and is not usually performed for data collected during operation.

13.4 Data

829

13.4.4 Databases Once the data has been collected, the next logical step is to arrange them in a database so that they can be effectively and easily used by several people.31 The amount of data may be voluminous, but the dataset must be limited to only those data that are relevant. The general content must be established at the design and development stages of the database, so that all the information the user will seek are included, and information which the user will never require are not included. A database helps to maintain knowledge within the company as people move between different positions. Development of a useful database requires leadership within the organization, formation of a multidisciplinary team, partnership among the team, ownership by the participants, cost–benefit analysis, and communication between developers and users. Databases may be paper-based (further processing of data is not possible), electronic word-based (processing is difficult), or electronic spreadsheet based (processing is easy). A company may use several databases for various reasons. They may use several standalone databases (with each database dealing with one specific aspect, e.g., corrosion) or integrated (e.g., one database dealing with all aspects of integrity management or all aspects of company information). Harmonization or integration of databases is useful, since it increases the efficiency of data collection, sharing, and management. It should be realized that scientific or technical databases are fundamentally different from nontechnical or business databases. In a non-technical or business database, the data is 100% accurate (e.g., a bank account). On the other hand, the data in a scientific or technical database may be a single value (if a parameter is measured once), a range (if the parameter is measured several times), or an estimate (based on experiments or knowledge from similar situation). Thus, a technical database should logically arrange data from various sources (overcoming imprecision of the data and missing data) to provide the user with a tool to use the information easily, effectively, and quickly. Standards providing general guidelines for developing databases include: • •

API 1160, ‘General guidelines on data management requirements’. ASME B31.8S, ‘General guidelines on data management requirements’.

13.4.5 Structure Data collected in the database should be arranged in a structured way,32 so that they can be retrieved, analyzed, and useful information obtained from them. There is no single, universally acceptable method for structuring databases, but the data structure must have the following three characteristics as a minimum: •

•

No two parameters are identified with same name (or same symbol), nor is the same parameter identified by more than one name. For example, the symbol ‘t’ may commonly be used to represent temperature or time. But in the database one abbreviation is used to represent only one parameter. On the other hand, pressure may commonly be abbreviated as Pres. or press. Either of these abbreviations can be used but only one should be used consistently throughout the database to refer to pressure. There is only one unit per parameter; for example, if temperature is recorded in two units (Centigrade and Fahrenheit), the values should be converted into one unit in the database. It does not mean that the database uses only one unit for temperature, but means that all temperature

830

•

CHAPTER 13 Maintenance

values are present in one unit at a time with the option of converting all temperature data into another unit if necessary. Relationships to a critical reference point are not lost or accidentally deleted. For example, many data about a pipeline may be referenced with respect to main line valve or compressor station. The unique identification or the name of the reference should be retained in the data structure; otherwise the whole dataset will become useless and any analysis based on the data will be erroneous.

13.4.6 Processing Data is of no use if it does not provide useful information. Data in the database is processed to provide status of the infrastructure, trend of its behavior, and recommendations for maintenance activities. The data processing can be performed manually or automatically. Several methods are available to process the data, including threshold-based, logic, statistical analysis, weighing framework, model based, computational, and expert system. •

•

•

•

•

•

The threshold-based approach is the most simplistic and easy; here the data are used to determine whether a particular property has reached a preset threshold. Some common data used include remaining wall thickness of an infrastructure or dry-film thickness of the coating. The logic approach is also known as the common-sense or qualitative approach. The data is analyzed by a person (e.g., SME) knowledgeable about the operation to determine the status of the infrastructure. No guidelines on how to analyze the data can be formulated but the logic is developed based on knowledge, experience, and familiarity with the system. Though this approach was prevalent in the early days of the oil and gas industry, it is slowly disappearing. The statistical approach may also be known as quantitative approach, and here the data is analyzed using statistical tools including analysis of variance (Anova), correlation, covariance, descriptive statistics (mean, median, standard deviation, kurtosis, mode, and skewness), exponential smoothing, Fourier analysis, histogram, moving average, random number generation, regression, sampling, and extreme value analysis (Weibull and Gumble statistical analysis).33 The weighing framework is also known as semi-quantitative approach, and here, various parameters are given a score and the total score is calculated. The scoring for the parameters may be adjusted depending on the data and other information. The total score is used to categorize the infrastructure in a range from those requiring immediate maintenance to those that do not require any maintenance. In the model-based approach, the data is analyzed using a scientific model. Chapters 6 and 10 discuss models to predict internal and external corrosion. These models are used to determine the status of the infrastructure. It is obvious that the database must contain input data required by these models for this approach to be successful. There is an increasing trend in the oil and gas industry to analyze data using scientific models. In the computational approach, the data is analyzed using scientific first principles. With advances in computer processing technology, several attempts are being made to develop a computational approach of problem solving and trending. This is a very sophisticated approach and is being

13.4 Data

•

831

used to understand unique corrosion features, e.g., corrosion over the bend of heavy oil transmission pipelines.34 For many practical reasons, all relevant field data may not be available. In such cases, expert systems such as artificial neural networks (ANN) may be used to fill the gap.35 Such expert systems must first be trained using complete data. Once trained, such systems may be used to analyze data with gaps to produce a trend. However, expert systems have not yet been accepted in the oil and gas industry.

13.4.7 Output and display Once the data is processed, the results can be output in several ways. The output may be isolated or a part of an integrated network. In the isolated mode, the result may be presented in the paper report/ form, by phone call, as a fax, or using electronic media (such as spreadsheet, graph, or email message). In this mode, the corrosion engineer obtains the end results and determines suitable action. In the integrated network, the data is processed and the end result is used to trigger the appropriate action automatically. Normally the corrosion engineer is also informed of the type of action being implemented. In order to execute this chain of events, the data should be entered into the database as they are generated, the database should be analyzed as the data becomes available, and the database should be programmed to take appropriate action. Some attempts have been made to link the data generated by online measurement techniques with process control.36 There are several ways to display the data. The end-user determines or approves the interface between the data and him/her. Depending on the data, they are displayed as text, tables, spreadsheets, or graphs. Most often the displayed data may be conveniently exported to another suitable media.

13.4.8 Storage Data may be stored on paper (hard copy), in standalone computers (e.g., main frame computers), and on web-servers. In the past, the data were stored only in the paper form. Paper storage occupied lots of space and hence the data was stored in offsite locations. This approach makes access to data difficult. Nowadays sophisticated electronic media are available that can store large amounts of data in a small space. Small amounts of data are often stored in spreadsheets in a standalone computer. They can be transmitted and shared through email or other electronic transportation methods (e.g., memory stick and, CD). Nowadays commercial network databases are increasingly available which help sharing a single database with many people. In addition more and more servers are available to store and share data on the web. ‘Trying to assess the true importance and function of the internet now is like asking the Wright brothers at Kitty Hawk if they were aware of the potential of American Airlines Advantage Miles. The internet and the web are changing the way we live and interact in novel ways that are hard to predict. One area where the web is going to make a lasting impact is how we exchange information. In that context, web-based data storage and sharing is here to stay and will grow. How far it can go and how much it can offer, in terms of a different and improved perspective is as certain as it is nebulous’.37

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The role of the web in promoting and supporting completely internet-based data storage and sharing should not be underestimated. The corrosion professionals should successfully adopt and adapt this tool.

13.5 Communication Communication, cooperation, and coordination are interrelated. Effective, proper communication increases the probability of cooperation between different groups and increases the probability of implementing a coordinated corrosion control practice. Communication happens in four ways: human to machine, machine to human, machine to machine, and human to human. For the most part, the communication between the first three entities can be maintained relatively easily and any problems with it can quickly be diagnosed and corrected. It is the human to human communication that is difficult to maintain unless conscious efforts are taken. Effective human to human communication may be the single factor that determines the success or failure of corrosion control. A proactive and proper communication increases the probability of success of corrosion control and the probability that others will ensure that best corrosion control practices are implemented. On the other hand, ineffective, improper communication may not only increase the probability of corrosion but also may amplify its negative effects. With respect to communication we should realize that: •

‘What we say (write), what we mean, what they hear (read), and what they understand may be four different things’.

Communication is not a one way street, i.e., it is as important to listen (read) as to talk (write). Hence the reverse is also true: •

‘What they say (write), when they mean, what we hear (read), and what we understand may be four different things’.

The above is true even when the communication happens in one language; as one SME points out; ‘English to English translation is important’.38 There are several communication media, including personal face-to-face verbal, group meeting, letter, telephone, fax, email, bulletin board, webpage (specific), webpage (generic, e.g., Twitter, Facebook), and text. Communication is not just talking, listening, writing, and reading but it includes gesture, body language, recognizing the culture, and recognizing the rule of the land. The corrosion professional should maintain communication with the corrosion team, the integrity team, senior management, suppliers, workers, regulators, stakeholders, subordinates, peers, general public, and the media. Some attributes of successful communication strategies are described in the following paragraphs.

13.5.1 Self It appears silly to discuss communication with one’s self, but it should be recognized that if we do not communicate and maintain our own schedule/plan it will be difficult to enforce that on others. Some common items for self-communication include work-plan, goals, responsibilities, commitment (personal, career, and recreational), meetings, travel, and other interests. If these items are entered in a

13.5 Communication

833

calendar or in a form that is visible, it will help us to recognize how much time has already been committed, how much time is left for new commitments, and how to balance various activities.

13.5.2 Corrosion team The core corrosion team may be just one person or a group of persons. Depending on the size of the company and the importance attached to corrosion, this team may be a separate entity or may be a part of the integrity team. Communication within the corrosion team should: • • • • • • • • • • • • •

Build credibility and trust Articulate clearly the main corrosion issues Consider a cooperative approach that identifies, includes, accepts, and involves all interested parties or expertise, i.e., a multi-disciplinary team structure Provide lead time for parties to understand and reflect on the issues Listen to solutions from different parties, recognizing that people would like to be involved in the decision-making process rather than in decision-implementing process Develop a workable solution together in an open, honest, and frank manner after considering all options Respect people’s time Develop an implementation strategy Identify the players, i.e., who is going to do what Obtain commitment from all parties Monitor the implementation Sought feedback on lessons learned and Evaluate strategies and make improvements

13.5.3 Integrity team As discussed in section 13.5.2, corrosion team may be a part of integrated team or may be a separate unit. The communication within the integrity team with respect to corrosion should: • • • • • • • • • •

Explain the risk of corrosion and benefits of corrosion control Articulate corrosion solutions and steps to implement them Understand other integrity related issues and needs Negotiate and develop solutions that address all integrity issues Develop common implementation strategies and time-frames Introduce corrosion implementation players and articulate their role Obtain commitment from all parties Monitor the implementation Seek feedback on lessons learned and Evaluate strategies and make improvements

13.5.4 Subordinates Depending on the company, there may be several positions equivalent to that of corrosion engineer. These positions and their functions are just as important. It is important for the corrosion engineer to be in tandem and in rapport with other subordinates, so that they understand and recognize the importance

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of corrosion control. Corrosion control activities should be in sync with other operational requirements. For this reason, communication with subordinates should: • • •

•

Indicate hazards due to corrosion, i.e., what could go wrong. Inform about symptoms of hazardous situations, e.g., increases in noise level, pressure fluctuation, and valve malfunction. Explain precautions to prevent and minimize activities causing hazardous situations, e.g., stopping corrosion inhibitor injection or switching off cathodic protection current during other maintenance activities and forgetting to turn them back on. Seek consideration for corrosion control activities during emergency response planning and execution, i.e., ensure that the importance of corrosion control is not forgotten during emergency situation.

13.5.5 Senior management Depending on the company structure, the corrosion team may communicate directly with senior management or through the integrity team. Whatever the route is, communication with senior management with respect to corrosion should: • • •

Indicate cost-benefit analysis, i.e., corrosion cost is not an expenditure but a saving for the future. Identify regulatory requirements, standards requirements, and environmental requirements. Explain how corrosion control measures meet corporate policy and make positive contributions to the corporate image.

13.5.6 Suppliers and service providers Depending on the type of service and company policy, the corrosion team may interact with suppliers and service providers either directly or indirectly, e.g., through tender. The communication with suppliers and service providers should: • • • • • •

Indicate the service requirement and the timeline at which it is required Identify the minimum acceptance criteria Obviously include cost Importance of their service Provide feedback of their service and of the performance of their products including advantages and limitations Recommend areas of improvement based on the experience

13.5.7 Workers Workers who put their hands on wrenches, valves, flow meters, switches, and other parts of the infrastructure play the most critical role in ensuring that corrosion strategies are properly implemented. Communication with workers should: • • •

Make sure they understand the nature of the work Provide clear procedures for their work Indicate the time it should be performed and it should be completed

13.5 Communication

• • •

835

Explain the importance of their work in controlling corrosion Motivate them to provide their best – plus 10% more. As one SME points out ‘motivation of the worker is the most critical aspect of corrosion control’27,39 Transfer knowledge continuously from the experienced to the novice40

13.5.8 Regulators Regulators are independent of the industry and are the sources which provide objective, effective, clear, and unbiased guidelines to develop and implement corrosion control strategies. They play a critical role in balancing industry requirements and public expectations. The better they can exercise and exhibit their independence, the better they serve both the industry and the general public. Communication with them should support their role and should: • • •

• • •

Acknowledge the regulator’s mandate. Exhibit the company’s knowledge of rules and regulations, as well as its responsibilities and commitment to meeting them. Highlight the company’s leadership in implementing, following, and exceeding the rules and regulations set by the regulators as well as the guidelines and best practices developed by the standard developing organizations. Describe appropriate emergency response measures. Describe incidents, if any, due to corrosion, and explanation how and why corrosion control measures failed, lessons learned, and steps for moving forward. Explain the cumulative environmental and societal impacts, if any, of corrosion including who were adversely affected, directly or indirectly.

Some guidelines on communication between regulators and companies are described in: • • • •

Alberta Energy Regulator (AER) Guide 56, ‘Requirements for Participant Involvement’. AER Guide 71, ID 2001-5, ‘Requirements for Emergency Preparedness and Public Consultation’. National Energy Board (NEB), Onshore Pipeline Regulations (1999), Emergency Preparedness and Response (EPR) Program: Continuing Education & Liaison Programs. CSA Z731-03, ‘Hazard Identification, Assessment, Emergency Planning’.

13.5.9 Peers Peers are those who carry out similar activities in a different company. They may have faced similar corrosion situations and may have solved the issues or may face similar issues and may look for solutions. Most corrosion professionals in the oil and gas industry are members of industry or subject specific associations. These associations may develop standards, best practices, or just provide a platform for discussing common issues. Some well-recognized professional associations active in the oil and gas industry that deal with corrosion include: • • • • •

NACE International ASTM G01: Corrosion Sub-Committee Society of Protective Coating (SSPC) Canadian Standards Association (CSA) Canadian Energy Pipeline Association (CEPA)

836

• • • • • • • •

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Canadian Association of Petroleum Producers (CAPP) Small Explorers and Producers Association of Canada (SEPAC) Canadian Crude Quality Technical Association (CCQTA) Pipeline Research Council International (PRCI) Interstate Natural Gas Association of America (INGAA) Banff Pipeline Workshop International Pipeline Conference (IPC) Oil Sands and Heavy Oil Materials and Integrity Workshop (OSHOW)

In general the communication with peers should • • •

• • • • •

Recognize that one company’s corrosion failure would affect others. Provide networking and partnerships opportunities. Include ‘what are you doing now’, ‘how are you doing it’, ‘what issues are you facing’, ‘are others facing similar issues’, ‘how others are dealing with these issues’ and ‘what is the best way’ to overcome the issues. Enable development and deployment of standards, best practices, and guidelines. Help to develop mechanisms to adopt and use best practices uniformly across the industry. Facilitate promoting corrosion awareness within the industry. Support enforcement of regulations on operators who do not maintain industry standards and best practices. Help developing strategies to collectively face the public and media.

13.5.10 Stakeholders Stakeholders have some interest in the company and in the industry, or have interest in the community in which the company and industry is located. They may have knowledge of and influence on the local community. Their involvement and input may provide solutions to social issues. They may be a local person or an organization. The stakeholders should be identified and profiled, i.e., who are they, what are their mandates, where do they operate, and their membership if applicable. They may have no technical knowledge of corrosion, but may fear its consequences. Therefore the communication with stakeholders should: • • • • • • •

Include an assessment of their skill level Foster a climate of cooperation Educate (e.g., giving a tour of the facility to explain how corrosion is being controlled, and demonstrate the early warning system) Be friendly, and cordial Be timely, open, accurate, honest, and relevant Identify the real issue and respond to it Overcome cultural and language barriers

13.5.11 General public The oil and gas industry personnel need to interact with the general public. The public are becoming more and more aware of the industry. Depending on the sector, the size of the company, and its policy, the corrosion engineer may or may not communicate directly with the public. In general, the corrosion

13.5 Communication

837

engineer is required to deal with the general public when an incident happens due to, or perceived to be due to, corrosion. It should be realized that the best technical communicator may not necessarily be the best communicator with the public. The information, expectation, and wavelength for these two types of communication are different. Communication with the general public should: • • • •

•

•

Assume that the average public read and write at a lower level than people working in the industry. Involve the public as early as possible; proactive communication before an incident happens may be difficult but is more effective than communication after an incident. Build trust through effective relationships, admit to a mistake if it occurred, and make a commitment to ensure that it does not recur as well as explain why it does not occur. Not overwhelm them; for example if several companies are involved on same activity, (e.g., drilling in a community) and if they all communicate with the public separately on same issue, the public will be overwhelmed with the information. In this situation one point of contact for the whole industry rather than contacts for each company is preferred. Sometimes the best people to communicate are employees who live in the community. Be aware of different perspectives. For example, industry is accustomed to assigning risk but the public will not accept any risk when it comes to people. Therefore, a strategy should be established before taking the risk plan to the public. Provide issues of importance (not numbers) and values of importance (not facts).

Some guidelines on public consultation are provided in: • •

CAPP, ‘Guide for Effective Public Involvement’ (capp.ca). CSA Z731, ‘Emergency Preparedness and Response’.

13.5.12 Media Larger failures or failures in the sensitive regions/infrastructure draw media attention. Most of the time, the media dramatizes the situation and portrays the industry in a bad light. Often the reporting is unbalanced, biased against company, and adversarial in nature. Once the media is involved, some response from company, industry, regulator, and sometimes, government becomes necessary. Regardless of how good the response is, it may be difficult to completely repair the damage inflicted by the media. Notwithstanding all these challenges, communication with the media should: • • •

Present a balanced picture about the situation, especially with respect to corrosion. Display point of contact for information through bulletin board, phone messages, and email autoreply. Include training of appropriate field operators so that they are equipped with dealing with the situation. Field operators are often the first point of contact with the media. It may be prudent for them to direct the media to appropriate communication person rather than communicate with the media directly.

13.5.13 Lawyers and court When an accident happens due to corrosion, any liability may be settled in court. If the responsible persons are found guilty, they may be convicted of criminal as well as civil negligence. Depending on the country in which the oil and gas industry operates and on the extent of damage, technical personnel

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CHAPTER 13 Maintenance

may need to appear in the court to clarify the incident. Technical communication with lawyers in the court should: • • • •

Be well prepared and rehearsed Be to the point and honest Be backed up with documented evidence Only provide answers to the question being asked without speculation or hypothecation

13.5.14 General All the discussions on communication discussed in sections 13.5.1 through 13.5.13 are mainly between corrosion professionals and other personnel. In addition, several communications (sometimes miscommunications) take place between several people without the knowledge of corrosion. The impact of any miscommunication may be reduced by: • • •

disseminating proactively aspects of corrosion to the extent possible keeping as much information as possible for sharing with general public and media making him/herself available or a designated communication person available to respond to the inquiry; in many situations the non-availability of appropriate contact person spreads the misconception and miscommunication faster

13.6 Associated activities Many corrosion control activities are carried out by associated members of the company. These members include material suppliers, service providers, contractors, SMEs, consultants, inspectors, commercial laboratories, and contract, temporary and part-time workers. They may be associated with the company for a long period of time or they may be called in to carry out a particular job. It is important to maintain relationships with these associated personnel so that their services, human power, and knowledge are available when needed. It is also important that the associated members recognize and understand the corrosion control policies and philosophies of the company, so that their service and work match the company’s expectation. Companies often pre-qualify several service providers to perform some task, e.g., the application of a coating. This happens when the project is so large that no one coating applicator has the capacity to handle it alone. In this situation, it is important to indicate expectations right from the tender stage, so that all coating applicators are aware of them from the beginning and maintain them during the project execution stage. This approach minimizes variation due to different coating applicators.

References 1. Lewandowski K. Key factors in improving maintenance skills. ‘Definition of International Air Transport Association (IATA)’. Maintenance 1990;5(1):22–7. March/April. 2. Bianchetti RL, editor. Peabody’s Control of pipeline corrosion. Houston, TX: NACE; 2001. ISBN: 1-57590092-0.

References

839

3. Niembro AM. Predictive maintenance program of cathodic protection systems in a petrochemical complex, Corrosion 1997. Paper # 555. NACE International, Houston, TX: NACE; 1997. 4. Baron J. How we achieve field-applied girth weld coating quality? Working Group #6: Coatings, Banff Pipeline Workshop. http://banffpipelineworkshop.com/index.php. 5. Goerz K. Maintenance and management of integrity for upstream pipelines. Banff Pipeline Workshop 2007. Internal Corrosion Tutorial, April 1–5, 2007. http://banffpipelineworkshop.com/index.php. 6. Murray A. 2nd Canada-India workshop on pipeline integrity. September 25–26. Canada: Calgary; 2008, http://www2.nrcan.gc.ca/PICon. 7. Hopkins P. Journal of pipeline integrity 2008, as presented by Allan Murray, 2nd Canada-India workshop on Pipeline Integrity. September 25–26. Canada: Calgary; 2008, http://www2.nrcan.gc.ca/PICon [accessed 02.03.13]. 8. Booz Allen report 2007, as presented by A. Murray, 2nd Canada-India workshop on Pipeline Integrity. September 25–26. Canada: Calgary; 2008, http://www2.nrcan.gc.ca/PICon [accessed 02.03.13]. 9. Van De Veer J. Shell, as presented by A. Murray, 2nd Canada-India workshop on Pipeline Integrity. September 25–26. Canada: Calgary; 2008, http://www2.nrcan.gc.ca/PICon [accessed 02.03.13]. 10. Tillerson R. Exxon Mobil, as presented by A. Murray, 2nd Canada-India workshop on Pipeline Integrity. September 25–26. Canada: Calgary; 2008, http://www2.nrcan.gc.ca/PICon [accessed 02.03.13]. 11. Scully JR, 16th International Corrosion Conference, Beijing, China, September 2005, as presented by J. Kish at NACE Northern Area Eastern Conference 2011, Ottawa, Ontario, Canada, Aug. 15–17, 2011. 12. Obeyesekere N. NACE Technical Exchange Group 282 X: Sour Corrosion, Technical Information Exchange, CORROSION 2005, NACE International. Houston, TX: NACE; March 2005. 13. Fitzherald J, Corrosion. 1998 plenary lecture, CORROSION 1998, NACE International. Houston, TX: NACE; 1998. 14. Joiner B, Josephs S. Leadership agility: five levels of mastery for anticipating and initiating change. 989, Market Street, San Francisco: Jossey-Bass, Wiley Imprint; 2007. CA 94103–1741, www.josseybass.com. ISBN: 978-0-7879-7913-3. 15. Dromgool MB. Dueling technical experts. Corrosion 2009, Paper # 9038, NACE International. Houston: TX; 2009. 16. Rasmussen J. Models of mental strategies in process plant diagnosis. In: Rasmussen J, Rousee WB, editors. human detection and diagnosis of system failures. New York: Plenum Press; 1980. p. 241–58. 17. Cooper MGB, Fletcher J. Non-technical solution for technical challenges. Corrosion 2010, Paper # 10189. Houston, TX: NACE; 2010. 18. Trethewey KR, Roberge PR. Corrosion management in the 21st century. British Corrosion Journal 1995; 30(3):192–7. 19. Trethewey KR, Roberge PR. lifetime protection in engineering systems: the influence of people. Materials and Design 1994;15(5):275–85. 20. Hoar TP, Report of the Committee on Corrosion and Protection, HMSO, London, UK: 1971. 21. The Role of human error in design, construction, and reliability of marine structures. SSC-378, Ship Structure Committee,In Washington D.C. US Coastguard; 1994. 22. Trethewey KR, Roberge PR. a knowledge-based structure to improve learning lessons in the military. Corrosion 1996, Paper # 96640, NACE International. Houston, TX: NACE; 1996. 23. Murray A, based on Swiss Federal Institute of Technology Report, 2nd Canada-India workshop on Pipeline Integrity Calgary Canada September 25–262008, http://www2.nrcan.gc.ca/PICon [accessed 02.03.13] 24. Tretheway KR, Roberge PR, Modeling human interventions in corrosion failures, NACE CORROSION Conference 1997, Paper # 325, NACE International, Houston, TX 1997.

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25. Abes J, based on NTSB Pipeline Accident Report PAR 02/02 and RSPA News Release17–01,2nd CanadaIndia workshop on Pipeline Integrity, Calgary, Canada, September 25–26 2008, http://www2.nrcan.gc.ca/ PICon [accessed on 02.03.13] 26. Macdiarmid J, ‘Process and utility corrosion managementpolicy driven and procure based’, NACE, Northern Area Eastern Conference, Ottawa, Aug. 15–17, 2011. 27. Grzyb D. A look at internal corrosion trends. Banff Pipeline Workshop. Internal Corrosion Tutorial, April 1–5, 2007, http://www2.nrcan.gc.ca/PICon; 2007 [accessed 02.03.13]. 28. Ellor JA, Ault JP. Using electronic tools and databases to manage coatings used for corrosion control’, NACE CORROSION Conference 2008, Paper # 8197, NACE International, Houston, TX, 2008. 29. Kwas D. Maintenance and management – transmission pipelines. Banff Pipeline Workshop. Internal Corrosion Tutorial, April 1–5, 2007, http://www2.nrcan.gc.ca/PICon; 2007 [accessed 02.03.13]. 30. Angwin M, Nelsor JL, Syrett BC. Technical database design. Corrosion 1996, Paper # 96366, NACE International. Houston, TX: NACE; 1996. 31. Bowman TJ, Husa EI. A System for storing cathodic protection measurement data. Corrosion 1997, Paper # 97123, NACE International. Houston, TX: NACE; 1997. 32. Raley RE, Wang MC. Data warehouse and data mining techniques airframe for corrosion control. Corrosion 1999, Paper # 99237, NACE International. Houston, TX: NACE; 1999. 33. Skoog DA, West DM, Holler FJ. Chapter #4’: Application of statistics to data treatment and evaluation. In: Fundamental of Analytical Chemistry. Learning, Inc: Thomson; 1996. ISBN: 0-03-00593800. 34. Landry X, Runstedtler A, Papavinasam S, Place TD. Computational fluid dynamics study of solids deposition in heavy oil transmission pipeline. Corrosion 2012;68(10):904–12. 35. Silverman DC. Artificial neural network to predict degradation of non-metallic lining materials from laboratory tests. Corrosion 1994;50(6):411. 36. Kane RD, Eden DA. Electrochemical monitoring of corrosion in sour systems: fact and fiction of electrode bridging, fouling, and other horror stories. Corrosion 2005, Paper # 5637, NACE International. Houston, TX: NACE; 2005. 37. Srinivasan, ‘Evaluation of the efficacy of web-based conferencing for global corrosion information exchange’, PICon paper # 2000-2, http://www2.nrcan.gc.ca/picon/journal/ [accessed 09.03.13]. 38. Teevans P. ‘NACE TG 305 wet gas internal corrosion direct assessment (WG-ICDA) methodology for pipelines’Corrosion 2010, TG 305 meeting, March 2010. 39. Menke J. Corrosion – a ‘people’ solution. Corrosion 2000, Paper # 279, NACE International. Houston, TX: NACE; 2000. 40. Hack HP. Knowledge transfer from experienced to novice engineers. CORROSION 2012 Plenary Lecture. NACE International. Houston: TX; 2012.

CHAPTER

14

Management

14.1 Introduction Naturally occurring hydrocarbons (oil or gas) present underground cannot be directly used as fuel, i.e., they are of low value (see Chapter 1 for more information on the value of hydrocarbons). The primary objective of the oil and gas industry is to convert these lower value natural hydrocarbons into useful fuel, i.e., add value to them (Figure 14.1; top row). The more economical the process is, higher is the economic benefit to the industry. Thus, the profit of the oil and gas industry (POGI) is: POGI ¼ CHCC

ðCHCU þ CLV

HV Þ

(Eqn. 14.1)

where CHCC is the cost of hydrocarbon to the customer, CHCU is the cost of hydrocarbon present underground, and CLV_HV is the cost of converting lower value hydrocarbons to higher value hydrocarbons. CLV_HV includes the cost associated with moving the hydrocarbons through various sectors (see Chapter 2 for descriptions of the sectors) of the oil and gas industry. Each sector incrementally adds value to the hydrocarbons while incurring costs. As presented in Figure 14.1 (top, second row), minimizing risks is one among several activities incurring costs. The risks include improper design, improper operation, corrosion, third party damage, and others (Figure 14.1; top, third row). The industry implements a top-down approach to minimizing the risks in an economic way, i.e., it keeps CLV_HV as low as possible. It is also obvious that the industry does not invest in hydrocarbons with high CHCU unless either CLV_HV is extremely low or CHCC is very high. The normal approach to estimate the risk due to corrosion is bottom-up. First, the material of construction is established (Figure 14.1; bottom, row 1). Carbon steel is the first material of choice and the industry has long experience with it. If carbon steel is found to be inadequate then other materials are considered. Chapter 3 discusses the numerous materials available and the different methods by which they can be classified and characterized. Second, the factors influencing corrosion of materials in different environments are considered. Chapter 4 discusses the main factors influencing corrosion. Third, the mechanism by which the given material may undergo corrosion in the given environment is understood. Chapter 5 discusses different corrosion mechanisms occurring in the oil and gas industry. Based on all this information (material, main influencing factors, and mechanism) as well as past experience with same or similar material environmental interactions, the expected corrosion rate is predicted. Chapters 6 and 10 discuss models for predicting internal and external corrosion rates respectively (Figure 14.1; bottom, row 2). It should be pointed out that ‘corrosion mechanism’ and ‘corrosion model’ are not interchangeable terms. In general, the mechanism provides a theoretical explanation for the particular type of corrosion Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00014-5 Copyright Ó 2014 Elsevier Inc. All rights reserved.

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CHAPTER 14 Management

Lower-value hydrocarbon

Oil and Gas Industry

Higher-value hydrocarbon

Financial issues

Regulatory issues

Risk

Environmental issues

Others

Improper design

Improper operation

Corrosion

Third party damage

Others

Management

Maintenance

Measurement

Monitoring

Mitigation

Model

Materials/ Environment interaction

Main influencing factors

Mechanism

FIGURE 14.1 Corrosion Management in the Context of Oil and Gas Industry Operation.

and derives the rate of corrosion based on fundamental first principles. In contrast, a model is a practical tool to predict a corrosion rate based on carefully conducted laboratory experiments and/or field experience. It is important that the model used to establish corrosion rate is relevant to the actual mechanism of corrosion of a given material/environment combination. For example, a general corrosion model must not be used to predict localized corrosion. An ideal situation is to develop a theoretical mechanism that can be practically applied, but such a model may not be available for all situations.

14.2 Risk assessment

843

The rationale behind using a theoretical mechanism, a practical model, or a suitable combination of both should be established. Figure 14.2 provides a flowchart to predict corrosion rates either from a mechanism or a model. The corrosion rate thus obtained is used to establish the minimum wall thickness required to compensate for corrosion during the operating life, i.e., to establish a corrosion allowance. If the corrosion rate of the material of choice in the given environment is high, a mitigation strategy is established to reduce it to an acceptable level (Figure 14.1; bottom, row 3); Chapters 7 and 9 discuss various strategies to mitigate internal and external corrosion respectively. When the oil and gas infrastructure is in service, it is routinely monitored to ensure that any corrosion is progressing at or more slowly than the predicted corrosion rate (Figure 14.1; bottom, row 4). Chapters 8 and 11 discuss various techniques for monitoring internal and external corrosion respectively. Additional information from other measurements is used to complement the data obtained from monitoring techniques (Figure 14.1; bottom, row 5). Chapter 12 discusses these measuring techniques. Finally the infrastructure is serviced, repaired, and worn-out parts replaced to ensure that it continues to function properly (Figure 14.1; bottom, row 6). Chapter 13 discusses various maintenance activities. Thus, the financial aspect of corrosion control is top-down (Figure 14.1; top three rows), and it balances the requirements of corrosion control activities with those of other equally important activities; whereas the technical aspects of corrosion control are bottom-up, and move intuitively through model, mitigation, monitoring, measurement, and maintenance activities (Figure 14.1; bottom six rows). Corrosion management provides the vital and seamless link between top-down corporate (financial) requirements and bottom-up corrosion team (technical) requirements. In a way, the corrosion management is a combination of art and science to balance financial and technical requirements. It incorporates engineering and business aspects to achieve the goal of long-term stability of the oil and gas infrastructure as well as the enterprise. Corrosion management is a systematic, proactive, continuous, ongoing, technically sound, and financially viable process of ensuring that the people, infrastructure, and environment are safe from corrosion. The responsibilities of corrosion management include: • •

• •

Evaluation and quantification of corrosion risks during design, construction, operation, shutdown, and abandonment stages, and identification of factors causing, influencing, and accelerating them. Establishment and implementation of organizational structure, resources, responsibilities, best practices, procedures, and processes to mitigate and monitor corrosion risks and to carry out maintenance activities. Maintenance and dissemination of corporate strategy, regulatory requirements, finance, information affecting corrosion, and records on corrosion control activities. Review of the successful implementation of corrosion control, and identification of opportunities for further correction and improvement.

14.2 Risk assessment Equation 14.2 presents the most common way of defining risk:1 R i ¼ PE  C c

(Eqn. 14.2)

CHAPTER 14 Management

Collect as many operating parameters as possible

Material of construction qualified for this purpose

Yes

No

Select appropriate material

Yes

No

Environment of operation within range of use of material

Yes

Does the mechanism predict corrosion rate? Yes

Is there a theoretical mechanism that can explain the corrosion failure types based on material and operating conditions?

No

No

No Simulate laboratory experiments by controlling as many parameters as possible

Field failure morphology and corrosion rate reproduced in the laboratory

No

Modify laboratory methodology

Does the predicted corrosion rate within 10% of maximum corrosion rate observed No/ when operating DNK parameters are used as inputs? Yes

Are the values of input parameters used in the mechanism/model the same as data obtained from the field?

No

Yes

Are there any other constants used over and above the input parameters?

Repeat test; results within 10% of first test No

Yes

No

Repeat test two more times; compile all four test results

List constants and their values

Repeat the test at twice the duration of first set of tests (twice or four times depending on repeatability) Predicted rate of corrosion type (uniform or localized); Mean and standard deviation from two time periods are used to project future trend.

FIGURE 14.2 Flow Chart to Predict Corrosion Rate.

Yes

Is there a practical model that can predict the corrosion failure type and corrosion rate based on material and operating conditions?

Yes

Do not know (DNK)

Change operation

Yes

Yes

DNK

No

No Yes

Is the repeatability or reproducibility of data used to develop the model known?

Yes

844

14.2 Risk assessment

Risk remains constant with time. Such risks are due to earth movements and third party damage

Risk increases with time. Such risks are due to corrosion, cracking, and fatigue

Number of Failures

Risk decreases with time. Such risks are due to improper material, material defect, and improper operating conditions

845

Time

FIGURE14.3 Bathtub Curve of Risk. (Adapted from Ref. 2).

where Ri is the risk, PE is the probability of an event, and Cc is its consequence. The risk increases either due to an increase in the probability of the event, to the increase in its consequences, or both. The probability of the event depends on two factors (Eqn. 14.3): PE ¼ WE  LE

(Eqn. 14.3)

where WE is the occurrence of an event, e.g., corrosion, cracking, material degradation, improper operation, improper material selection, material damage, third party damage, and earth movement, and LE is the likelihood of that event happening. In practice, normally, the occurrence (WE) and likelihood (LE) are not separated, i.e., probability (PE) intuitively includes both.

14.2.1 Occurrence Figure 14.3 illustrates the occurrence of risks in various phases.2 The occurrence for some risks is high initially and then progressively decreases with time. This phase is commonly known as the ‘infant mortality phase’, and typical risks in this phase are due to improper installation or workmanship, improper material, improper operation conditions, and defective materials. In the second phase the occurrence of risks is low and constant. This phase is commonly known as the ‘constant failure phase’, and typical risks in this phase are due to random event triggers such as earth movements and third party damage. The final phase is commonly known as ‘wear-out phase’. In this phase the occurrence of risks increases and the risks in this phase are corrosion and wear.

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CHAPTER 14 Management

Model failure Mitigation failure Corrosion Monitoring failure Maintenance failure Management failure

Accident

FIGURE 14.4 Domino Theory. (Adapted from Ref. 3).

The following section discusses why corrosion occurs and presents some methods/theories used to explain the relationship between corrosion risk and the systems/activities used to control it.

14.2.1a Second law of thermodynamics The corrosion process is thermodynamically favorable: according to the second law of thermodynamics, the entropy of the universe, or any isolated system within it, continues to increase. Entropy is a measure of disorderliness; thus the disorderliness of the universe continues to increase. In other words, a system in an orderly state is in a higher energy state and tends to return back to a lower energy state (disorderly state). Metals are extracted from their mineral components by supplying energy (higher energy state) and they have a natural tendency to revert back to their original state (lower energy state). For this reason, corrosion is a spontaneous process and the risk of it occurring is always present. In order to control corrosion, energy must be supplied to the metals to keep them in the higher energy ‘orderly’ state. The energy is supplied through the corrosion control process.

14.2.1b Domino theory According to this theory (Figure 14.4), corrosion occurrence can be prevented by establishing barriers. All barriers to corrosion are linked to one another, and the failure of one barrier may be enough to topple all other barriers.3 The failure of one barrier leads to the failure of other dependent barriers (downstream), but does not affect independent barriers upstream to it. Identification of the failure in the barrier and correcting it prevents progression of corrosion towards accident-breaking remaining barriers. Intuitively this theory indicates that the first barrier to corrosion is critical and when it fails it will induce a domino effect.

14.2.1c Swiss-cheese theory/layers of protection analysis (LOPA) According to this theory, progress of corrosion towards failure occurs as a result of discrete weaknesses in the barriers (Figure 14.5), rather than due to failure of the whole barrier.3,4 Further, this theory indicates that corrosion may progress and lead to failure only when the weaknesses are aligned through

14.2 Risk assessment

Mitigation

Model

Monitoring

Maintenance Management

Accident

Corrosion

Assumptions in the model wrong

847

Model is not relevant to the operating conditions

Inadequate supply of mitigation (e.g., low or no inhibitor addition or cathodic protection)

Inputs to model are not available

Improper use of cleaning of pig

Inadequate monitoring Improper position of probes Inadequate analysis of ILI data

Inadequate capacity Inadequate maintenance of data Inadequate skills

Confusion over responsibility Lack of corporate direction Lack of coordination between different groups

FIGURE 14.5 Swiss-cheese Theory. (Adapted from Refs. 3 and 4).

all the barriers. In other words, the failure occurs due to the alignment of a series of otherwise inconsequential events. This theory explains two important aspects of corrosion control: •

•

Making one perfect barrier (i.e., plugging of all weaknesses in one barrier) or realigning them (e.g., repeated pigging operation irrespective of indication from model and monitoring data that corrosion does not occur) can potentially prevent corrosion from proceeding towards failure, and Even when several strong barriers to corrosion control are present, corrosion can proceed through the weak parts in those barriers.

14.2.1d Event-tree model According to the event-tree model, every event causes or triggers several subsequent events. By following through the series of events, the potential impact of each event can be determined. Figure 14.6 illustrates this model using an inhibitor tank running out of its contents as the initiating event. This one improper maintenance activity led to several other events and, in the worst case scenario, to product release due to internal corrosion.

14.2.1e Fault-tree model The fault-tree model explains occurrence of corrosion in the opposite direction to the event-tree model, i.e., it tracks events backwards from a corrosion occurrence. Figure 14.7 illustrates this model using a leakage due to external corrosion as its example. The fault-tree model is used during failure analysis, and the results are used to overcome deficiencies and to develop better corrosion control practices.

14.2.1f Murphy’s law Murphy’s Law states that ‘things that can go wrong will go wrong’. In a way Murphy’s Law reiterates the imperative indicated by the second law of thermodynamics; that corrosion is thermodynamically

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CHAPTER 14 Management

Inhibitor tank running out of contents (Inhibitor package has corrosion inhibitor, scale inhibitor, and biocide)

Corrosion rate increases to a rate higher than that in unmitigated condition

Corrosion rate increases to that in unmitigated condition

No damage

Increased scale formation

Increased microbial activity

No event No leak

No leak

Leakage

Increased incidents of leakage

Leakage No operational issue

Pressure drop

No shutdown

No event

Shutdown

Increased localized corrosion

FIGURE 14.6 Event-tree Model.

Leakage due to external corrosion

and Underestimation of corrosion rate

Insufficient repair

or

and Overestimation of coating efficiency

or

Model calculation wrong Model input wrong (3 party damage not considered)

FIGURE 14.7 Fault-tree Model.

Insufficient CP

Mitigation strategy wrong

Insufficient analysis of survey data

Maintenance delay (after 3 party damage)

Monitoring strategy wrong

Management inefficiency

or

Not aware of third party damage

Increased sludge formation

Aware of 3 party damage but did not pass the information

Pressure drop

14.2 Risk assessment

849

favorable, and that any combination of events is possible. Murphy’s Law provides a very simplistic explanation of why corrosion occurrence can be driven to very low values, but never zero.

14.2.2 Likelihood Once the types of risk occurrence are known, the likelihood of their occurrence under the operating conditions should be assessed. There are several methods by which the likelihood of an adverse event occurring can be determined. These may be broadly classified into: qualitative, quantitative, and semiquantitative.5

14.2.2a Qualitative (Expert analysis) Qualitative methods of determining the likelihood of risk are based mainly on the knowledge of subject matter experts (SMEs). SMEs have typically acquired knowledge through several years of experience in the operation and functionality of a system (internal SME), or have acquired knowledge based on working with similar systems (external or consultant SME). The qualitative risk assessment process involves meeting with all concerned persons, including SMEs and representatives from design, construction, operation, maintenance, and integrity teams. The various risks are discussed and a decision is taken on the likelihood of their occurrence. This meeting may be informal (implicit) or formal (explicit). The informal qualitative risk assessment process is an undocumented exercise. Traditionally, the oil and gas industry has used informal qualitative risk assessment processes in which SMEs provide direction based on his/her own experience, reasoning, inference, technical, and scientific knowledge. The main advantage of this approach is that the SMEs are typically thorough and are able to make decisions based on the acquired knowledge of several years ‘successes’ and ‘failures’. But this process is undocumented, the knowledge is often not easily transferable, and the validity of the decisions cannot be audited. The formal qualitative risk assessment process is a documented exercise. It involves structured discussion and documentation of decisions. This process requires a discussion of assumptions, collection of data, and other tools needed for arriving at a decision. The main advantage of this approach is that the decisions are documented and hence can be made available to future users. Because the discussions are documented, a consensus agreement on the level of risk can be time-consuming and tedious. Whether a formal or informal process is employed, the outcome depends on who is present in the meeting. The representatives from different departments attending the meetings may change over time; and thus the opinions and decisions from one group or department may vary over time – leading to protracted decision-making. As the pool of suitable SMEs continues to decline in the industry (see section 13.3), the use of a qualitative risk assessment process is also in decline.

14.2.2b Quantitative (Statistical) This method is also known as probabilistic risk assessment (PRA), numerical risk assessment (NRA), or quantitative risk assessment (QRA). It functions on the premise that the corrosion rate is a ‘distributed parameter’ rather than a single value. It first analyzes the data to quantitatively determine its distribution pattern. The data used for this purpose may be corrosion rate, remaining wall, wall loss, or any other similar parameter. As illustrated in Figure 14.8, the distribution pattern may be uniform, normal, triangular, exponential, truncated, Weibull, or Gumbel. Based on the current distribution pattern (corrosion rate or any other corrosion related data) the future distribution pattern is determined

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CHAPTER 14 Management

Uniform

Normal

Triangular

Exponential

Weibull

Truncated

Gumbel

FIGURE 14.8 Statistical Distributions of Typical Corrosion Data.6

using statistical methods.6 One of the most common equations used for this purpose is the Poisson equation (Eqn. 14.4):7 
Ccorr : eð ftÞ (Eqn. 14.4) PðCcorr Þ ¼ ð f ) tÞ Ccorr: max

14.2 Risk assessment

851

FIGURE 14.9 Variation of Failure Pressure Probabilities as a Function of Time 14.8. (Reprinted with permission from NACE International).

where P(Ccorr) is the probability of corrosion rate reaching a particular value, f is the average corrosion rate (mils per year), t is the time period for which the probability is sought (years), Ccorr is the corrosion rate (mils per year) for which the probability is sought and Ccorr .max is the maximum corrosion rate (mils per year). P(Ccorr) is used to determine the probability of risks, including pressure exceeding maximum operating pressure (MOP), human injuries, environmental damage, property damage, leak, or rupture. Figure 14.9 illustrates the probability of pressure distribution as a function of time. From this figure it is apparent that the possibility of operating pressure exceeding MOP occurs between the sixth and seventh year of operation,8 but that a 50% probability of failure does not occur until after year 23. This method provides a precisely quantified failure probability. For this reason, this is better than the deterministic method (which uses only one data point) because it does not underestimate or overestimate the corrosion rate. However, this method requires large amounts of data, and cannot be utilized without it. Additionally the data should be relevant to the corrosion failure mechanisms under consideration. In other words, the mechanism of corrosion should be determined prior to analyzing the data, and such a determination may be arbitrary or may involve the SME. For this reason this method is not fully quantitative.

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Standards providing guidelines to use quantitative risk assessment include: • • • • •

CSA Z662, Annex O, ‘Reliability Based Methodology’ API 570, ‘Piping Inspection Code: In Service Inspection, Rating, Repair, and Alteration of Piping Systems’ API 580, ‘Risk Based Inspection’ API 581, ‘Risk Based Inspection Technology’ DNV RP G101, ‘Risk Based Inspection of Offshore Topsides Static Mechanical Equipment’

14.2.2c Semi-quantitative (Numerical indexing) The semi-quantitative method is a combination of qualitative and quantitative methods. In this method, a knowledgeable person (e.g., SME) or a team of knowledgeable persons pragmatically assign numerical values to various components contributing to the overall risk. The components contributing to overall risk may be just one (e.g., pressure) or there may be several hundreds (e.g., pressure, temperature, flow, material, and operation). The relative contribution of each component may be equal or different. For example, if five components contribute to overall risk, the relative contribution of each component may be 20% each (i.e., 20 x 5 ¼ 100%) or each may have a unique weighting (i.e., 40 þ 20 þ 20 þ 15 þ 5 ¼ 100%). The value indicates the importance of the component with respect to risk, i.e., the higher the numerical value of a component, the higher the risk from that component. In the above example, the component contributing 40% has a higher overall risk than the one contributing 5%. Also, the components which increase risks have positive numerical values, whereas those decreasing risks (e.g., mitigation strategies) have negative values. To facilitate the assignment of numerical values, the infrastructure may be divided into various segments. The segments may be fixed (e.g., every mile of a pipeline) or flexible (e.g., a pipeline crossing through high consequence and low consequence areas (or population classes) may be segmented whenever the consequence area changes. The greatest advantage of the semi-quantitative method is its ability to develop a risk assessment with whatever data that is currently available. For example, if information about how a particular component contributes to risk is not available, the subject matter expert (SME) may initially assign a numerical value which can be adjusted using future information. For this reason, this method can be developed and implemented at any stage of the operation. The disadvantage of this method is the subjectivity of assigning numerical weighting and values to the various components. The SME’s knowledge is thus critical in assigning the relative contribution of each component and its numerical value.

14.2.3 Consequence The consequence of corrosion risk depends on the extent of damage it causes, types of contents leaked into the environment, manner in which the contents are dispersed, and location in which the failure occurs (Eqn. 14.5):9 CC ¼ ED  CT  MR  LF

(Eqn. 14.5)

where CC is defined in Eqn.14.2, ED is extent of damage, CT is the type of contents released, MR is the manner in which the contents are released, and LF is the location in which the failure occurs.

14.2 Risk assessment

853

14.2.3a Extent of damage (ED) The extent of damage (ED) depends on the geometry of the corrosion defect. As illustrated in Figure 14.10, this is characterized by its length, width, and depth. Depending on the geometry of the defect, a leak or rupture may occur (Figure 14.11). When the length and width of the corrosion defect

Width of the defect, w

Depth of the defect, d

Length of the defect, l

Large

FIGURE 14.10 Geometry Characteristics of Corrosion Defect.

Rupture

W/D

Large Leak

Medium Leak

Small

Rupture Small Leak Small

FIGURE 14.11 Types of Corrosions Failures.

L/D

Large

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is relatively similar to its depth, it results in small hole penetrating the wall, and a relatively small leak into the environment. When several corrosion defects coalesce, their combined length proportionately increases. As the length (or width) to the depth of corrosion defects increases, the wall of the infrastructure may undergo plastic deformation before the defect penetrates through the wall; plastic deformation of wall may lead to large leakage or rupture. In terms of volume release consequence, ED typically increases in the order: small leak < large leak < rupture. However, volume of release is also affected by the duration of the event. Large leaks or ruptures are more easily identified and responded to by automated leak detection monitors. These events are normally of short duration, as the infrastructure where such event occurs is quickly shut down and isolated. Very small leaks which occur far from operator or public surveillance may occur for extended periods of time and release significant volumes.

14.2.3b Type of contents (CT) The consequence of failure depends on the type of contents being released into the environment. The environmental impact of the contents depends on their flammability (i.e., if the content catches fire when released), reactivity (i.e., if the content reacts unfavorably with the environment to produce toxic substances), and toxicity (i.e., if the content is poisonous to the species in the environment). Equation 14.6 defines a method to determine the consequence of CT: CT ¼ Fc þ Rc þ Tc

(Eqn. 14.6)

where Fc is the flammability of content, Rc is the reactivity of the content, and Tc is the toxicity of the content. Table 14.1 provides a method to rank the contents in terms of consequence.

14.2.3c Manner of release (MR) The manner in which the contents are released from the failed infrastructure affects the consequence of failure. The contents may be released as: fire ball, vapor cloud, or liquid spill. Table 14.1 Consequence of Contents Released from the Oil and Gas Infrastructure9 Type of Impact Consequence Ranking

Flammability ( F)

1 (less severe consequence) 2

Non combustible above 200

3

100e200

4

75e100

5 (more severe consequence)

Below 75

Reactivity

Toxicity

Completely stable

No hazard

Mild on heating with pressure Significant even without heating

Only minor residual injury likely Medical attention required to avoid temporary incapacitation Cause serious temporary injury Cause death or major injury

Detonation possible with confinement Detonation possible even without confinement

14.2 Risk assessment

855

When flammable hydrocarbons are suddenly released from a high-pressure environment to a low-pressure environment, they can easily ignite and burn. The size of the fire and duration for which it burns depends on the pressure of the infrastructure, volume of hydrocarbon released, and the ability of emergency teams to control the leak and fire. If the released hydrocarbon vapors do not find a source of ignition they form a vapor cloud. The vapor cloud may be toxic (if it contains poisonous substances such as hydrogen sulfide) or asphyxiant (i.e., it displaces oxygen leading to suffocation). Vapor clouds in low lying areas may also catch fire at a later stage if they find a source of ignition. Released hydrocarbon liquids will contaminate the environment (e.g., water, vegetation, or soil). Similar to a vapor cloud, liquid hydrocarbons may also catch fire at a later stage if they find a source of ignition. A large pool of liquid hydrocarbons can collect from a leak through a small opening because the small pressure drops associated with these leaks may not be detected by the pressure monitors installed on the infrastrcture. In terms of consequence, MR generally increases in the order: liquid spill < vapor cloud (nontoxic) < vapor cloud (toxic) < fire.

14.2.3d Location of failure (LF) The consequence also depends on the location in which corrosion leads to failure. Equation 14.7 defines a method to determine the consequence of LF: L F ¼ P D þ Es

(Eqn. 14.7)

where PD is the population density and Es is the environmental sensitivity. The US Department of Transportation divides locations into four classes to determine the consequence of a pipeline failure.10 The classes are determined based on 1 mile by 1320 ft rectangle area, centered over the pipeline (i.e., 660 ft on either side of the pipeline centerline): • • • •

Class 1: fewer than 10 dwellings Class 2: more than 10 and fewer than 46 dwellings Class 3: more than 46 dwellings or has a high-occupancy building or well-defined outside meeting area Class 4: multi-storey building (such location is considered as high consequence area)

Table 14.2 presents another methodology for scoring population density.11 The consequence also depends on sensitivity of the environment in which the failure occurs. There are several ways in which this sensitivity can be defined. Table 14.3 presents a methodology in which the consequence is scored based on both sensitivity and on the value of the location.12

14.2.4 Quantification As defined in Eqn. 14.2, the risk can be quantified by the probability of an event occurring and its consequence. Normally, the risk is quantified using a matrix structure. Several grids such as 3 x 3, 4 x 4, 4 x 5, and 5 x 5 may be used to quantify risk, but the 5 x 5 grid is most commonly used (Figure 14.12).13 This matrix approach helps to integrate the risk assessment with the consequence assessment in an easy, comprehensive, and readily understandable manner. Irrespective of how the risk assessment is carried out, e.g., qualitative, quantitative, or semi-quantitative, the result may be

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Table 14.2 Scoring of Population Density in Terms of Consequence9,11 Population Type

Score

Extraordinary situation Multistory buildings Commercial Residential urban Residential suburban Industrial Semirural Rural Isolated No-habitat

10 9 (DOT equivalent 8 7 6 (DOT equivalent 5 4 (DOT equivalent 3 (DOT equivalent 2 1

score is 4)

score is 3) score is 2) score is 1)

expressed as a value between 0 and 5. The assessment process may be very detailed – as discussed in sections 14.2.2 14.4, and 14.5. Consequence may also be expressed as a value between 0 and 5. The product of probability and consequence is used to quantity the overall risk as: • • •

0 to 4 as acceptable risk region in which no mitigation measure is required. 5 to 12 as the ALARP (as low as reasonably possible) region in which comprehensive risk mitigation strategies are implemented to reduce the risk. 13 to 25 is the unacceptable region in which oil and gas infrastructure should not be operated.

14.3 Risk management The oil and gas industry operates successfully by keeping the operational risk in the acceptable or ALARP region. If the risk escalates to the unacceptable region or is predicted to reach this, then suitable actions are taken to reduce the risk level. These actions may include mitigation, monitoring, and maintenance; regulations in many sectors of the industry mandate that risk reduction actions must be undertaken immediately or operation is shutdown. Even if the risk is in the acceptable or ALARP regions, the system should be monitored to ensure that it continues to remain in that state. Thus, risk management is a process of continuously assessing risk and of making the right choices to reduce it if it escalates. All these activities incur cost; for this reason effective risk management requires an understanding of the relationship between risk and cost. This will enable selection and implementation of the optimal corrosion management program to reduce risk.

14.3.1 Risk–cost relationship Logically, any expenditure (cost) should bring benefit. Similarly, as the cost increases the risk should decrease. However, the relationship between risk and cost may not be straightforward. It is for this

14.3 Risk management

857

Table 14.3 Scoring of Environmental Sensitivity in Terms of Consequence9,12 Sensitivity • • • • • • •

Value

10

Ocean Major river Major lake Other major water structure Nesting grounds or nursing areas of endangered species Vital sites for species propagation Presence of an endangered species

Score

• Rare equipment • Hard to replace facilities • Extensive associated damage would be felt

9

on loss of facilities

• Major costs of business interruptions

• • • • •

Freshwater swamps and marshes Saltwater marshes Mangroves Vulnerable water intakes for community water supplies (surface or groundwater intakes) Very serious damage potential

• Significant additional damages expected •

due to difficult access or extensive remediation Serious harm is done by a leak

• Shorelines with rip rap structures or gravel •

beaches Gently sloping gravel river banks

• Mixed sand and gravel beaches • Gently sloping sands and gravel river banks • Topography that promote wider dispersion •

(slopes, soil conditions, and water currents) More serious damage potential

• • • •

Coarse-grained sand beaches Sandy river bars Gently sloping sandy river banks National and state parks and forests

• • • • • • •

anticipated Most serious repercussions are anticipated High degree of public outrage National and international news Very high property value High costs and high likelihood of business interruptions Expensive industry shutdown required Widespread community disruptions are expected High publicity regionally Some national coverage

• • • Moderate business interruptions anticipated • Well-known or important historical or

8

7

archaeological sites

• Public outrage is anticipated • Long-term (one growing season or more)

6

damage to agriculture Other associated costs Some community disruption Regional new stories

• • • • Low-profile historical and archaeological

5

sites High-expense cleanup area due to access Equipment needs Other factors unique to this area High level of local public concern

• • • • • Unusual public interest in this site • High-profile locations such as recreation

4

areas

• Some industry interruptions (without major costs)

• Local new coverage (Continued )

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Table 14.3 Scoring of Environmental Sensitivity in Terms of Consequence9,12 Continued Sensitivity

Value

Score

• • • • •

• Some level of associated costs; higher than

3

Fine-grained sand beaches Eroding scarps Exposed eroding river banks Difficulties expected in remediation Higher than normal spill dispersal

• • • • • • • • • • •

• Wave-out platforms in bedrock • Bedrock river banks • Minor increase in environmental damage potential

• Shorelines with rocky shores, cliffs, or banks

Probability

• No extraordinary environmental damages

normal is anticipated Limited-use buildings (warehouses, storage facilities, small offices) might have access restricted Industry image Picnic grounds Gardens High-use public areas Increasing property values Corporate image

2

Property values are higher than normal Company image

1

Potential damage are normal for this class location No extraordinary damage expected

0

Dangerous

5

10

15

20

25

High

4

8

12

16

20

Medium

3

6

9

12

15

Low

2

4

6

8

10

Minimum

1

2

3

4

5

Minimum

Low

Medium

High

Dangerous

Consequence Acceptable risk As low as reasonably possible (ALARP) risk Unacceptable risk

FIGURE 14.12 Quantification of Risk. (Adapted from Ref. 13).

14.3 Risk management

859

Reliability

A

Risk

B

C

1

2

3 Cost

FIGURE 14.13 Relationship Between Risk and Cost. (Adapted from Refs. 9 and 14).

reason actions undertaken to reduce the risk should be judicious. Figure 14.13 presents three possible ways that risk and cost relate with one another.9,14 •

• •

The most preferred approach is the one in which the risk level decreases drastically for small increases in cost – as occurs in the early stage (i.e., low-cost side) of Figure 14.13, Curve A. The risk does not normally reach zero, but rather tapers off to a low or ALARP level in the later stage (i.e., high-cost side) of Figure 14.13, Curve A. In most cases, the risk level decreases linearly with the increase in cost (Figure 14.13, Curve B). The least preferred approach is the one in which the risk level decreases at a rate far lower than the rate in which the cost increases (Figure 14.13, Curve C). This usually happens with infrastructure that has not been properly maintained, and for which actual reduction of risk will occur only after sufficient efforts are completed. Note that the high-cost side of Figure 14.13, Curve C exhibits a behavior in which the risk level decreases rapidly for small increment of cost.

In the examples presented in Figure 14.13, the cost increases in the order: option A (line 1) < option B (line 2) < option C (line 3) to keep the system in the same risk level. From this perspective, the risk reduction strategy producing curve A is the best option at all levels of risk. However in real life, the risk-cost curves of different options may overlap with one another. In that situation, the best option to reduce risk should be determined at different levels of risk.

14.3.2 Methods to estimate the cost (Economics) The cost of a project, activity or operation depends on the value of money. For various reasons, the value of money fluctuates over time. For example, if one has $1,000 and deposits it in a bank, assuming

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that the bank gives 5% interest rate, the value of money at the end of one year will be $1,050. On the other hand, if one invests the $1,000 on a product and if the product depreciates by 5%, at the end of one year one will only have $950. These simple illustrations help to understand the real worth of money after a given period of time, and help to estimate the cost of an investment, operation, or project. These illustrations however do not consider the purchasing power of money. Two methods commonly used to estimate cost are capitalization and discounting. • •

Capitalization is the method of determining the ‘future value’ of ‘a present amount’; i.e., what will be the worth of $1,000 that I have in hand today in one year? Discounting is the method of evaluating ‘present value’ of ‘a future amount’; i.e., what is the worth today of $1,000 that I will receive in one year’s time?

In both methods, a compound interest rate (or other suitable factor) is used to determine the value at different periods of time. In the capitalization method, the future value (FV) is calculated using Eqn. 14.8: i h (Eqn. 14.8) FV ¼ PV ð1þ iR ÞT

where FV is the future value, PV is the present value, iR is the interest rate, T is the duration (normally year or fraction of year), and [(1þ iR)T] is known as compound factor. In the discounting method, the present value is calculated using Eqn. 14.9: " # 1 PV ¼ FV (Eqn. 14.9) ð1þ iR ÞT

where [1/(1þiR)T] is known as discount factor (DF). The DF includes all factors that affect the PV including interest rate and other expenditures (e.g., corrosion cost). Financial investment is made in a project or an activity today with the anticipation that the project or activity generates additional cash in the future. The amount of cash generated is known as ‘cash flow’ and summation of all cash flows is known as ‘net cash flow’. If the project only incurs expenditure, the net cash flow is negative, and if the project generates new cash over and above the initial investment, the net cash flow is positive. The cash flow is corrected with a ‘discount factor’ to calculate the PV. Several methods are available to estimate the cost of a project or investment based on PV. Table 14.4 presents the general characteristics of these methods as well as their pros and cons.15 Some of these methods are discussed further in the following paragraphs.16

14.3.2a Net present value (NPV) Table 14.5 illustrates the calculation of PV using an investment in which $5,000, $10,000, $100,000, $15,000, and $15,000 are spent during year 5, year 4, year 3, year 2, and year 1. From the start year (year 0) onwards this investment starts earning additional cash in the following manner: $1,000, $10,000, $20,000, and $100,000 respectively in year 0, year 1, year 2, year 3 and in subsequent years. Consequently the net cash flow becomes positive at the end of year 4. However this calculation does not include the discount factor, i.e., operating expenditure as well as interest paid to borrow money (assuming that money was borrowed to make the investment). At a discount rate of 10 or 20% (as per Eqn. 14.9), the NPV becomes positive only at the end of year 5 or year 8, respectively. The net cash flow is thus corrected with DF to determine the NPV of an investment.

Table 14.4 Economic Methods to Evaluate Cost15 Method Net present value (NPV)

Description

Disadvantages

Application

This method estimates time value of money and includes interest or other discount (expenditure) factor

This method is difficult to use to compare projects with different lifespans

Most widely used tool in various investments

Quick and easy calculation. Results are easy to interpret

Does not consider inflation, interest rate (if money is borrowed), or cash flow

Rough initial estimation to determine if the investment is profitable

This method estimates time value of money

This method does not consider cash flow outside the payback period

Screening tool to determine if the investment is profitable

This method is useful to calculate equivalent annual cost of a project

This method produces only average annual cost and it does not estimate actual cost each year

This method is useful to compare alternate projects with different length of life

The results are presented as percentage of investment

The method is useful only when the investment generates income

This method is useful to track rate of investment

14.3 Risk management

NPV process adjusts cash flow to present value (PV) of an asset by including a Discount Factor (DF). Discount factor is a measure of interest rate or other rate of return for cash flowing in or out. Normally the investment is made on project yielding positive NPV. Simple payback This method calculates the time period (SPP) required to return the initial investment. The investment with the shortest payback time is the most profitable. Discount payback Essentially the same as the simple period (DPP) payback method, but includes the time value of money into account, i.e., it includes discount rate. Equivalent annual This method determines cost (EAC) equivalent annual cost of a project, i.e., it adjusts the NPV value to calculate equivalent cost for every year. The IRR is a measure of rate Investment rate of average return to the initial of return (IRR) investment.

Advantages

861

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Table 14.5 Illustration of Cash Flow, Present Vaue (PV), Net Present Value (NPV) and Payback (PP) Calculations

Year 5 4 3 2 1 0 1 2 3 4 5 6 7 8 9 10

Cash Flow, K $ (Undiscounted Rate) 5 10 100 15 15 1 10 20 100 100 100 100 100 100 100 100

PV (At a Discount Rate of 10%)

PV (At a Discount Rate of 20%)

8 15 133 18 17 1 9 17 75 68 62 56 51 47 42 39

12 21 173 22 18 1 8 14 58 48 40 33 28 23 19 16

Net Cash Flow (or NPV), K $ (Undiscounted) 5 15 115 130 145 144 134 114 14 86 186 286 386 486 586 686

NPV, K $ (At the Discount Rate of 10%) 8 23 156 174 190 189 180 164 89 20 42 98 149 196 239 277

NPV, K $ (At the Discount Rate of 20%) 12 33 206 228 246 245 236 222 164 116 76 43 15 9 28 44

14.3.2b Payback period (PP) This method calculates the time required for the initial investment to return. There are two PP methods: simple payback period (SPP), which does not consider DF, and discount payback period (DPP), which does include DF. Obviously DPP is more accurate than SPP because it includes the time value of money. Figure 14.14 demonstrates the SPP and DPP based on the data presented in Table 14.5. From Figure 14.14 it is evident that as the DF increases, the DPP increases, i.e., the time required for the initial investment to return is longer.

14.3.2c Equivalent annual cost (EAC) The equivalent annual cost (EAC) method converts the PV into equivalent annual cost using the capital recovery factor (CRF) (Eqn. 14.10): " # iR ð1  iR ÞT EAC ¼ PV: (Eqn. 14.10) ð1þ iR ÞT 1 where [iR(1 iR)T/(1 þ iR)T 1] is the CRF. In order to calculate the EAC, a reasonable time period for the project or activity or investment should be established. The lower the EAC, the more economic and profitable is the project or activity or investment. Table 14.6 illustrates the use of EAC using three

14.3 Risk management

863

1,000

500 NPV (Undiscounted) NPV (10% Discounted) NPV (20% Discounted)

250

20% Discount

-250

10% Discount

0

Undiscounted

Net Present Value, 1,000 $

750

-500 -10

-5

0

5

10

15

Duration, years FIGURE 14.14 Illustration of Payback Period. (Based on data presented in Table 14.5).

competing projects. From Table 14.6 it is evident that option #2 is more economic (lowest EAC) and option #3 is least economic (highest EAC).

14.3.2d Investment rate of return (IRR) The investment rate of return (IRR) may also be known as the rate of return on investment (ROI). The IRR is calculated as percentage using Eqn. 14.11: 
P TNI=T :100 (Eqn. 14.11) IRR ¼ TII Table 14.6 Illustration of Equivalent Annual Cost (EAC) Calculation

Option

Capital Cost, $

Life, Years

EAC (Undiscounted)

Capital Recovery Factor (CRF) (At 10% Discount Rate)

EAC (At 10% Discount Rate)

1 2 3

10 20 30

2 7 5

5 3 6

0.58 0.21 0.26

5.76 4.11 7.91

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CHAPTER 14 Management

Table 14.7 Illustration of Investment Rate of Return (IRR) (using data presented in Table 14.5) Investment Rate of Return Details Irr Parameters

For Undiscounted Rate

At a Discount Rate of 10%

At a Discount Rate of 20%

Total net income (TNI), K$ TNI/Total year, K$ IRR, %

501 50 19

305 31 12

191 19 7

where TNI is the total net income or total discounted net income, T is the duration of the project or activity in years, and TII is the total initial investment. Table 14.7 illustrates IRR using data from Table 14.5; for a total investment of $145,000, the rates of income over a period of 10 years are respectively; 19% (discounted rate is zero percent), 12% (discounted rate is 10%), and 7% (discounted rate is 20%).

14.3.3 Methods to optimize corrosion cost From the cost calculation (discussed in section 14.3.2), it is evident that project planners will favor activities that yield highest NPV over the entire project life, have the shortest PP, the lowest EAC, and the highest IRR. On the other hand, corrosion decreases NPV, increases PP, increases EAC, and lowers IRR; thus, corrosion has negative impact on economics. Corrosion professionals act to educate technical and business colleagues about the economical benefits of preventing failures and downtime caused by corrosion. Participation by corrosion professionals in the early stages of a project increases corrosion education of the team. This in turn leads to corrosion control strategies which provide maximum economic benefits to the company. The primary benefit of incorporating corrosion control strategies during the design stage is decreased operating cost. If appropriate corrosion control strategies are not implemented, premature failure due to corrosion may occur. Failure may result in: fatalities, injuries, property damage, environmental damage, business interruption, loss of customer confidence, customer dissatisfaction, political and legal ramifications, loss of competitive advantage, and loss of corporate and company image, and regulatory, legal, and contract penalties. In addition, a corrosion related incidence will usually result in scrutiny of many entities including corrosion professional, corrosion team, integrity team, senior management, suppliers and service providers, workers, and regulators by stakeholders, general public, media, and lawyers. Following the investigations and scrutiny, regulatory authorities will create new rules for mandatory compliance. In general, an assessment of the cost impact of corrosion should include: • • •

Capital expenditures for material selection and for modeling the interaction of material and the main influencing factors to establish baseline corrosion rate. Operating expenditures for corrosion mitigation, monitoring, maintenance, and management. Additional expenditures or loss of revenue (e.g., due to loss of production due to shutdown) should corrosion failure occurs.

14.3 Risk management

865

The following sections discuss methods to optimize the cost of corrosion. It should be pointed out that these methods have several commonalities; i.e., they perform same or similar activities.

14.3.3a Life cycle cost (LCC)17 Life cycle cost (LCC) may also be known as whole life costing (WLC) or cost in use (CIU). LCC is a process of estimating all costs associated with a project or activity for its entire duration. If all associated costs are known and accounted for, then different options could be considered to reduce the total cost of the project without increasing the risk. This method helps in tracking the flow of money at different stages of the project. Normally LCC is used at the beginning of a project, but in theory it can be used at any stage. Figure 14.15 illustrates the different stages of a typical project and the extent to which corrosion professionals could and should provide expertise. Table 14.8 lists key activities corrosion professionals perform at different stages. During the conceptual stage, detailed information is less readily available; sometimes the only information available may be the pressure, volume, and temperature (PVT) curve of a pipeline or process. Using the available information, the materials of construction and the environmental conditions as well as types of corrosion are identified.

Degree of Influence, %

40%

25%

15% 10% 5%

4%

t Ab

an

do

Fa

nm

ilu

en

re

n m N or

C

om

al

m

O

is

pe

si

ra

on

ct ru st on C

tio

g in

n io

es ig D

C

on

ce p

t

n

1%

Stages FIGURE 14.15 Degree of Influence of Corrosion Professionals at Different Stages of a Project.

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Table 14.8 Typical Corrosion Related Activities in Various Stages of a Project Stage

Corrosion Related Activities

Conceptual

Materials, environment, and their interaction Main factors influencing corrosion Mechanisms Modeling Maintenance Monitoring Measurement Mitigation Monitoring Maintenance Management Management Mitigation

Design Construction Commissioning Normal Operation

Failure Abandonment

Reference Chapters

Cost in an Arbitrary Currency

3

3

4 5 6 and 10 13 8 and 11 12 7 and 9 8, 11, and 12 13 14 14 7 and 9

2 1 12 17 7 10 10 10 20 7 10) 1

) See Figure 14.16 more details. As illustrated in scenario 2 of this figure, the funds for corrosion control is progressively reduced when compared to funds requested based on LCC analysis (scenario 1); Consequently premature corrosion failure has occurred. Note in Figure 14.16, scenario 1 there is no failure, as funds are made available as per LCC analysis

During the design stage, materials of construction and operating environments are established and the anticipated corrosion rates of various elements are established from material–environmental interactions. Laboratory data, if necessary, are collected to establish corrosion mechanism and corrosion rate. All the information is used to model the anticipated corrosion rate. Decisions regarding mitigation strategies, monitoring techniques, and maintenance schedules are made on the basis of the model output. During the construction stage, communication is maintained with the construction team to ensure that the mitigation strategy (e.g., external coatings) as well as accessories to carry out mitigation (e.g., inhibitor injection point), monitoring (e.g., ports for inserting coupons and launching pigs), and maintenance activities are properly installed. During commissioning, key activities of the corrosion professional include: assessing the threat of internal corrosion from hydrotest water, and compiling the pre-operation baseline data for the infrastructure. During operation, typical activities to control corrosion include: • •

•

Implementing and adjusting mitigation strategies in response to changing operating conditions (e.g., increase inhibitor concentration in response to higher water cut in the process stream). Field monitoring and/or inspection for corrosion at established intervals. The data from measurement (e.g., temperature, pressure) activities are collected and integrated with monitoring data. Maintenance of corrosion related equipment at established intervals and as per changing operating conditions. The data is collected, analyzed, and archived. Further the workforce and communication are maintained.

14.3 Risk management

•

867

Implementation of a corrosion management program/practices to ensure that the mitigation, monitoring, and maintenance activities are properly conducted according to changing operating conditions and at regular intervals, and that the risk-cost balance is evaluated periodically. Corrosion management must also ensure that failure analysis is conducted (should failure happen), reasons for failure identified, and methods to avoid such failures are developed and implemented.

Operating requirements may sometime require temporary or permanent abandonment of structure. In this situation, corrosion managers must ensure that all conducting solutions (e.g., water) are removed and an inert gas blanket is applied to mitigate internal corrosion and that the infrastructure is protected (e.g., application of cathodic protection) to mitigate external corrosion. Figure 14.16 presents a typical breakdown of the cost of corrosion at different stages: Scenario 1 presents typical costs associated with various corrosion control activities described in Table 14.8. In scenario 2 progressive cost-cutting measures at various stages of the project results in a premature failure which in fact increases the total cost to above that in scenario 1. The further disadvantages of scenario 2 include indirect cost and other losses (human and reputation) associated with failure. Table 14.9 illustrates the advantages of LCC analysis to select the most economic strategy, using controlling internal corrosion in an oil production pipeline as an example. The conceptual and design activities (cost $15,000) have indicated that mitigation strategies are required to control internal corrosion. Internal corrosion can be controlled either by cladding the carbon steel with corrosionresistant alloys or by adding corrosion inhibitor. The additional cost for cladding the pipeline is $50,000, over and above the carbon steel material cost of $100,000. The construction and commissioning costs are each $15,000. Thus the capital expenditure for using clad carbon steel is $195,000 50

OPEX and Recurring Scenario 1 Scenario 2

40

30 Cost, %

CAPEX and Non-Recurring

20 Avoidable

10

0 Concept

Design

Construction Commissioning Normal Operation

Stages

FIGURE 14.16 Typical Cost of Corrosion Control Activities.

Failure

Abandonment

Table 14.9 Comparison of NPV of Two Options to Control Internal Corrosion of Oil Production Pipelines Inhibited Carbon Steel

Clad Carbon Steel

Discounted Rate, %

Cash

Cash

Corrosion

Flow

Flow,

Flow

(or NPV),

1,000 $

Activities (See

0

Net

Cash

Control

Year

Discounted Rate, %

Net

Type of

Table 14.8)

Cash Flow, 1,000 $ (Undiscounted rate)

Interest and Others

Normal

(or NPV),

PV,

1,000 $

NPV,

(Undis-

Interest

Normal

PV,

1,000 $

Corrosion

Corrosion

1,000

(Undis-

1,000

counted

and

Corrosion

Corrosion

1,000

(Undis-

NPV,

Control

Inhibitor

$

counted)

$

rate)

Others

Control

Inhibitor

$

counted)

1,000 $

5

Conceptual

5

10

0

0

8

5

8

5

10

0

0

8

5

8

4

Design

10

10

0

0

15

15

23

10

10

0

0

15

15

23 222

3

Material

100

10

0

0

133

115

156

150

10

0

0

200

165

2

Construction

15

10

0

0

18

130

174

15

10

0

0

18

180

240

1

Commissioning

15

10

0

0

17

145

190

15

10

0

0

17

195

257

1

10

5

5

1

144

189

1

10

5

0

1

194

256

10

10

5

5

8

134

181

10

10

5

0

9

184

247

20

10

5

5

14

114

167

20

10

5

0

15

164

232

100

10

5

5

58

14

109

100

10

5

0

66

64

166

100

10

5

5

48

86

61

100

10

5

0

57

36

109

100

10

5

5

40

186

21

100

10

5

0

50

136

60

Normal operation

1

Normal operation

2

Normal operation

3

Normal operation

4

Normal operation

5

Normal operation

6

Normal

100

10

5

5

33

286

13

100

10

5

0

43

236

16

100

10

5

5

28

386

40

100

10

5

0

38

336

21

100

10

5

5

23

486

64

100

10

5

0

33

436

54

100

10

5

5

19

586

83

100

10

5

0

28

536

82

100

10

5

5

16

686

99

100

10

5

0

25

636

107

100

10

5

5

13

786

113

100

10

5

0

21

736

129

100

10

5

5

11

886

124

100

10

5

0

19

836

147

100

10

5

5

9

986

133

100

10

5

0

16

936

164

100

10

5

5

8

1,086

141

100

10

5

0

14

1,036

178

100

10

5

5

6

1,186

148

100

10

5

0

12

1,136

190

100

10

5

5

5

1,286

153

100

10

5

0

11

1,236

201

100

10

5

5

5

1,386

157

100

10

5

0

9

1,336

210

100

10

5

5

4

1,486

161

100

10

5

0

8

1,436

218

100

10

5

5

3

1,586

164

100

10

5

0

7

1,536

225

100

10

5

5

3

1,686

167

100

10

5

0

6

1,636

231

operation 7

Normal operation

8

Normal operation

9

Normal operation

10

Normal operation

11

Normal operation

12

Normal operation

13

Normal operation

14

Normal operation

15

Normal operation

16

Normal operation

17

Normal operation

18

Normal operation

19

Normal operation

20

Normal operation

870

CHAPTER 14 Management

300 Inhibited Carbon Steel Cladded Carbon Steel

NPV, 1,000 $

200

100

0

-100

-200

-300 -10

-5

0

5

10

15

20

25

Duration, Year

FIGURE 14.17 Comparison of NPV For Two Options to Control Internal Corrosion of Carbon Steel Production Pipeline. (Based on data from Table 14.9).

and that for using carbon steel without cladding is $145,000. The production’s cash flow is $1,000 (year 1), $10,000 (year 2), $30,000 (year 3), and $100,000 (from year 4 onwards). The cost of normal corrosion control activities during operation is estimated at a discounted rate of 5% and the cost of adding corrosion inhibitors is estimated at a discounted rate of 5%. With these estimates, using Eqn. 14.9, the NPV of the project can be calculated to determine the most cost-effective method to control corrosion. Figure 14.17 compares the NPVs for both clad and inhibited carbon steel. From Table 14.9 and Figure 14.17, it is clear that if production is expected to carry on for less than nine years, then carbon steel with corrosion inhibitor is the economic corrosion control choice; if the useful life is more than 10 years, then clad carbon steel is the economic corrosion control choice; at a nine year life, both options are equally viable. The above example does not include the probability of failure. Often it may not be possible to take an error free decision, so it may be prudent to include uncertainty into the analysis. Equation 14.12 provides a way to include uncertainty in the LCC analysis by modifying the NPV:   
 
 PF 100 PF ðNPV CF Þ þ ðNPVÞ (Eqn. 14.12) NPVc ¼ 100 100 Where NPVc is the NPV corrected for probability of failure, PF is the probability of failure (0 to 100), and CF is the cost of the failure. Figure 14.18 presents a comparison of NPV for the project detailed in Table 14.9 in Year 9 with the assumption that the probability of failure for clad carbon steel and carbon steel with corrosion inhibitor

14.3 Risk management

871

100

NPV, 1,000 $

80

60

40

No failure

25% probability of failure

No failure

5% probability of failure

20

0 Inhibited

Cladded

Corrosion Control for Carbon Steel Production Pipeline

FIGURE 14.18 Influence of Probability of Failure on Corrosion Control Strategies. (Based on NPV for year 9 in Table 14.9).

is 25% and 5%, respectively. Based on this data, it is clear that clad carbon steel is far more cost effective than carbon steel with corrosion inhibitor. Further, the selection of a corrosion resistant material is a process safety improvement, because it removes the possibility of a failure due to an incomplete or incorrectly executed inhibition program. The key messages from the LCC analysis presented in Figures 14.15 through Figure 14.18, and Table 14.8 and Table 14.9 are: • • • •

Corrosion professionals add maximum value when they participate during early project stages, The cheapest option may not be the right one for the project life cycle, It is essential to include uncertainties in deciding the most economic option, and Incremental capital expenditure (CAPEX) increase due to corrosion control measures may significantly reduce operating expenditure (OPEX).

The development of LCC is not without challenges; some typical challenges include the following: • •

When CAPEX are high, there will be a tendency to pick the cheapest option in spite of the fact it will increase OPEX. The actual cost for the corrosion control program may be difficult to break out from the total cost of the project.

Guidelines on LCC are provided in the following standards: •

ISO 15686–5, ‘Buildings and Constructed Assets – Service Life Planning – Part 5: Life Cycle Costing’.

872

• •

CHAPTER 14 Management

ISO 15663, ‘Petroleum and Natural Gas Industries – Life Cycle Costing’. EFC Working Party Report, EFC 32, ‘Life Cycle Costing of Corrosion in the Oil and Gas Industry: A guideline’.

14.3.3b Front-end engineering design (FEED)17 The front-end engineering design (FEED) process is also called Front-End Loading (FEL) or preproject planning (PPP). The premise of FEED is that if the equipment or structure is designed properly at the beginning of a project, then the probability of it functioning properly during service is maximized. FEED may be considered to represent all activities carried out in the conceptual and design stages of the LCC process (see Figure 14.15) and in a way it may be considered as a sub-set of an LCC process. However, a FEED process may also be carried out as a separate process without considering LCC. FEED may primarily be used to determine the feasibility of a project from economic and technical points of view, and may sometimes be used as a ‘go’ or ‘no go’ decision point. The information available for the design engineers at the FEED stage is minimal. Decisions are therefore taken based on previous similar projects, data from laboratory experiments, or theoretical simulations. The typical output of FEED is an engineering drawing or a blue-print incorporating preliminary structure layout, equipment design and specification, material specification, construction schedule, budget, and project design basis memorandum. The FEED process also identifies vendors who can manufacture, fabricate, and construct the material and equipment. Shipping and warehousing logistics for materials and equipment are also included in FEED. The key role for the corrosion professional during FEED is the specification of materials of construction. If appropriate materials are specified – taking into consideration all operating conditions for the entire life of the infrastructure – then the cost of corrosion can be economically managed during service. On the other hand if due diligence is not exercised during the FEED process for material selection, premature failure may happen.

14.3.3c CAPEX vs. OPEX18 As illustrated in Figure 14.16 and Table 14.9, there is a balance between CAPEX and OPEX. Normally if CAPEX is high, OPEX is low, and vice versa. However such relationship should be evaluated on a project by project basis. For projects being considered in an economic period featuring high interest rates, there is incentive to keep CAPEX as low as possible. Decisions to keep CAPEX low may be taken consciously, acknowledging that this will increase OPEX during service. The economic argument for this decision may be two-fold: • •

The project itself may be cancelled if the CAPEX is too high during the conceptual design stage, and OPEX may be absorbed without significant economic impact during operation when revenue is being generated.

From the point of view of corrosion control, it would be useful to compare a higher CAPEX – lower OPEX scenario with a lower CAPEX – higher OPEX scenario and develop appropriate strategies to manage corrosion. Case studies similar to Figure 14.16 may be generated to describe the negative

14.3 Risk management

873

impact of lowering both CAPEX and OPEX. If both CAPEX and OPEX are reduced, the likelihood of failures due to corrosion increases, which would indeed increase the life cycle cost.

14.3.3d Key performance indicators (KPI) Key performance indicators (KPIs) may also be known as key point indicators (KPI). They provide “high level” statistics about the performance status of the corrosion management strategy. The most popular method of presenting the KPI is the ‘traffic signal’ method in which three color schemes are used:19,20 • • •

Green (corrosion management strategy works properly) Amber (corrosion management strategy does not work properly and action should be taken as soon as possible to correct the situation) Red (corrosion management strategy does not work and immediate action must be taken)

The parameters selected as KPIs must be relevant and measureable. Normally, internal corrosion monitoring, external corrosion monitoring and measurement data are considered as KPIs, but several other parameters may also be used. Table 14.10 presents some KPIs used in the oil and gas industry. KPI status is normally used to ensure that the corrosion management strategies are achieving the intended results.

14.3.3e Risk based inspection (RBI)2,21 In an ideal situation, 100% of the infrastructure should be monitored and inspected – all the time – in order to ensure that the structure is safe and is free from any risk. Unfortunately, such an endeavor is not only prohibitively costly but also impossible. The intelligent alternative is then to inspect only critical sections that are at higher level of risk. This is the basis of the risk based inspection (RBI) process. The RBI process first identifies those infrastructure sections which are at higher levels of risk. To determine the risk level, the quantified risk is calculated, i.e., the product of probability and consequence is calculated (see section 14.2.4). The RBI process then inspects the sections to determine the actual level of risk. If the inspection confirms that the risk level is indeed high, then the section is either repaired or replaced. If the inspection indicates that the risk level is medium or low, then the interval at which the section should be re-inspected is determined and scheduled. Figure 14.19 illustrates that the concept of determining the locations of highest risk from modeling. The results indicate that distances 3, 16, 22, and 44 km are at relatively high levels of risk. The advantage of RBI is that instead of inspecting the whole 50 km distance, only specific areas of higher risk are inspected more thoroughly. Subsequent inspection reveals that risk at distance 22 km is high, at 16 km is moderate, and at 3 and 44 km is low. Based on the risk levels, decision can be made to repair distance 22 km, to repair or re-inspection distance 16 km, and to re-inspect distances 3 and 44 km. Figure 14.20 illustrates how the risk increases as the function of time and how decisions about whether to repair or re-inspect can be made. From Figure 14.20, it is obvious that the risk level reaches the ALARP risk level at year 3 and high risk level at year 7 without applying any mitigation strategies: •

In scenario 1, the location is repaired at year 3 and subsequent corrosion mitigation strategy kept the risk level low until year 22 when another repair should be carried out.

Table 14.10 Examples of Key Performance Indicators used in the Oil and Gas Industry19

Mitigation (Internal)

Monitoring (Internal)

12

A quantitative model with a predicted maximum corrosion rate has been developed based on material, main influencing factors, and mechanism

Green

Amber

Red

Yes

 Yes, but maximum corrosion rate is not

No

 

quantified Corrosion rate is quantified, but all main influencing factors are not considered Corrosion rate predicted is not that of corrosion mechanism that is anticipated to progress (e.g., general corrosion rate to predict localized pitting corrosion rate)

15

Hydrostatic test performed

Yes

15

Pipe cleaned and dried after hydrostatic test

Yes

No

15

Schedule of cleaning pig runs established

Yes

19

Percentage cleaning pig runs performed as per schedule in a year (or any fixed duration)

More than 99

16, 17

Schedule for applying corrosion inhibitor established

Yes

19

Percentage availability of continuous inhibitor in a year (or any fixed duration)

More than 99

95 to 99

Less than 95

19

Percentage of batch inhibitor application as per schedule in a year (or any fixed duration)

More than 99

95 to 99

Less than 95

19

Schedule for applying biocides established

Yes

19

Percentage of biocide availability in a year (or any fixed duration)

More than 99

24

Field monitoring techniques established

Yes

25

Locations for installing field monitoring techniques established

Locations where the worst case corrosion conditions prevail

Yes; but dryness not completely established

No No

95 to 99

Less than 95

No

No 95 to 99

Less than 95 No

Locations are selected where corrosion is expected and they may not be the locations where severe corrosion will occur

No basics for the selection of locations other than that these locations are easily accessible

CHAPTER 14 Management

Model (Internal)

KPI Status of Activity or Deliverable Target Defined for Activity or Deliverable

874

Activity

Reference Table 14.14, row number

Field monitoring frequency established

Yes

No

26

Percentage of field data collection in a year (or any fixed duration) as per established frequency

More than 99% complete

95 to 99% complete

Less than 95% complete

27

Analysis of field monitoring data completed and data correlated with operating conditions (e.g., measurement data), months from data collection

One

One to three

More than three

32

Field inspection techniques established

Yes

32

Field inspection location selection

Where severe corrosion conditions prevail

32

Field inspection frequency established

Yes

32

Percentage of field data collected compared to target, %

More than 99

95 to 99%

Less than 95

33

Analysis of inspection data completed and correlated with operational conditions, months from data collection

Three

Three to six

More than six

20

Coatings (mainline, girthweld, insulator, and concrete), as applicable are compatible with one another

Yes

No or do not know

20

Cathodic protection installed within one year of installing the section

Yes

No

21

All factors affecting the effectiveness of cathodic protection are understood and overcome

Yes

No Locations are selected where corrosion is expected and they may not be the locations where severe corrosion will occur

No basics for the selection of locations, other than that these locations are easily accessible and/or where pig launching facility exists No

Some yes; but not all

No

875

(Continued)

14.3 Risk management

Mitigation (External)

25, 26

Table 14.10 Examples of Key Performance Indicators used in the Oil and Gas Industry19 Continued

Green

Amber

Red

A quantitative model with a predicted maximum corrosion rate has been developed based on material, main influencing factors, mechanism, and mitigation strategies

Yes

 Yes, but maximum corrosion rate is not

No

28

Coating holiday detection performed at the time of installation and all defects are repaired

Yes

29

Field above-ground monitoring techniques established

Yes

29

Locations for performing field above-ground monitoring techniques established

Locations where the worst case corrosion conditions prevail

29

Frequency of performing field above-ground monitoring techniques established

Yes

29

Percentage of field data collection in a year (or any fixed duration) as per established frequency

More than 90% complete

75 to 90% complete

Less than 75% complete

30, 31

Analysis of field monitoring data completed and data correlated with operating conditions (e.g., measurement data), months from data collection

One

One to three

More than three

32

Field inspection techniques (e.g., inline inspection) established

Yes

32

Field inspection location selection

Where worst case corrosion conditions prevail

22

 

quantified Corrosion rate is quantified, but all main influencing factors are not considered Corrosion rate predicted is not that of corrosion mechanism that is anticipated to progress (e.g., general corrosion rate to predict localized pitting corrosion rate)

Yes, but data is not available

No

No Locations are selected where corrosion is expected and they may not be the locations where severe corrosion will occur

No basics for the selection of locations other than that these locations are easily accessible No

No Locations are selected where corrosion is likely to take place and they may not be the locations where worst case corrosion condition exists

No basics for the selection of locations, other than that these locations are easily accessible and/or where pig launching facility exists

CHAPTER 14 Management

Monitoring (External)

KPI Status of Activity or Deliverable Target Defined for Activity or Deliverable

876

Activity Modeling (External)

Reference Table 14.14, row number

Measurement

Field inspection frequency established

Yes

No

32

Percentage of field data collected compared to target, %

More than 90

75 to 90%

Less than 75

33

Analysis of inspection data completed and correlated with operational conditions, months from data collection

Three

Three to six

More than six

32

Opportunities for field below ground measurement established

Yes

No, but looking for opportunity

No

32

Field below ground measurements performed

Yes and data relevant for understanding external corrosion collected.

Yes, but data relevant for external corrosion not collected

No

32

Analysis of field below ground measurement completed and data correlated with operating conditions

Yes

Yes, but the data not correlated with other field operating conditions

No

32

Completion of analysis of field below ground measurement data correlation of that with operating conditions (e.g., measurement data), months from data collection

One

One to three

More than three

34

Types of measurement data required are established

Yes

35

Percentage of measurement data collected in a year (or any other fixed duration)

More than 90

36

Critical equipment to be maintained identified

Yes

No

37

Frequency of maintenance of critical equipment established

Yes

No

37

Percentage of maintenance activities completed in a year

More than 90

75 to 90

Less than 75

42

Required workforce for maintenance per square meter (square inch) of infrastructure established

Yes

Not sure

No

44

Capability of workforce to perform the task established

Yes

Not sure

No

43

Availability of required workforce per year

99

95 to 99

Less than 95

No 75 to 90

Less than 75

14.3 Risk management

Maintenance

32

877

(Continued)

Table 14.10 Examples of Key Performance Indicators used in the Oil and Gas Industry19 Continued

Green

Amber

Red

45

Data to be collected and stored established

Yes

No planned data collection established but whatever data available are stored

No

46

Percentage of data collected per year

More than 99

95 to 99

Less than 95

47

Communication strategy established

Yes

48

Effectiveness of communication strategy checked

Once a year

49

Corrosion risk of the infrastructure assessed

Yes

49

Corrosion risk level

Low

49

Consequence of risk assessed

Yes

49

Consequence of risk

49

No No frequency established, but randomly done

No No

Medium

High

Low

Medium

High

Quantification of risk (likelihood times consequence)

Low

ALARP

High

49

Corrosion risk management strategies established

Yes

49

Number of KPIs established

Yes

49

Status of KPIs

 90% in green  

No

No No and Up to 10% in amber and No in red

 Less than 90% in green or  90% in amber or

 90% in red or  less than 75% in red or

 75 to 90% in amber

49

Budget available to reduce risk

Yes

Some

No

50

Failure due to corrosion per year

No failure

One unexpected leak

More than one unexpected leak or rupture

50

Review of corrosion management strategy

Annual

Random and frequency more than one year

No

50

Report on corrosion management completed, months from review

Within 3

3 to 6

More than 6 or no report planned

50

Opportunities for improvement identified in the annual report

Yes

Some

No

50

Percentage implementation of opportunities identified before next review

More than 99

95 to 99

Less than 95

CHAPTER 14 Management

Management

KPI Status of Activity or Deliverable Target Defined for Activity or Deliverable

878

Activity

Reference Table 14.14, row number

879

ALARP

Based on Inspection

Low

Risk Level

High

14.3 Risk management

0

5

10

15

20

25

30

35

40

45

50

Distance, KM

ALARP

Risk without RBI Scenario 1 Scenario 2 Scenario 3 Scenario 4

Low

Risk Level

High

FIGURE 14.19 RBI Process of Prioritization of Locations of Higher Risk.

0

5

10

15

20

25

Duration, Year FIGURE 14.20 Illustration of the Effect of Inspection and Repair on Risk in a RBI Process.

30

880

•

• •

CHAPTER 14 Management

In scenario 2, the risk is allowed to reach middle of the ALARP level before repair activities are carried out in year 5; subsequent mitigation strategies enabled this location to remain at the ALARP level without any further repair. In scenario 3, the risk is allowed to reach the high level before repair activities are carried out in year 8, and subsequently repair activities are carried out in years 13, 20, and 24. In scenario 4, the section is in the high risk level before the repair activities are carried out in year 13 and subsequently the repair activities are carried out in year 20 and 24 to keep the risk in the ALARP region.

From the above discussion it is apparent that the tolerance to risk increases in the order Scenario 1 < Scenario 2 < Scenario 3 < Scenario 4 and that the practice exercised in scenario 4 presents the highest probability of premature failure. Scenario 4 is therefore the least preferred option. By selecting sections at higher risk levels, inspecting them, and taking action to reduce their risk level, the RBI process cost-effectively manages the risk. The accuracy or reliability of the RBI method must be validated before implementing the process. The success of RBI process depends on the ability: • • •

• • • • • •

to obtain data about operating conditions of the infrastructure, to track variations in operating conditions (e.g., upset and abnormal operating conditions), to include all components of the infrastructure into the RBI process (e.g., the conditions prevailing inside a dead-leg of a section are different from bulk conditions. Therefore the risk level in the section with dead-leg is different – normally high), of models to correctly predict the high risk locations, to establish risk levels of baseline conditions, especially for those infrastructures for which no historical data exists, of tools to inspect the high risk locations to accurately determine the remaining wall, of repair and replacement techniques to reduce the risk, of mitigation strategies to control risk, and of models to predict the future inspection schedule.

Standards providing guidelines for developing and implementing RBI process include: • • •

API 580, ‘Risk Based Inspection’ API 581, ‘Risk Based Inspection Technology’ DNV RP G101, ‘Risk Based Inspection of Offshore Topsides Static Mechanical Equipment’

14.3.3f Fitness for service (FFS)22 Fitness for service (FFS) is a process of determining the severity of flaws in a structure. The flaws are first evaluated by non-destructive techniques (NDT). Techniques used in inline inspection are also used as NDTs (see sections 8.3 and 11.5). The flaws may be transgranular stress-corrosion cracks (TGSCC), intergranular stress-corrosion cracks (IGSCC), fatigue corrosion cracks, fatigue cracks, and other crack-like flaws. Central to the FFS assessment is the development of failure assessment diagram (FAD). A FAD (Figure 14.21)22 is a plot of susceptibility of a flaw to plastic collapse versus the susceptibility of the flaw to fracture. Materials fail by plastic collapse when they have high fracture toughness and low yield stress and when the flaw size is large (relative to wall thickness), and they fail by fracture when their fracture toughness is low (i.e., brittle material), their yield strength is high and the flaw size is small (relative to wall thickness).

14.3 Risk management

Flaw dimensions

Stress analysis

881

1.2 Failure assessment curve

1.0

Stress intensity factor solution, KI

Unacceptable region

0.8 Kr

Failure assessment point

K Kr = I Kmat

0.6 0.4

Material fracture toughness, Kmat

0.2

Acceptable region

0.0 0.0

0.2

0.4

Reference stress solution, σ ref

Flaw dimensions

0.6

Lr =

0.8

σ ref σy

1.0

1.2 Lr

1.4

1.6

1.8

2.0

2.2

Material yield stress, σ y

Stress analysis

FIGURE 14.21 Fitness Assessment Diagram. Reproduced with permission from Elsevier.

The first step in constructing the FAD is to establish the boundary between safe (where the flaws do not lead to failure either by plastic or fracture collapse) and unsafe (where flaws can lead to failure) regions. Equation 14.13 is commonly used to define such a boundary:22   6 Kr ¼ 1 0:14L3r 0:3þ 0:7e½ 0:65Lr Š (Eqn. 14.13)

where Kr is the measured of susceptibility of a flaw to fracture and Lr is the measure of susceptibility of a flaw to plastic collapse. Equation 14.12 is valid under the conditions defined in Eqn.14.14: Lr  Lr ðmaxÞ

(Eqn. 14.14)

where Lr(max) is defined in Eqn.14.15: LrðmaxÞ ¼

sf sy

(Eqn. 14.15)

where sf is the material flaw stress, i.e., the average of the ultimate tensile stress and yield stress) and sy is the material yield stress. The second step is to characterize the flaw, as measured by NDT. The flaws (cracks), material, and environment should be characterized to the greatest extent possible. The characterization of cracks includes establishing their size, shape, length, depth, location, proximity to stress

882

CHAPTER 14 Management

concentration (e.g., weld, crevice), path, orientation, numbers, and spacing (between cracks if more than one is present). The material characterization includes information on age, initial microstructure, stress level, presence of corrosion (general or localized), and surface condition (e.g., presence of welding and coating). The environmental characterization includes ability of the environment to sustain crack growth. Once the flaw is characterized, the Lr and Kr are calculated using Eqns.14.16 and 14.17 and the result is plotted on the FAD. sref (Eqn. 14.16) Lr ¼ sy where sref is the reference stress. Kr ¼

K1 Kmat

(Eqn. 14.17)

where K1 is the stress intensity factor and Kmat is the material fracture toughness. In order to include the stress-corrosion cracking (SCC) rate into K1, another parameter, known as the hreshold intensity factor for SCC, K1SSC, is used. Below K1SSC the applied K1 does not accelerate the SCC rate but above it the applied K1 rapidly increases SCC rate. •

K1SSC is determined in the laboratory using a pre-cracked specimen either under constant load or constant displacement conditions.

Standard providing guidelines for conducting laboratory tests includes: •

ISO 7539-6, “Corrosion of Metals and Alloys-Stress Corrosion Testing-Part 6: Preparation and Use of Precracked Specimens for Tests under Constant Load or Constant Displacement”.

The magnitude of K1SSC and the SCC rate depend on material, environment and configuration of loading. Therefore the laboratory tests should be carried out in conditions which are as close as possible to the real operating conditions (see section 8.2). In using the K1SSC determined in laboratory for real operating conditions, two other factors should be considered: the duration of laboratory tests is far shorter than that of real operation, and the data is generated in the laboratory under static conditions, but the real operational conditions are dynamic and may include short term excursions above the intended design conditions. The final step in the FFS assessment is to determine if the flaws are in the safe or unsafe zone. If flaws are in the unsafe zone, corrective steps such as repair and replacement activities are performed. If flows are in the safe zone, it is necessary to identify the drivers (e.g., material, environment, temperature, and stress) and estimate the time for flaws to grow into the unsafe zone. The following standards provide guidelines for performing an FFS assessment: • • • •

British Standards Institution, BS 7910, ‘Guide to methods for assessing the acceptability of flaws in metallic structure’ British Energy Generation Ltd, R6 Revision 5, ‘Assessment of the integrity of structures containing defects’ API RP 579, ‘Fitness for Service’ European Fitness for Service Thematic Network (FITNET TN), FITNET MK 7, ‘Fitness for service procedure’

14.5 Activities of corrosion management

883

14.4 Corrosion risks Chapter 2 describes various sectors of the oil and gas industry. Between the point where the first drill-bit contacts the hydrocarbons underground and where the refined petroleum products are delivered to a consumer, the oil and gas infrastructure are subjected to different types of corrosion. Table 14.11 summarizes types of corrosion occurring in different sectors. From the table it is obvious that all sectors of the oil and gas industry are susceptible to corrosion. Some types of corrosion – e.g., liquid metal embrittlement (when the production fluid contains mercury) and fretting corrosion – are very rare. On the other hand, some types of corrosion are rare in one sector (e.g., internal corrosion in gas transmission pipelines) and more frequent in another (e.g., production pipeline). The type of corrosion depends on the material of construction and the environment in which the structure operates. In order to estimate the corrosion risk, both the material and the environment should be characterized. Characterizing the material is relatively straightforward but characterizing the environment is not. This is because once constructed the material remains the same, unless it has failed or has completed its designed life time. But the operational parameters may change hours, daily, weekly, monthly, randomly, and abruptly. Table 14.12 provides parameters by which the environment may be characterized. In characterizing the environment, the typical, minimum, maximum, and abnormal operating conditions should be understood. Further, it should be noted that there are limitations to our ability to fully characterize risk due to limitations in the techniques. Table 14.13 lists some limitations which should be taken into account in estimating risk. The upstream sector operations are not in steady state. Their operational variations may trigger and/or accelerate corrosion in downstream sectors. For example, failure of a separator may lead to release of water in a dry gas transmission pipeline. Normal corrosion management in the gas transmission pipeline works on the premise that the gas is dry; therefore when water is accidently released into the system the corrosion risk should be re-evaluated. For this reason it is necessary to treat the oil and gas infrastructure as a continuum and to evaluate the corrosion risk in that continuum.

14.5 Activities of corrosion management Section 14.1 describes the responsibilities of corrosion management. To effectively manage corrosion, several activities are undertaken. Table 14.14 describes 50 activities in a typical corrosion management process. These 50 activities should only be considered as a guideline to start the corrosion management process. Depending on the sector, on when corrosion management (i.e., from conceptual stage or during operation) is implemented, and on other requirements, the number of activities may increase or decrease. The number of activities depends on the level of risk; in general, the number of risk reduction activities increase with the expected risk level. It is essential to develop and list all applicable risk reduction activities. Without comprehensive list it will be difficult to manage corrosion and demonstrate that corrosion management is an integral part of corporate due diligence. Some attributes common to all should be recognized. These are discussed in the following paragraphs. To facilitate management of corrosion, the infrastructure may be divided into segments and the risk level can be assigned to each segment. Activities are developed to keep the risk of the segment to the established level.

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CHAPTER 14 Management

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Corrosion Issues (See Table 5.1) Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Erosioncorrosion2, SSC2, chloride SCC2, and MIC2 Pitting1, SCC1, and localized pitting corrosion1 and CUI(A)2 Pitting1, chloride SCC1, and localized pitting corrosion1, LME1, and CUI(A)

Oxygen, chlorides, H2S, CO2, pH, sand, and microbes H2S, CO2, pressure, and temperature H2S, CO2, pressure, water composition, and temperature

2.4

CUI(A)2

Acids

2.5

Underdeposit corrosion (scaling)1, CUI(A)2, and MIC2 Chloride SCC1 and CUI(A)2

Oxygen, H2S, CO2, water composition, and microbes Chlorides, Oxygen, H2S, and CO2 Sand and water

2.6

Sector

Component

Production

Drill Pipe

Corrosion fatigue2

Casing Pipe

SSC1,2

Downhole Tubular

SSC1

2

Acidizing Pipe Water Generators and injectors

General corrosion1 Localized corrosion1

Gas Generators

Localized corrosion1

Open mining

Erosioncorrosion1

In situ Production

Erosioncorrosion1

Wellhead (onshore and subsea)

SSC1

Wellhead (subsea)

Localized pitting corrosion2

Erosion1, localized pitting corrosion1, wear1, and abrasion1 Localized pitting corrosion1, MIC, and CUI(A)2

Localized pitting corrosion1, CUI(A)2, and erosioncorrosion1 Galvanic corrosion2

Temperature, pressure, sand, and water (brackish), CO2, H 2S H2S, CO2, sand, and water

Water (ocean)

Reference Sections 2.2

2.3

2.7

2.8

2.9

2.10

2.10

14.5 Activities of corrosion management

885

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1)

Sector

Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Production Pipelines

Localized pitting corrosion1

Grooving corrosion1, HIC1, SWC1, FILC1, erosion corrosion1, CUI(A)2, and MIC2

Water, oil, H2S, CO2, oxygen, sulfur, sand, temperature, pressure, flow, pH, and microbes.

2.11

Heavy Crude Oil Pipelines

Localized pitting corrosion1

Oil, water

2.12

Hydrotransportation Pipelines Gas Dehydration Facilities Oil separators

Erosioncorrosion1

Erosion corrosion1, CUI(A)2, and MIC2 Localized pitting corrosion1 and CUI(A)2 HIC1, erosioncorrosion1, and CUI(A)2 CUI(A)2

Sand, water, and oxygen (air)

2.13

H2S, CO2, water, sand, and pH H2S, CO2, oil, water, oxygen, and pH Sand, water, flow, temperature, H2S, CO2, water, oxygen, and pH

2.14

Component

Localized pitting corrosion1 Localized pitting corrosion1

Recovery Centers (Extraction)

Erosioncorrosion1

Upgraders

See refineries section

Lease Tanks

Waste Water Pipelines Tailing Pipelines

Erosioncorrosion1

FILC1

Reference Sections

2.15

2.16

2.17 SSC1, HIC1, SOHIC1, cracking1, galvanic corrosion1, localized pitting corrosion1, CUI 2 and MIC1,2 Localized pitting corrosion1 and CUI(A)2 Localized pitting corrosion1 and CUI(A)2

Water, H2S, CO2, and microbes

2.18

Oxygen, CO2, and oil

2.19

Sand, flow, water, oxygen, and CO2

2.20

(Continued )

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CHAPTER 14 Management

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1) Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Localized pitting corrosion1, MIC1,2, stray current corrosion2, telluric current corrosion2, and alternating current corrosion2, and fretting corrosion2 Cavitation corrosion1, localized pitting corrosion1 and fretting corrosion2 Erosion corrosion, Localized pitting corrosion1 Localized pitting corrosion1, erosion, deposition corrosion1, and CUI(A)2 CUI(A)2 and MIC1,2

Pressure, crude oil, black powders, temperature, water, oxygen, CO2, and microbes

2.21

Flow and sand

2.22

Flow

2.23

Various

2.24

Sand (sediments), microbes (fouling2), and water Water Water

2.25

2.26 2.27

Water

2.28

H2S, CO2, pressure, water composition, and temperature

2.29

Sector

Component

Transmissionpipeline

Transmission Pipelines (Midstream Pipelines)

SCC2

Compressor Stations

Erosioncorrosion1

Pump Stations

Cavitation corrosion1

Pipeline Accessories

Galvanic corrosion1

Transportation- Ships Tanker

LNG Tanks Railcars Trucks Storage

Gas (underground)

Localized pitting corrosion1

CUI(A)2 Localized pitting corrosion1 Localized pitting corrosion1 Chloride SCC1, localized pitting corrosion1, and CUI(A)2

Reference Sections

14.5 Activities of corrosion management

887

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1)

Sector

Refining

Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Oil Tanks

Localized pitting corrosion2

Localized pitting corrosion1 and MIC2

Water, oxygen, CO2, and microbes

2.30

Desalter

Localized pitting corrosion1

2.31.1

Atmospheric and vacuum distillation Hydrotreating unit

Localized pitting corrosion1

Water composition, salt Organic acids, inorganic acids (HCl), H2S, and temperature

Component

Catalytic cracking unit

Thermal cracking Hydrocracking

Steam cracking Merox Catalytic reforming unit

Visbreaker

SSC1

High Temperature Corrosion (Graphitization)1 e Above 450 C Intergranular SCC Graphitization High temperature corrosion1 High temperature corrosion Localized pitting corrosion High temperature corrosion (metal dusting)1

High temperature corrosion

Reference Sections

2.31.2 and 2.31.3

HIC1, SCC1,2 and localized pitting corrosion1, and CUI(A)2 Erosion1, intergranular1, and SCC1

H2S, temperature, organic acids, inorganic acids, and flow Temperature, flow, ammonia, carbonates, and pH

Erosion

Temperature

2.31.6

Localized pitting corrosion

H2S, temperature, and organic acids Temperature Steam

2.31.7

Sulfur compounds Temperature, chloride, ammonia, organic acids, and inorganic acids Temperature

2.31.9

Localized pitting corrosion1, chloride SCC1, carburization, and ammonia SCC1.

2.31.4

2.31.5

2.31.8

2.31.10

2.31.11

(Continued )

888

CHAPTER 14 Management

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1)

Sector

Component

Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Reference Sections

Coker

High temperature corrosion1

H2S, temperature, and organic acids

2.31.12

Gas plants (saturated) Gas plants (unsaturated) Alkylation

Localized pitting corrosion Localized pitting corrosion Grooving1

Salt water

2.31.13

Salt water

2.31.13 2.31.14

Isomerization

Localized pitting corrosion

Gas treating

Localized pitting corrosion Localized pitting corrosion1

Inorganic acids (sulphuric and hydrofluoric), flow, temperature, SO2, and oxygen Chlorides High temperature H2S, CO2, and amines Inorganic acid, H2S, flow, chloride, and temperature Temperature, H2S, CO2, SO2, and sulfur. H2S, flow, temperature, water composition, chloride, and oxygen Water composition, oxygen, microbes, chloride, pH, temperature, and flow

Sour water strippers

Claus sulfur plant Heat exchangers

Cooling towers

High temperature corrosion1 Localized pitting corrosion1

Localized pitting corrosion1

FILC1, general corrosion1, galvanic corrosion1, hydrogen embrittlement1, LME1, and SCC1

Erosioncorrosion1 and hydrogen embrittlment1 Localized pitting corrosion1 Erosioncorrosion1

Selective leaching (Dezincification)1 erosion corrosion, and underdeposit corrosion (scaling)1

2.31.15

2.31.16 2.31.17

2.31.18

2.31.19

2.31.20

14.5 Activities of corrosion management

889

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1)

Sector

Component

Major (Most Corrosion Failures Occur Due to)

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

Solvent extraction

General corrosion1

Chloride SCC1

Organic acids, chlorides, and temperature

2.31.21

Steam reforming

Erosioncorrosion1

Corrosion fatigue1 and SCC1

Solids, velocity temperature, carbonates, bicarbonates, oxygen, and CO2 Non-corrosive environment

2.31.22

Inorganic acid (phosphoric acid) Temperature and acid gases

2.31.24

Hydrogen, ammonia, temperature, oxygen, and water CO2, CO, and hydrogen

2.31.26

Methyl tertiary butyl ether (MTBE) Polymerization

Distribution

General corrosion1 Localized pitting corrosion1

Hydrogen plant

Hydrogen embrittlement1

Ammonia plant

Hydrogen embrittlement1

Methanol plant

Localized pitting corrosion1High temperature corrosion (metal dusting)

Others units Product pipelines

Localized pitting corrosion2

High temperature corrosion, Localized pitting corrosion1 HIC and High temperature corrosion (nitriding)1

MIC2

Terminals

CUI(A)2

City gates and local distribution

General corrosion1 and CUI(A)2

Water, CO2, microbes, and temperature. Water, CO2, and temperature. Non-corrosive environment

Reference Sections

2.31.23

2.31.25

2.31.27

2.31.28 2.32

2.33 2.34

(Continued )

890

CHAPTER 14 Management

Table 14.11 Corrosion Issues in Various Sectors of Oil and Gas Industry Continued Corrosion Issues (See Table 5.1)

Sector

Component

Major (Most Corrosion Failures Occur Due to)

CNG tanks Special

Diluent pipelines

Localized pitting corrosion2

High vapor pressure pipelines CO2 pipelines

Localized pitting corrosion2

Hydrogen pipelines

Ammonia pipeline Biofuel infrastructure

Localized pitting corrosion2 Hydrogen embrittlement2

Localized pitting corrosion and SCC Localized pitting corrosion2

Minor (Corrosion Failures also Occur Due to)

Major Influencing Factors (See Chapter 4)

General corrosion2

Non-corrosive environment

2.35

Localized pitting corrosion1 and MIC2 MIC2

Water, CO2, microbes, and temperature. Water, CO2, microbes, and temperature. Water, CO2, and temperature. Hydrogen, water, pressure, CO2, microbes, and temperature.

2.36

Localized pitting corrosion1 CUI(A)2 and MIC2

Reference Sections

2.37

2.38 2.39

2.40

SCC1, localized pitting corrosion1, and MIC2

Water, CO2, microbes, organic acid, and temperature.

2.41

1

Internal surface External surface; and (A)for the purpose of this table, CUI may either represent corrosion under protective coating or corrosion under insulator

2

To evaluate how well each activity is implemented, several KPIs may be required. Table 14.14 provides an overview process to quickly evaluate the status of implementation. Additional KPIs may be developed as required. Each activity carries an associated cost. A cost-benefit analysis should be performed before any activity is undertaken.23,24 No standard is available to provide guidelines for estimating the cost of each activity; however Table 14.14 provides percentage costs for each activity, based on a general survey of the oil and gas industry. This information should be used as a starting point. The percentage cost of each activity may vary for different sectors in the industry. The percentage costs may be also converted into currency values or so that the real cost of the activity and timing to implement it such as to produce maximum benefit can be determined. In general, the earlier the activity is implemented, the less it will cost, and the higher will be the corrosion risk reduction. Table 14.14 also lists the stages at which various activities are typically implemented.

14.5 Activities of corrosion management

891

Table 14.12 Typical Parameters Deciding the Operation Conditions of Oil and Gas Infrastructure) Parameter

Typical Units

Volume of oil Volume of water Volume of gas Solid content Temperature Total pressure H2S partial pressure CO2 partial pressure Oxygen content Chemical composition of the environment

cm3, m3, liter, gallons, or barrel cm3, m3, liter, gallons, or barrel cm3, m3 cm3, m3, liter,  C or  F PSI, kPA, atmosphere PSI, kPA, atmosphere PSI, kPA, atmosphere ppm or ppb

• Chloride • Sulfate • Sulfide • Carbonate • Bicarbonate • Acetate • Sodium • Potassium • Calcium • Barium Microbial species

• • • • • • • • • •

• SRB • APB • IOB • IRB pH Flow Wall shear stress

• Bacterial count per volume • Bacterial count per volume • Bacterial count per volume • Bacterial count per volume 0 to 14 m/s or feet/s Pa

)

ppm ppm ppm ppm ppm ppm ppm ppm ppm ppm

or % or % or % or % or % or % or % or % or % or %

Minimum, maximum, and typical values should be known

14.5.1 Segmentation of infrastructure Corrosion is efficiently managed by reducing the area of the segment, making the areas of each segment as uniform as possible, and separating internal and external surfaces of the infrastructure,. For the purpose of establishing a corrosion management program, a fixed area (e.g., one square kilometer) may be considered as a starting point. For example a 200 km pipeline with inner diameter of 78.8 cm and outer diameter of 80 cm will have a surface area of 1 square kilometer (Eqn. 14.17):   (Eqn. 14.17) Surface area ¼ 2prðinnerÞ 1 þ 2prðouterÞ 1

892

CHAPTER 14 Management

Table 14.13 Some Limitations of Corrosion Control Techniques Technique

Used for

Current Limitation

Modeling

To predict the corrosion rate

• Accuracy of model •

Mitigation

prediction Lack of models to predict the rate of all types of corrosion, especially localized corrosion

To protect external surface of infrastructure

• Lack of consensus on

Monitoring

Monitoring corrosion rate

Inspection

Measuring remaining wall thickness

Measurements

Measuring various parameters influencing corrosion rate

Maintenance of data

Various reasons

All current monitoring techniques are point sensors, i.e., they monitor the corrosion rate or wall thickness only at the point where the sensor contacts the surface Accuracy of the techniques and the duration it takes between measurements (e.g. ILI runs) and interpreted results Many of the measurement techniques are offline requiring withdrawal of solution and performing the analysis in the laboratory Lack of standardized procedures to collect, store, analyse, and use data

cathodic shielding phenomenon of protective coating

Next Immediate Advancement Required Quantitative models to predict rate of corrosion

Standard methodologies to evaluate cathodic shielding property of coating Global sensors that can monitor a wide range of area

Breakthroughs in the inspection technique to determine the wall thickness Development of reliable online measurement technique that can automatically take the reading Development of consensus standards for data collection and maintenance

where r(inner) is the inner radius of the pipe (in cm, inch, or km), r(outer) is the outer radius of the pipe (in cm, inch, or km); and l is the length (km or mile).

14.5.2 Corrosion risks Information presented in Table 14.11 may be used as a starting point to determine the corrosion risks in various segments. It is anticipated that no more than five mechanisms can cause corrosion in one segment. Identification and evaluation of alternative designs, options may reduce the corrosion risks.

Table 14.14 Overview of Corrosion Management Activities

Description of Activities

Value in (unit)

1

Segmentation of infrastructure

Square kilometer or square mile

2

Corrosion risks

Numerical value

3

Location of infrastructure

Numerical value

4

Quantification of risk

Numerical value

5

Life of infrastructure

Years

6

Materials of construction

UNS number

Corrosion Numerical Index

Reference Chapter

0.50

Conceptual

2

2.00

Conceptual

3, 4, 5

2.00

Conceptual

1, 2, 14

1.00

Conceptual

6, 10, 14

0.50

Conceptual

3, 4, 5

6.00

Design

3, 4, 5

893

0 to 1: Each segment is 1 square kilometer or less 2 to 3: Each segment is more than 1 square kilometer 4 to 5: Segment area varies 0 to 1: for no or low corrosion risk 2 to 3: for secondary corrosion risk 4 to 5: for main corrosion risk 0 to 1: Consequnce of failure is relatively low 2 to 3: Consequence of failure is relatively medium 4 to 5: Consequnce of failure is high 1 to 2: Overall risk from corrosion is relatively low e the system should be monitored to ensure that the risk remains low 3 to 9: Overall risk from corrosion is relatively medium e mitigation and monitoring strategies are used to reduce the risk 10 to 25: Overall risk from corrosion is high e the infrastructure will fail if adequately strategies are not implemented to reduce risk 0 to 1: Life is between 1 to 5 years 2 to 3: Life is between 5 to 10 years 4 to 5: Life is more than 10 years 0 to 1: Material selected based on corrosion consideration 2 to 3: Material selection not based on corrosion consideration, but the material is compatible in the environment with approprate corrosion control measures 4 to 5: Suitability of material from corrosion perspective is not established

Stage at which the Cost is Incurred

14.5 Activities of corrosion management

Activity No.

Cost (In Percent),)) age)

(Continued)

894

Table 14.14 Overview of Corrosion Management Activities Continued

Description of Activities

Value in (unit)

7

Corrosion allowance (wall thickness)

mm or mil

8

Normal operating conditions

Various (See Table 14.12)

9

Upset conditions or operation excursions in the upstream segment

N/A

Corrosion Numerical Index 0 to 1: Corrosion allowance more than corrosion rate times anticipated life 2 to 3: Corrosion allowance more than mitigated corrosion rate times anticipated life 4 to 5: Corrosion allowance less than mitigated corrosionrate times anticipated life 0 to 1: Operating conditions within the range established for the entire duration of the project 2 to 3: Operating conditions exceed intermittentently, but within 10% of the limits established for short duration (typically less than 1 hour) 4 to 5: Operating conditions exeed the limit established frequently or operating conditions change completely from initial condition 0 to 1: Potential influence of upset conditions in the upstream segment on the corrosion of the segment under consideration is understood and plan established with upstream team to avoid or minimize such upset conditions 2 to 3: Potential influence of upset conditions in the upstream segment on the corrosion strategies of the segment under consideration is understood and communicaiton plan established with upstream team to obtain information in case if there is an upset or operating excursions

Stage at which the Cost is Incurred

Reference Chapter

0.25

Design

3, 4, 5

1.00

Design, Operation

3, 4

0.50

Design, Operation

4

CHAPTER 14 Management

Activity No.

Cost (In Percent),)) age)

4 to 5: Potential influence of upset conditions in the upstream segment on the corrosion conditions of the segement under consideration is not understood and no communication plan in place to obtain information on upset conditions from upstream segment Upset conditions in this sector affecting downstream sector

N/A

11

Mechanisms of corrosion

N/A

12

Maximum corrosion rate (Internal surface)

mpy or mm/y

13

Maximum corrosion rate (External surface)

mpy or mm/y

0.25

Design, Operations

2, 3, 4

2.00

Design

5

1.00

Design

2, 3, 4, 5, 6

1.00

Design

2, 3, 4, 5, 10

895

0 to 1: Potential influence of upset conditions and operation excursions understood and plan established to avoid or minimize the effect of such upset conditions 2 to 3: Influence of upset conditions or operation excursions evaluated and corrosion control strategies modified accordingly 4 to 5: Potential influence of upset conditions on downstream is not understood 0 to 1: All corrosion mechanisms are considered and most prominent ones determined 2 to 3: Some corrosion mechanisms are considered 4 to 5: Mechanisms of corrosion not fully understood 0 to 1: Maximum corrosion rate is based on model, laboratory experiment, simulation, or documented similar field experience 2 to 3: No basis for the selection of maximum corrosion rate 4 to 5: No anticipated maximum corrosion rate established 0 to 1: Maximum corrosion rate is based on model, laboratory experiment, simulation, or documented similar field experience 2 to 3: No basis for the selection of maximum corrosion rate 4 to 5: No anticipated maximum corrosion rate established

14.5 Activities of corrosion management

10

(Continued)

Description of Activities

Value in (unit)

14

Installation of proper accessories

N/A

15

Commissioning

N/A

16

Mitigation to control internal corrosion: is it necessary?

N/A

Corrosion Numerical Index 0 to 1: Corrosion professional is involved during construction to ensure installation of accessories for implementing mitigation, monitoring, and maintenance activities 2 to 3: corrosion professional involved during the construction but unable to ensure that accessories are installed properly 4 to 5: corrosion professional is not involved during the construction 0 to 1: Infrastructure is properly hydrotested and the water used in the hydrotest properly removed, baseline conditions (e.g., inline inspection, CP current demand) established to ensure that the corrosion rate is and will remain at the predicted rate, and all data from the design stage is collected and properly stored in the database for future use 2 to 3: Infrastructure is properly hydrotested and the water used in the hydrotest is properly removed, but baseline conditions are not established 4 to 5: No documented evidence that the hydrotest is conducted properly and the infrastructure is commissioned properly 0 to 1: No. Based on the analysis performed and strategies implemented (e.g., use of corrosion resistant alloys) at the conceptual and design stages no addition corrosion control strategies are required

Cost (In Percent),)) age)

Stage at which the Cost is Incurred

Reference Chapter

17.00

Construction

8, 11

17.00

Commission

13

0.50

Conceptual, Design, Operation

7

CHAPTER 14 Management

Activity No.

896

Table 14.14 Overview of Corrosion Management Activities Continued

2 to 3: Yes. Based on the analysis performed at the conceptual and design stages

Mitigation strategies to control internal corrosion

N/A

18

Mitigated internal corrosion rate, target

mpy or mm/y

19

Effectiveness of internal corrosion mitigation strategies

mpy or mm/y

20

Selection of Mitigation to control external corrosion

N/A

3.00

Operation

7

0.50

Operation

7

1.00

Operation

7

0.50

Design, Operation

9

14.5 Activities of corrosion management

17

897

4 to 5: Yes. Based on current operating conditions of the infrastructure. 0 to 1: No mitigation strategy is implemented (as per activity 16) or mitigation practice implemented is timetested and proven to control the predominant mechanism of corrosion occurring under the operating conditions of the infrastructure 2 to 3: Mitigation strategy is established and aligned by trial and error method under the operating conditions and is proven to be effective 4 to 5: Mitigation strategy is not aligned with the operating conditions of the infrastructure 0 to 1: Mitigated corrosion rate is based on baseline corrosion rate (established as per activities 12 and 17) and efficiency of mitigation strategy 2 to 3: No basis for the selection of maximum corrosion rate 4 to 5: No anticipated maximum corrosion rate established 0 to 1: Mitigation practices are implemented (e.g., corrosion inhibitor is available) more than 99% of the time 2 to 3: Mitigation practices are implemented 95 to 99% of time 4 to 5: Mitigation practices are implemented less than 95% of time 0 to 1: The most appropriate strategies (coating and cathodic protection) selected based on current standards and industry best practices at the conceptual and design stages 2 to 3: Strategies (coating and cathodic protection) selected based on current standards and industry best practices

(Continued)

Table 14.14 Overview of Corrosion Management Activities Continued

Description of Activities

Value in (unit)

Corrosion Numerical Index

Stage at which the Cost is Incurred

Reference Chapter

21

Implementation of Mitigation strategies to control external corrosion

N/A

22

Mitigated external corrosion rate, target

mpy or mm/y

23

Effectiveness of external corrosion mitigation strategy

mpy or mm/y

24

Internal corrosion monitoring techniques

N/A

0 to 1: Corrosion control strategies implemented and baseline data collected within the first year of operation of the infrastructure 2 to 3: Corrosion control strategies implemented within the first year of operation of the infrastructure and baseline data collected afterwards 4 to 5: Corrosion control strategies implemented but baseline data not collected 0 to 1: Mitigated corrosion rate is based on baseline corrosion rate and efficiency of mitigation strategy 2 to 3: No basis for the selection of mitigated corrosion rate 4 to 5: No anticipated mitigated corrosion rate established 0 to 1: Mitigation practices are implemented (e.g., cathodic protection is available) more than 99% of the time 2 to 3: Mitigation practices are implemented 95 to 99% of time 4 to 5: Mitigation practices are implemented less than 95% of time 0 to 1: Two or more complimentary techniques that are proven to be effective in monitoring the corrosion type occurring in the segment are used 2 to 3: Only one type of monitoring technique that is provend to be effective in monitoring the corrosion type occurring in the segment is used

3.00

Conceptual, Design, Operation

9

0.50

Conceptual, Design, Operation

9

1.00

Operation

9

2.00

Operation

8

CHAPTER 14 Management

4 to 5: Selected based on previous version of standard which may not include all industry best practices

898

Activity No.

Cost (In Percent),)) age)

4 to 5: No monitoring is performed or technique used is not proven to be effective in monitoring the corrosion type occurring in the segment 25

26

Numerical value

0 to 1: Number of working probes cover all critical areas and non-critical areas 2 to 3: Number of working probes enough to cover most critical areas 4 to 5: Number of working probes not enough to cover all critical areas

1.00

Operation

8

mpy or mm/y

0.50

Operation

8

Accuracy of internal corrosion monitoring techniques

Percentage

0 to 1: The corrosion rates from two or more different types of monitoring probes agree with one another within 10% 2 to 3: The corrosion rates from two or more different types of monitoring probes agree with one another within 11 to 25 % 4 to 5: The corrosion rates from two or more different types of monitoring probes differ from one another by more than 25% 0 to 1: The corrosion rate from two or more different types of monitoring probes agree with one another within 10% and they agree with mitigated corrosion rate within 10% 2 to 3: The corrosion rate from two or more different types of monitoring probes agree with one another within 11 to 25 % and they agree with mitigated corrosion rate within 25% 4 to 5: The corrosion rate from two or more different types of monitoring probes differ from one another by more than 25% and they differ from mitigated corrosion rate by more than 25%

0.25

Operation

8

14.5 Activities of corrosion management

27

Number of probes per unit area to monitor internal corrosion Internal corrosion rates, from monitoring technique

899

(Continued)

Table 14.14 Overview of Corrosion Management Activities Continued

Value in (unit)

28

External corrosion monitoring techniques

N/A

29

Number of probes per unit area to monitor external corrosion

Numerical value

30

External corrosion rate, from monitoring technique

mpy or mm/y

31

Accuracy of external corrosion monitoring techniques

Percentage

Corrosion Numerical Index 0 to 1: Two or more complimentry techniques that are proven to be effective in monitoring the corrosion type occurring in the segment are used 2 to 3: Only one type of monitoring technique that is provend to be effective in monitoring the corrosion type occurring in the segment is used 4 to 5: No monitoring is performed or technique used is not proven to be effective in monitoring the corrosion type occurring in the segment 0 to 1: Working probes or measurements by above-ground measurement cover all critical areas and non-critical areas 2 to 3: Working probes or measurements by above-ground measurements cover most critical areas 4 to 5: Working probes or measurements by above-ground measurement do not cover all critical areas 0 to 1: The corrosion rates from two or more different types of monitoring probes agree with one another \within 10% 2 to 3: The corrosion rates from two or more different types of monitoring probes agree with one another within 11 to 25 % 4 to 5: The corrosion rates from two or more different types of monitoring probes differ from one another by more than 25% 0 to 1: The corrosion rates from two or more different types of monitoring probes agree with one another within 10% and they agree with mitigated corrosion rate within 10%

Stage at which the Cost is Incurred

Reference Chapter

2.00

Operation

11

1.00

Operation

11

0.50

Operation

11

0.25

Operation

11

CHAPTER 14 Management

Description of Activities

900

Activity No.

Cost (In Percent),)) age)

2 to 3: The corrosion rates from two or more different types of monitoring probes agree with one another within 11 to 25 % and they agree with mitigated corrosion rate within 25%

Frequency of inspection

Years

33

Percentage difference between targeted mitigated internal corrosion rate or corrosion rate from monitoring techniques and corrosion rate from inspection technique

Percentage

5.00

Operation

11

0.50

Operation

6, 7, 8

901

(Continued)

14.5 Activities of corrosion management

32

4 to 5: The corrosion rates from two or more differenttypes of monitoring probes differ from one another by more than 25% and they differ from mitigated corrosion rate by more than 25% 0 to 1: Frequency established based on sound engineering (e.g. RBI) and documented process 2 to 3: Frequency established based on some engineering process, but the process followed to make the decision is not clear and is not documented 4 to 5: More than 10 years or the infrastructure cannot be inspected (e.g., no pig launching or receiving facilities) 0 to 1: The corrosion rates from inspection technique and from the monitoring probes (or mitigated corrosion rate as established) agree within 10% 2 to 3: The corrosion rates from inspection technique and from the monitoring probes (or mitigated corrosion rate) agree with one another within 11 to 25% 4 to 5: The corrosion rates from inspection technique and from the monitoring probes differ by more than 25%

902

Table 14.14 Overview of Corrosion Management Activities Continued Stage at which the Cost is Incurred

Reference Chapter

Activity No.

Description of Activities

Value in (unit)

34

Percentage difference between targeted mitigated external corrosion rate or corrosion rate from monitoring techniques and corrosion rate from inspection technique Measurement data availability

Percentage

0 to 1: The corrosion rates from inspection technique and from the monitoring probes (or mitigated corrosion rate) agree within 10% 2 to 3: The corrosion rates from inspection technique and from the monitoring probes (or mitigated corrosion rate) agree with one another within 11 to 25% 4 to 5: The corrosion rates from inspection technique and from the monitoring probes differ by more than 25%

0.50

Operation

9, 10, 11

Various

0 to 1: All measurement data required for deciding corrosion conditions of the segment are available in a readily usable format 2 to 3: Measurement data required for deciding corrosion conditions of the segment are available but not in a readily usable format 4 to 5: Not all measurement data required for deciding corrosion conditions of the segment are available 0 to 1: The validity of the measured data is established using a documented procedure and the measured data is properly integrated to establish the corrosion rate

1.00

Operation

12

1.00

Operation

12

35

36

Validity and utilization of measured data

N/A

Corrosion Numerical Index

CHAPTER 14 Management

Cost (In Percent),)) age)

2 to 3: The measured data is utilized without any validation process and the measured data is properly integrated to establish the corrosion rate

Procedures for establishing the maintenance schedule

N/A

38

Maintenance activities

N/A

39

Internal corrosion rate, after maintenance activities

mpy or mm/y

1.00

Operation

12

5.00

Operation

12

0.25

Operation

6

14.5 Activities of corrosion management

37

903

4 to 5: The measured data is utilized without any validationprocess and the measured data is used general guidelines to establish the corrosion rate 0 to 1: Preventive type established based on experience, when the risk moves from low to ALARP stage, and scheduled on time 2 to 3: When the risk moves from ALARP to high risk stage, i.e., when conditions indicate that failure is imminent if the maintenance is not executed 4 to 5: When the risk is in the high risk stage in an ad hoc manner or corrective, i.e., after an incidence has occurred 0 to 1: The maintenance work is carried out as planned with all teams delivering their services as per schedule 2 to 3: The maintenance work is generally carried out as planned but not per schedule due some delay in the coordination of various team deliverables 4 to 5: The maintenance work needs to be modified from the original planned because the corrosion condition of the infrastructure is worst than anticipated 0 to 1: Corrosion rate after the maintenance activities is lower than the corrosion rate before maintenance activities 2 to 3: Corrosion rate after the maintenance activities is same as that before maintenance activities 4 to 5: Corrosion rate after the maintenance activities is higher than the corrosion rate before maintenance activities

(Continued)

Description of Activities

Value in (unit)

40

Percentage difference between internal corrosion rates before and after maintenance activities

Percentage

41

External corrosion rate, after maintenance activities

mpy or mm/y

42

Percentage difference between external corrosion rates before and after maintenance activity.

Percentage

Corrosion Numerical Index 0 to 1: Corrosion rate before the maintenance activities is within 10% of the corrosion rate established in activity 33 2 to 3: Corrosion rate before the maintenance activities is lower by more than 10% than the corrosion rate established in activity 33 indicating the maintenance activity is not necessary at this time 4 to 5: Corrosion rate before the maintenance activities is higher by more than 10% than the corrosion rate established in activity 33 indicating the maintenance activity should have been carried out earlier 0 to 1: Corrosion rate after the maintenance activities is lower than the corrosion rate before maintenance activities 2 to 3: Corrosion rate after the maintenance activities is same as that before maintenance activities 4 to 5: Corrosion rate after the maintenance activities is higer than the corrosion rate before maintenance activities 0 to 1: Corrosion rate before the mainteance activities is within 10% of the corrosion rate established in activity 34 2 to 3: Corrosion rate before the maintenance activities is lower by more than 10% than the corrosion rate established in activity 34 indicating the maintenance activity is not necessary at this time

Cost (In Percent),)) age)

Stage at which the Cost is Incurred

Reference Chapter

0.50

Operation

6, 12

0.25

Operation

10

0.50

Operation

9, 10, 11, 12

CHAPTER 14 Management

Activity No.

904

Table 14.14 Overview of Corrosion Management Activities Continued

4 to 5: Corrosion rate before the maintenance activities is higher by more than 10% than the corrosion rate established in activity 34 indicating the maintenance activity should have been carried out earlier Workforce e Capacity, skills, education, and training

Numerical value

44

Workforce e Experience, knowledge, and quality

Numerical value

45

Data management e Data to database

N/A

0.50

Operation

13

0.50

Operation

13

5.00

Operation

13

905

0 to 1: The number of workers is enough to carry out the work and all personnel involved have proper education and formal training to carry out the task 2 to 3: The number of workers is just enough to carry out the work and key personnel involved have proper education and formal training to carryout the task 4 to 5: The number of workers is not enough to ensure quality of work e the workers feel over worked; the educational and training requirements of the workers are not known 0 to 1: All personnel involved have at least five years of experience and knowledge in similar work 2 to 3: Key personnel have at least five years of experience and knowledge in similar work and others are gaining experience and knowledge under these key personnel and such arrangement is formally implemented 4 to 5: The experience and knowledge of personnel involved in the job cannot be established or verified 0 to 1: Data from different activities, measurements are automatically and systematically transferred to the database 2 to 3: Data from different activities, measurements are manually and systematically transferred to the database 4 to 5: Data transfer to database is not well established or no data management practice exists

14.5 Activities of corrosion management

43

(Continued)

Table 14.14 Overview of Corrosion Management Activities Continued

Value in (unit)

46

Data management e Data from database

N/A

47

Internal communication strategy

N/A

48

External communication strategy

N/A

Corrosion Numerical Index 0 to 1: Data is properly verified, systematically stored, and proactively passed onto appropriate persons or appropriate persons can retrieve the data in the format required 2 to 3: Data is properly verified, stored, and passed on to appropriate persons but not necessarily in the format he or she requires 4 to 5: Data transfer from the database is not well established or no data management practice exists 0 to 1: Internal communication strategy between all parties (including corrosion team, integrity team, subordinates, senior management, suppliers and service providers, workers, and regulators) is established, practiced, and documented 2 to 3: Internal communication strategy between only some entities is established, and communication with others is only on adhoc basis 4 to 5: No proper internal communication strategy exists or it exists but is not practiced 0 to 1: External communication strategy and communication person(s) with all parties (including failure investigators, regulators, stakeholders, general public, media, and lawyer/court) are established, practiced, and documented 2 to 3: External communication strategy and communication person(s) with only some entities are established, communication with others is only on ad hoc basis

Stage at which the Cost is Incurred

Reference Chapter

2.00

Operation

13

2.00

Operation

13

1.00

Operation

13

CHAPTER 14 Management

Description of Activities

906

Activity No.

Cost (In Percent),)) age)

4 to 5: No proper communication strategy exists or it exists but is not practiced and the communication person does not understand the actual corrosion situation 49

Corrosion management review

Years

50

Failure frequency

Numerical value

3.00

Operation

14

1.00

Operation

14

Very general guidelines and it various depending on the oil and gas sector, country of operation, and type of operation This category is very specific to the country, company, and location of the infrastructure and should be individually determined

))

14.5 Activities of corrosion management

)

0 to 1: The corrosion control activities, i.e., all 50 steps discussed in this table, are reviewed annually and lessons learned are implemented to improve the corrosion control practice 2 to 3: The corrosion control activities are reviewed between every 2 to 5 years 4 to 5: No fixed schedule is established to review corrosion control activities 0 to 1: Zero failure or incidence due to corrosion during the review period for the segment 2 to 3: Less than 5 failures due to corrosion but none in high consequence area 4 to 5: More than 5 failures in low consequence area or one failure in the high consequence area

907

908

CHAPTER 14 Management

14.5.3 Location of infrastructure The consequence of failure depends on the location of the infrastructure. The information presented in Tables 14.1, 14.2, and 14.3 may be used as a starting point to establish the consequence of failure. Identification and evaluation of alternate locations or routes may reduce the consequence of failure.

14.5.4 Quantification of risk The corrosion control measures depend on both the type of failure and where it takes place; for example the consequence of a low-pressure, sweet natural gas pipeline leak in a remote area is low when compared to a leak in sour gas pipeline in a populated area. By balancing the design and location of the infrastructure the overall risk may be reduced.

14.5.5 Life of infrastructure Certain decisions on corrosion management depend on the life of the infrastructure. For example Figure 14.17 compares inhibited carbon steel and clad carbon steel; if the life of infrastructure is long, clad carbon steel is economic. Carbon steel, with addition of corrosion inhibitors, is more economic for short life infrastructure. The corrosion professional may have no influence on the facility’s design life, but needs to manage corrosion depending on the stated operating life of the infrastructure.

14.5.6 Materials of construction In some cases, the optimum material for corrosion control may not be used due to various reasons, including cost, marketplace availability, and fabrication feasibility. In this situation, appropriate strategies should be established to control corrosion during operation. One way to influence and convince the design team to choose appropriate materials for corrosion control is to present data from standard laboratory experiments and/or case histories from similar operations.

14.5.7 Corrosion allowance The corrosion allowance is the wall thickness of the material designated as allowance for loss due to corrosion; this is in addition to the wall thickness required for containing pressure and other structural purposes. The corrosion allowance calculation is based on the predicted corrosion rate for the operating conditions, and on the anticipated life of the infrastructure. Results from standard laboratory experiments using materials selected for construction and/or field experience from using the materials in similar operating conditions are used to determine the corrosion allowance.

14.5.8 Normal operating conditions The infrastructure is designed, built, and intended to run at “normal operating conditions”. The infrastructures are mostly operated within the designed operating conditions. However, there will be occasions when decisions are consciously taken to operate the infrastructure above the normal operating conditions, e.g., higher temperatures, beyond designed life.

14.5 Activities of corrosion management

909

14.5.9 Upset conditions (Operating excursions) in the upstream segment The oil and gas infrastructures are in a continuum. Failures in the upstream segment may accelerate corrosion and impact the corrosion strategies of the segment under consideration. Upset conditions or operating excursions are typically unplanned and are due to failure of equipment, operator error, or malfunctioning of some system component. The corrosion professionals must be aware of such incidences and must evaluate, document, and report the short-term and long-term impacts of “abnormal operation” of the upstream segment on the corrosion strategies of the segment under consideration.

14.5.10 Upset conditions (Operating excursions) Upset conditions or operating excursions are typically unplanned and are due to failure of equipment, operator error, or malfunctioning of component of equipment. The corrosion professional must evaluate, document, and report the short-term and long-term impacts of “abnormal operation” of the infrastructure. A root cause analysis of excursions will improve the project design and reduce corrosion.

14.5.11 Mechanisms of corrosion The types of mechanisms can be deduced from operating experience with similar facilities and/or based on laboratory experiments conducted to simulate the anticipated operating conditions.

14.5.12 Maximum corrosion rate (Internal surfaces) The maximum corrosion rate should the rate of the most prominent or probable mechanism. For example, the practice of using a uniform corrosion rate to predict the localized pitting corrosion rate is not appropriate. The maximum corrosion rate may be an average corrosion rate or deduced by using extreme value statistical analysis. If the average corrosion rate is used, the spread of data, i.e., standard deviation, should be known.

14.5.13 Maximum corrosion rate (External surfaces) The maximum corrosion rate should the rate of the most prominent or probable mechanism. The influence of corrosion control measures (coatings and cathodic protection) must be taken into effect in establishing the corrosion mechanism and maximum corrosion rate. The maximum corrosion rate may be an average corrosion rate or deduced by using extreme value statistical analysis. If the average corrosion rate is used, the spread of data, i.e., standard deviation, should be known.

14.5.14 Installation of proper accessories This is one activity in which corrosion professionals are the least involved. However, the selected corrosion control practices can only be effectively carried out if the related equipment is properly installed (e.g., pig launcher, pig receiver, rectifier connection, corrosion inhibitor injection port, and

910

CHAPTER 14 Management

corrosion monitoring coupons and probes). By mandating the involvement of the corrosion professional and including them in the construction contract, the proper installation of accessories can be ensured.

14.5.15 Commissioning During commissioning, three key functions should be carried out: cleaning to ensure that the infrastructure is free from all construction errors (e.g., removal of tools, water, and other corrosion causing objects), establishment of baseline corrosion conditions, and transfer and storage of data from the design stage to the commissioning stage in the database system. Further, the commissioning procedure should be re-evaluated to remove errors that may contribute to or influence corrosion or escalate risk of corrosion during operation.

14.5.16 Mitigation to control internal corrosion Under certain conditions, mitigation strategies may not be implemented at the start of the project, but rather when operating conditions change. For example, the addition of corrosion inhibitors to a production pipeline becomes necessary when the oil-wet surface becomes a water-wet surface. Such a transition may occur when the percentage water-cut reaches a critical point (see chapter 7 for more information). Corrosion professionals may proactively develop an optimum corrosion mitigation strategy during the design stage.

14.5.17 Mitigation strategies to control internal corrosion Most oil and gas infrastructure, even those constructed using corrosion resistant alloy, may require some kind of mitigation, e.g., cleaning. By working with the monitoring and inspection team, the mitigation strategy may be established and aligned with the operating conditions of the infrastructure.

14.5.18 Mitigated internal corrosion rate – target To save costs, corrosion allowance is kept to a minimum, with the assumption that the mitigation practices carried out during operation will keep the corrosion rate low. Therefore the mitigated corrosion rate should be equal to or less than the target so that the infrastructure will continue to function safely for its service life. By performing laboratory experiments using standard methodologies to evaluate the efficiency of mitigation strategies, an appropriate corrosion rate target may be achieved.

14.5.19 Effectiveness of the internal corrosion mitigation strategy The mitigated corrosion rate assumes that the mitigation strategy is available and effective 100% of the time. The mitigated corrosion rate is directly correlated to the percentage of time mitigation strategy functions properly. The availability and effectiveness of the mitigation strategies may be increased by working with maintenance team and vendors.

14.5 Activities of corrosion management

911

14.5.20 Selection of mitigation strategies to control external corrosion Most parts of the world have regulations that require underground energy infrastructure to be protected by both protective coatings and cathodic protection. The above-ground structure may also be coated with paints (for esthetic reasons) or with thermal insulation which also provides some degree of corrosion protection. Coordinated teamwork at the conceptual and design stages will lead to optimum mitigation strategy.

14.5.21 Implementation of mitigation strategies to control external corrosion Mitigation strategies, such as inspecting external coatings, should be performed during the commissioning stage, and the cathodic protection should be installed within one year of commissioning the structure. By working with the monitoring and inspection teams, the mitigation strategies should be optimized based on operating conditions of the infrastructure and baseline data should be collected.

14.5.22 Mitigated external corrosion rate – target To save costs, corrosion allowance is kept to a minimum, with the assumption that the mitigation practices (coatings and cathodic protection) will keep the corrosion rate acceptably low. By performing laboratory experiments using standard methodologies to evaluate the efficiency of mitigation strategies, the appropriate corrosion rate target may be established.

14.5.23 Effectiveness of external corrosion mitigation strategy The mitigated corrosion rate assumes that the mitigation strategy is available and effective 100% of the time. The mitigated corrosion rate increases with the percentage of time over which the mitigation strategy (i.e., cathodic protection) does not function properly. Similarly, the incidence of mitigated corrosion increases in proportion to the rate of deterioration of the protective coating systems. By working with maintenance, and vendors, the availability and effectiveness of mitigation strategies may be increased.

14.5.24 Internal corrosion monitoring techniques Intrusive monitoring techniques are normally sensitive to 1 mpy level. However, the corrosive rate monitored on the intrusive probes is assumed to represent corrosion of the infrastructure. In contrast, non-intrusive techniques are comparatively less sensitive (i.e., 10 mpy). But they monitor the actual infrastructure as opposed to a surrogate sensor. To be effective, both types of monitoring techniques should be used. The effectiveness of the monitoring techniques can be increased by field testing.

14.5.25 Number of probes to monitor internal corrosion Industry guidelines for the number of probes required to ensure that the infrastructure is adequately covered do not exist. Therefore this number should be established from operating experience, by trial and error. Potential exists to develop industry standards to achieve adequate probe monitoring coverage according to internal surface area.

912

CHAPTER 14 Management

14.5.26 Internal corrosion rates from monitoring techniques When comparing corrosion rates from different probes it should be recognized that some techniques provide a continuous corrosion rate, some provide an instantaneous corrosion rate, and some techniques provide a time averaged corrosion rate. Collaboration with monitoring techniques vendors and corrosion professionals will improve the agreement between various techniques.

14.5.27 Accuracy of internal corrosion monitoring techniques The validity of the techniques to monitor the type of corrosion occurring and the locations of the probes should be ascertained. If the monitoring techniques are appropriate, normally the corrosion rate from the monitoring technique (rather than mitigated corrosion rate targeted from activity 18) should be used for further corrosion management activities. Personnel involved in activities 12, 18, and 27 are encouraged to collaborate to improve the agreement between corrosion rates generated by different methods.

14.5.28 External corrosion monitoring techniques Certain monitoring equipment is placed in a fixed location, whereas others are mobile (i.e., a person moves the probe over the infrastructure) or remote (i.e., a remotely operated vehicle moves the probe over the infrastructure). To be effective, different types of monitoring techniques should be used. By conducting field tests to validate additional techniques for monitoring the type of corrosion occurring, the effectiveness of the technique may be ascertained.

14.5.29 Number of probes to monitor external corrosion Industry guidelines for the number of probes or number of measurements required to cover the infrastructure adequately do not exist. Therefore the numbers should be established from operating experience, by trial and error. Future development of industry standards may identify the number of probes for adequate monitoring coverage according to external surface area.

14.5.30 External corrosion rate from monitoring technique When comparing corrosion rates from different probes it should be recognized that fixed probes make repeat measurements as a function of time, whereas mobile probes make repeat measurements as a function of distance. Collaboration with monitoring techniques vendors and corrosion professionals will improve the agreement between various techniques.

14.5.31 Accuracy of external corrosion monitoring techniques The validity of the techniques to monitor the type of corrosion occurring should be ascertained. If the monitoring techniques are appropriate, normally the corrosion rate from the monitoring technique (rather than mitigated corrosion rate established in activity 22) should be used for further corrosion management activities. Personnel involved in activities 13, 22, and 31 are encouraged to collaborate to improve the agreement between corrosion rates from the different methods.

14.5 Activities of corrosion management

913

14.5.32 Frequency of inspection In some countries, the frequency of inspection is regulated and mandated. Some inspection techniques can differentiate between internal and external corrosion, so both internal and external corrosion rates can be deduced from a single inspection run. By performing two inspections at close intervals as well as by rigorous risk-based inspection (RBI) process, the required frequency of inspection may be established.

14.5.33 Percentage difference between internal corrosion rates from monitoring and inspection techniques The validity of the techniques to measure the type of corrosion occurring should be ascertained. If the inspection technique is appropriate, the corrosion rate from the inspection technique (rather than mitigated corrosion rate targeted in activity 18 or corrosion rate from monitoring techniques established in activity 26) should be used for further corrosion management activities. Personnel involved in the establishment of different corrosion rates in activities 18, 26, and 33 are encouraged to collaborate to improve the agreement between various corrosion rates generated by the different methods.

14.5.34 Percentage difference between external corrosion rates from monitoring and inspection techniques The validity of the techniques to measure the type of corrosion occurring should be ascertained. If the inspection technique is appropriate, the corrosion rate from the inspection technique (rather than mitigated corrosion rate targeted in activity 22 or corrosion rate from monitoring techniques established in activity 30) should be used for further corrosion management activities. Personnel involved in the establishment of different corrosion rates in activities 22, 30, and 34 are encouraged to collaborate to improve the agreement between various corrosion rates generated by the different methods.

14.5.35 Measurement data availability Proper data is required to identify corrosion conditions in the segment. Extensive data is collected by groups within companies for reasons other than corrosion control. Sharing of databases with the corrosion management team will facilitate improvements to the corrosion control program and improve project economics.

14.5.36 Validity and utilization of measured data The reliability of the measurement and lag time between measurement and integration of measured data with other corrosion parameters should be considered before using the data for the corrosion management process. Computer software programs are available to readily perform statistical analyses to establish the precision of the data. The data may be validated by developing a documented procedure and by prescribing a minimum precision.

914

CHAPTER 14 Management

14.5.37 Procedures for establishing the maintenance schedule The extent of maintenance depends on the level to which the corrosion risk has been allowed to escalate. More extensive and complex maintenance activities are required to mitigate higher risk corrosion. Regular meetings involving corrosion teams responsible for corrosion control (i.e., those involved in activities 12, 18, 26, and 33 for internal corrosion and activities 13, 22, 30, and 34 for external corrosion control) as well as operational teams are necessary to prioritize, plan, and schedule the corrosion related maintenance activities.

14.5.38 Maintenance activities The window for carrying out maintenance activities is normally small due to operational and other requirements. Within the small window, the activities of several teams need to be coordinated. By having a ‘lessons learned’ debriefing meeting after each maintenance activity, future maintenance activities can be optimized and corrosion conditions may be predicted with higher accuracy.

14.5.39 Internal corrosion rate after maintenance activities When maintenance is carried out, steps should be taken to decrease the influence of factors causing corrosion. Consequently, the corrosion rate should decrease after maintenance. However, a reduction may not be possible in some situations because the already implemented corrosion control program has kept the corrosion rate at the low target. Such situation may occur, when the section had reached its designed life time and hence needed replacement. Maintenance activities should be reviewed to ensure that no unintended action took place that may increase the corrosion rate. Team meetings with corrosion, maintenance, and operations personnel can identify opportunities to reduce the corrosion rate by altering the operating and maintenance procedures.

14.5.40 Percentage difference between internal corrosion rate before and after maintenance activities Maintenance activities provide an opportunity to physically examine the infrastructure, for example by excavating an underground infrastructure and removing its protective coating. The actual remaining wall thickness can be measured and the most real corrosion rate can be determined. Personnel involved in the establishment of different corrosion rates (i.e., those involved in activities 12, 18, 26, 33, and 38) are encouraged to collaborate to improve the agreement between the various corrosion rates.

14.5.41 External corrosion rate after maintenance activities When maintenance is carried out, steps should be taken to decrease the influence of factors causing corrosion. Consequently, the corrosion rate should decrease after maintenance. However, a reduction may not be possible in some situations because the implemented corrosion control program has kept the corrosion rate at the low target. Maintenance activities should be reviewed to ensure that no unintended action took place that may increase the corrosion rate. Team meetings with corrosion, maintenance, and operations personnel can identify opportunities to reduce the corrosion rate by altering the operating and maintenance procedures.

14.5 Activities of corrosion management

915

14.5.42 Percentage difference between external corrosion rate before and after maintenance activity Maintenance activities provide an opportunity to physically examine the infrastructure, for example by excavating an underground infrastructure and removing its protective coating. Therefore, the actual remaining wall thickness can be measured and the most real corrosion rate can be determined. Personnel involved in the establishment of different corrosion rates (i.e., those involved in activities 13, 20, 30, 34, and 41) are encouraged to collaborate the agreement between the various corrosion rates determined.

14.5.43 Workforce – capacity, skills, education, and training There is no industry standard to provide guidelines for the number of workers required per unit surface area (internal and external) to carry out corrosion control activities properly. This may be a difficult target to establish. However, collaboration between companies to develop an industry guideline standard would be useful. There may be some company specific best practices for specific corrosion control activities. Companies may consider these best practices to be proprietary and confidential. Workers in certain sectors of the oil and gas industry are mandated to have a minimum education and formal training before being allowed to undertake work. Many industry associations offer shortterm formal education and training programs to qualify personnel for specific tasks. By developing a career plan for workers in which attending formal education and training programs are a mandatory requirement, their ability to perform specific tasks may be ensured.

14.5.44 Workforce – experience, knowledge, and quality The oil and gas industry is currently experiencing very high turnover, with many experienced workforce members retiring. This is opening up opportunities for young leaders. The practical knowledge of the workforce is reflected in the quality of work, and is to some extent related to experience. By developing a mentorship program in which young personnel work with experienced personnel over an extended period of time, knowledge transfer may be facilitated.

14.5.45 Data management – Data to database Most people work within the perimeter of their key functionality. It is the responsibility of the corrosion management process to transfer information from teams that have it to those teams that need it. For example, the planned temporary outage of corrosion inhibitor or shutting off of cathodic protection rectifier must be communicated to the corrosion monitoring team. The corrosion management process should coordinate information collection and distribution. Data collection and information technology (IT) is an integral part of corrosion management and is required by regulators in many sectors of the oil and gas industry. The data collection process may be streamlined by implementing automatic data collection and entry processes. Several commercial databases are available for automatic data collection and entry. It is feasible to maintain remote corrosion databases to facilitate data sharing and off-line assessments.

916

CHAPTER 14 Management

14.5.46 Data management – Data from database The importance of data management and analysis is increasingly recognized and is increasingly being regulated in many parts of the oil and gas industry. By having a knowledgeable third party company systematically, proactively, and regularly analyze and qualify the data, and format them in the manner required by corrosion professional, the reliability and use of the data may be vastly improved.

14.5.47 Internal communication strategy The importance of a communication strategy is not fully recognized in the oil and gas industry. By scheduling regular meetings (weekly, monthly, quarterly biannually, or annually) with all parties involved, the important aspects of corrosion control may be communicated, discussed, debated, and practical solution developed. Improved communications will improve the corrosion management program and in turn improve the economic performance of the project.

14.5.48 External communication strategy Communications with external parties (e.g., failure investigators, regulators, stakeholders, public, regulatory agencies) after a corrosion incident has occurred must be accurate, objective, and transparent. The corrosion professional is obligated to provide information to incident investigation teams. The corrosion professional must realize it is not possible to immediately identify and communicate the root cause because important data and facts are lacking in the early stages of the incident. Time is required to assemble the information needed to give the full picture of the incident. Eventually, communications with external parties can include the lessons learned, and details about corrosion control strategies implemented to prevent a repeat incident.

14.5.49 Corrosion management review for continuous improvement No process is perfect at the beginning. With experience and from lessons learned, opportunities arise to further improve the process. Therefore systematic and periodic review of the implementation of corrosion control activities should be conducted, and opportunities to correct and further improve these activities should be identified. Unless the corrosion control activities are reviewed and the lessons learned are incorporated, the corrosion management program will not succeed. In this record thorough failure analysis provide opportunities to avoid similar failures in the future.25 By adjusting the frequency of review meetings, by expanding participants to include operations and maintenance personnel, and by appraising senior management of the potential impact of corrosion risk if not proactively controlled, corrosion management will be effectively implemented. Normally the corrosion management process should start from the conceptual stage. However, if the corrosion management process is being implemented in an existing operations, the process can be started conveniently by reviewing the applicability of various activities, i.e., start at Activity 49. By identifying the top five activities with the highest scores and by implementing solutions to reduce them, the corrosion management practice may be effectively started.

References

917

14.5.50 Failure frequency As the corrosion management practice improves, the frequency of failure or incidence due to corrosion will decrease. To achieve this, the corrosion numerical index score should be 0 to 1 in all 50 categories discussed Table 14.14. The oil and gas industry is striving to reach ‘zero failure’ and is not comfortable with any target other than this. The target of ‘zero failure due to corrosion’ may be achieved when corrosion management practice reaches 100% perfection.

References 1. Muhlbauer WK, editor. Pipeline Risk Management Manual: Ideas, Techniques, and Resources. 3rd ed. Elsevier; 2004. ISBN-13: 978-0-7506-7579–6, page 4. 2. Horrocks P, Adair S. Chapter 4.34,’Risk based inspection’ in Shreir’s Corrosion, Volume 4, Management and Control of Corrosion. In: Cottis B, Graham M, Lindsay R, Lyon S, Richarson T, Scantelbury D, Stott H, editors. Elsevier; 2010. ISBN: 978-0-444-52788-2, p. 3096. 3. Abes Jake. A management systems approach to pipeline integrity. Second Canada-India Workshop on Pipeline Integrity. Canada: Alberta, Calgary; Oct. 25–26, 2008. 4. Reason JT. Managing the risks of organizational accidents. Ashgate Publishing Ltd; 1997. 5. Simola K, Mengolini A, Bolado-Lavin R. Formal expert judgement: An overview; 2005. EUR 21772 EN. 6. Dawson JL. Chapter 4.30, ‘Corrosion management overview’. In: Cottis B, Graham M, Lindsay R, Lyon S, Richarson T, Scantelbury D, Stott H, editors. Shreir’s Corrosion, Volume 4, Management and Control of Corrosion. Elsevier; 2010. ISBN: 978-0-444-52788-2, p. 3020. 7. Muhlbauer WK, editor. Pipeline risk management manual: ideas, techniques, and resources. 3rd ed. Elsevier; 2004. ISBN-13: 978-0-7506-7579-6, page 296. 8. Desjardins G. Corrosion rate and severity results from inline inspection Data. CORROSION 2001. Paper #1624 NACE International, Houston, TX, USA (2001). 9. Muhlbauer WK, editor. Pipeline risk management manual: ideas, techniques, and resources. 3rd ed. Elsevier; 2004. ISBN-13: 978-0-7506-7579–6, Based on contents of Chapter 7. 10. US Department of Transport, 49 CFR, Appendix E to Part 192: Guidance on determining high consequence areas and on carrying out requirements in the integrity management rule (Latest version). 11. Prugh RW, Johnson RW. Guidelines for vapor release mitigation. New York: American Institute of Chemical Engineers; 1988. 12. Risk assessment in the Federal Government: managing the process. Washington, DC: National Research Council, National Academy Press; 1983. 13. Risk based inspection resource document. American Petroleum Institute Publication; 2002. API 581. 14. Kiefner JF. ‘A risk management tool for establishing budget priorities’, Risk Assessment and Management of Regulated Pipelines Conference, NACE TechEdge Series, Houston, TX, Feb. 10–12, 1997. 15. Schade J. ‘Life cycle cost calculation models for buildings’, Based on a part of InPro. an integrated project co-funded by the European Commission within the Sixth Framework Program, (http://www.inpro-project. eu), [accessed 12.23.11]. 16. Verink ED. Corrosion economic calculations. In: ASM Hand Book, Corrosion Vol. 13.A, ‘Corrosion: Fundamentals, Testing, and Protection’ 2003. p. 941–5. ISBN: 0-87170-705-5. 17. Dawson J, John G, Oliver K. Chapter 4.41,’Management of corrosion in the oil and gas industry’ in Shreir’s Corrosion, Volume 4, Management and Control of Corrosion. In: Cottis B, Graham M, Lindsay R, Lyon S, Richarson T, Scantelbury D, Stott H, editors. Elsevier; 2010. ISBN: 978–0-444–52788–2, p. 3242. 18. Kennedy I. “Driving Efficiency from the Operation Phase of the Oil and Gas Asset Life Cycle”, http://www. echarris.com/research__views/expert_views.aspx; [accessed on 02.09.13].

918

CHAPTER 14 Management

19. Guidance for corrosion management in oil and gas production and processing. London: Energy Institute; May 2008. ISBN: 978:0 85293 497 5. 20. ‘Economics of corrosion’, NACE 3C194. Technical Committee Report, (Withdrawn. Houston, TX: NACE International; 1994. 21. Risk Based Inspection: Developments of Guidelines, ASME Research Report, May 1, 1993, ASMETwo Park AvenueNew York, NY 10016-5990 22. Sherry AH. Chapter 4.35,’Assessment of fitness for service’ in Shreir’s Corrosion, Volume 4, Management and Control of Corrosion. In: Cottis B, Graham M, Lindsay R, Lyon S, Richarson T, Scantelbury D, Stott H, editors. Elsevier; 2010. p. 3102–16. ISBN: 978-0-444-52788-2. 23. Vernink ED. Economics of corrosion. In: Revie RW, editor. Uhlig’s Corrosion Handbook. 3rd ed. New Jersey: John Wiley and Sons; 2011. ISBN: 978–0.470-87825-7, p. 21–30. 24. NACE Standard Report, “Guide to improving pipeline safety by corrosion management”. NACE International, Houston, TX, USA,; 2011. Item #24245. 25. A. Bhardwaj, S.Degan, N.M. Rao, and R.P. Nagar, Corrosion - Case Histories00 , NACE Gateway of India Section, ISBN: 81-87099-47-X, 2009, Quest Publications, D60, Vasant Villa, Amrut Nagar, Ghatkopar (W), Mumbai, 400-086, India.

Appendix I: Abbreviations

Keywords Key to Typefaces in Table Normal: equation Italics: section Underlined: table Bold: figure

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure 6.42, 10.41

Abbreviation

Description

a aglyc ajet

6.27 6.15 8.13

aVan A

Constant Constant to account for glycol effect Hydrodynamic constant used in jet impingement flow calculation Van der Waal’s constant Surface area

AC

Alternating current

5.23

ACME

Anode (A), cathode (C), metallic conductor (M), and electrolytic conductor (E) Automatic custody transfer Alternating current voltage gradient de Waard and Milliams constant Atmospheric distillation unit Auxiliary electrode (commonly known as couter electrode)

5.2

ACT ACVG ADM ADU AE

4.53 4.24

7.5, 8.16, 9.2, 11.10 8.2.2.b , 9.3.3.b , 11.3

2.18 11.3 6.7 2.17 8.1 (Continued)

919

920

Appendix I: Abbreviations

dContinued

Abbreviation

Description

AFNOR

Association franc¸aise de Normalisation or French national organization for standardization Above-ground markers Silver/silver chloride electrode Activity of corrosion inhibitor in percentage. Aluminum As low as reasonably possible Measure of total solids effect in LSI Fraction of surface bare Analysis of variance Artificial neural network American National Standard Institute Acid producing bacteria

AGM Ag/AgCl Ainh Al ALARP ALSI AMe ANOVA ANN ANSI APB APS Aq ASc AST ATP ATU Awt B B BAT Bbl BCC BD BDM BEP BF [Bioac.] [Biode.] BLSI BOP BPD

Adenosine 5 phosphosulphate Piezoelectrically active area of a quartz crystal Fraction of surface covered with layer Above-ground storage tank Adenosine Triphosphate Alberta Transportation and Utilities Atomic weight Tafel Constant Constant Best Available Technology Blue barrel or barrel Body-centered cube Biocide decay factor De Waard and Milliam constant Best Environmental Practice Biocide factor Effect of bioaccumulation Effect of biodegradation Measure of temperature effect in the LSI Blow-out preventer Barrel per day

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

3.4

12.3.11

11.5 5.2 7.7 9.2.5 14.12 6.48 6.3.6 8.5.1. 13.4.6 10.2.2 4.9

13.4.6

5.14, 10.2.2.a , 11.7.6

8.2.4 10.4 6.3.6 1.7.4 8.2.4 1.6 8.24 8.18 10.41 7.4 1.2 3.2 6.42 6.7 7.4 6.42 7.4 7.4 6.48 2.2 1.5

1.5, 6.3.2.h

Appendix I: Abbreviations

921

dContinued

Abbreviation

Description

BS BSI BS&W BTU bVan C1

British Standard British Standard Institute Basic sediment and water content British Thermal Unit Van der Waal’s constant Constant used in Srinivasan’s model to calculate pH Constant used in Srinivasan’s model to calculate pH Conversion constant Concentration of a property measured Capital expenditure Canadian Association of Petroleum Producers Current attenuation technique Coal bed methane Consequence of risk Coating conductance Coating conductance per unit area Coating capacitance Normalized coating conductance in soil of constant resistivity Corrosion rate (in the absence of mechanical forces) Corrosion in the presence of mechanical forces Maximum corrosion rate Corrosion rate in sour environment Corrosion rate in sweet environment. Canadian Crude Quality Technical Association Copper-copper sulfate (reference electrode) Catalytic cracking unit Closed-cycle-vapor-thermo-generator Cathodic disbondment Critical Dilution Factor Double layer capacitance

C2 C4 Ca CAPEX CAPP CAT CBM CC CC CCA Ccoat CCnormalized Ccorr Ccorr.M Ccorr.max Ccorr.sour Ccorr.sweet CCQTA CCS CCU CCVTG CD CDF Cdl

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

9.2.5 3.4 2.18 1.2 4.53 6.16

14.3.3.f

6.17 4.13 12.1 13.2.2.a 13.5.9 11.3.7 1.4.2.e 14.2 11.3 11.7 10.2.2.b 11.12 6.55

14.3.3.a

11.9 14.5

6.11, 8.35, 10.42, 14.4

8.37 14.4 6.31 6.31 13.5.9 5.2 2.17 9.3.3.d 10.2.2.a 7.4 10.2.2.b

8.4, 9.3.4. A , 11.3.1 2.31.5

(Continued)

922

Appendix I: Abbreviations

dContinued

Abbreviation

Description

CE

Conversion constant to convert the result to kPa/m (0.0999) to account for elevation change, Counter electrode (May also be known as auxiliary electrode) European Committee for Standardization Canadian Energy Pipelines Association Constant extension rate test (more commonly known as SSRT) Cost of the failure. Corrosion rate (mpy or mm/y) from below-ground measurement Computational fluid dynamics Corrosion rate based on field operating condition Code of Federal Regulations (USA) Cyclic galvno-staircase polarization Chemical Hazard Assessment And Risk Management Concentration of lattice-dissolved hydrogen Cost of hydrocarbon sold to the customer Cost of hydrocarbon ‘esent underground Head conversion constant. Hydrogen atom concentration in a metal Threshold hydrogen concentration in a metal for it to be susceptible to HIC Concentration of acetic acid Cold heavy oil production with sand Catalytic Hydrocracking Unit Corrosion influenced erosion Corrosion rate (mpy or mm/y) from ILI survey Concentration of corrosion inhibitor Close interval potential survey Close interval survey Cost in use

CE CEN CEPA CERT CF CFBGM CFD Cfield CFR CGSP CHARM CH CHCC CHCU CHead CHo (CHo)TH [CH3COOH] CHOPS CHU CIE CILI.survey Cinh CIPS CIS CIU

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

4.11

8.1 3.4 13.5.9 8.2.1.c 14.9 10.39 4.2.4.c 10.23

8.2.2.

1.6 8.2.2.b 7.4 6.4 14.1 14.1 4.12 5.18.2

6.2.1, 6.5, 8.1

5.18.2 4.87 1.4.2.a 2.31.7 4.8 10.30 7.6 11.3.1 11.3 14.3.3.a

6.6 2.9 12.3.14

Appendix I: Abbreviations

923

dContinued

Abbreviation

Description

CLab

Corrosion rate based on laboratory coating evaluation Clostridia cultures Measure of calcium carbonate content in the LSI Cost of converting lower-value hydrocarbons to higher-value hydrocarbons Compressed natural gas Effect of CO2 partial pressure Effect of compatibility. Concentration of corrosion inhibitor in ppm Cost of corrosion inhibitor per ppm Cathodic protection

CLOS CLSI CLV_HV

CNG [CO2] [Comp.] [Concn.] [Cost] CP CPC CPCR CPP CPT CRA CRF C.RNo Inhibitor C.RInhibitor [C.R]Mean [C.R]std

CRU CSPG CSS CSSR Cstd.coat

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

10.15 6.43 6.48 14.1

1.7.6 7.2 7.4 7.2 7.2 2.11

2.35

5.2, 5.16, 9.1, 13.2.2.i

Cold-spot corrosion Cathodic protection current requirement Critical pitting potential Critical pitting temperature Corrosion-resistant alloy

5.24 11.3

Capital recovery factor Corrosion rate in the absence of corrosion inhibitor Corrosion rate in the presence of corrosion inhibitor Average or mean corrosion rate in the presence of corrosion inhibitor Standard deviation of corrosion rate (which is a measure of the repeatability of the test data) Catalytic Reforming Unit Constant in the single phase gas flow equation Cyclic steam stimulation Cyclic slow strain rate test Assumed maximum corrosion rate when the coating is fully protective

14.9 7.1

7.15

7.1

7.15

6.4.2 6.4.2 2.3

3.3.8, 7.1, 8.2.1.c 13.2.2.a

7.2 7.2

2.31.10 4.14 1.4.2.a 8.2.1.c 10.15

2.9

(Continued)

924

Appendix I: Abbreviations

dContinued

Abbreviation

Description

CSurveys CT Cth CTHo

Corrosion rate based on surveys Type of contents released Threshold hydrogen concentration Threshold hydrogen atom concentration Flow conversion constant Corrosion under insulation Coefficient of variation (also known as pit indicator) Concentration of droplets in the gas core (mass per unit volume calculated on a homogeneous basis). Diffusion coefficient Diameter Direct current Number of days for Clostridia cultures isolated from samples to turn positive Direct current voltage gradient Maximum depth (mils or mm) of the corrosion feature as determined by the direction measurement Diameter of pipeline downstream to expansion Diameter of pipeline downstream to contraction Diethanolamine Diethyene glycol Discount factor Deposit or fouling factor Diglycolamine (diaminoethooxyethanol) Number of days for Gallionella cultures isolated from samples to turn positive Digylcidyl Ether of Bisphenol-A Resin Density of gas and liquid mixture Internal diameter of pipeline Diffusivity of species i Internal diameter of the casing Discontinuity factor Diluted bitumen

Cu CUI CV Cw

D dA DC D[Clos] DCVG DDM

ddown,Ex ddown,Con DEA DEG DF DFF DGA D[Gall] DGEBA DGL di Di di,casing DiF Dilbit

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

10.31 14.5 8.2.1.b 6.2.1 4.12 2.31 8.34

5.20

4.54

6.1 9.12 8.2.2.b 6.43

8.1, 8.7 9.3.3.b , 11.3

11.3 10.39

4.40 4.41 2.14.2 6.3.1.f 14.9 6.44 2.14.2 6.43 9.2.1.e 6.38 4.5 4.59 4.42 6.42 2.16

7.8

7.8

Appendix I: Abbreviations

925

dContinued

Abbreviation

Description

DILI

Maximum depth (mils or mm) of the corrosion feature as determined by the ILI inspection Diameter of the jet Measure of alkalinity in the LSI Deoxy Ribonucleic acid Outer diameter of pipe Density of oil US Department of Transportation Diameter of pipe Discount payback period Diameter of sand particles Double-submerged arc welding Differential scanning calorimetry Number of days for sulfate reducing bacteria cultures isolated from samples to turn positive Distance slipped Density of specimen Density of soil Outer diameter of the tubing Dissipation rate of anode in the cathodic protection system Differential thermal analysis Distance tubing is off the center (used to calculate pressure drop in annular flow) Diameter of pipeline upstream to contraction Diameter of pipeline upstream to expansion Difference in surface energy between a steel-oil and a steel-water interface Electrons Potential Potential according to the NernstLatimer convention Absolute error Equivalent annual cost

djet DLSI DNA do Doil DOT dpipe DPP dsand DSAW DSC D[SRB]

dslip Dspecimen Dsoil do,tubing Dt DTA dtub.off dup,Con dup,Ex Dwo eE E) EA EAC

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

10.30

8.19 6.48 8.2.4 2.2 6.30 1.6 4.7 14.3.2.b 4.47 3.3.1.c 10.2.2.a 6.43

6.12, 8.5, 10.41

10.2 8.16 10.1 4.42 9.19 10.2.2.a 4.44 4.41 4.40 4.70 5.1 5.7 5.5

11.13

12.5 14.3.2.c (Continued)

926

Appendix I: Abbreviations

dContinued

Abbreviation

Description

Eb

The breakdown potential (potential positive to which passive surface layer is destroyed and transpassive region starts) Electromagnetic current attenuation technique Concentration of chemical (e.g., corrosion inhibitor) required to adversely affect 50% of a species Corrosion potential Epifluorescence Cell Surface Antibody Extent of damage Energy dispersive spectrometry Ethylenediaminetetraacetic acid Energy dispersive X-ray Enzyme electrode Eccentricity of tubes (used to calculate pressure drop in annular flow Enhancement factor of erosioncorrosion Electric field mapping Redox potential Redox potential of hydrogent Extra high resolution magnetic flux leakage Erosion-influenced corrosion Emulsion inversion point Electrochemical impedance spectroscopy Electromagnetic acoustic transducer Electro-motive force Effect of emulsion Electrochemical noise Standard redox potential (according to Gibbs-Stockholm convention) Enhanced oil recovery Ehylene propylene diene monomer Potential positive to which passive surface layers are formed. Electrochemical reactivation

ECAT EC50

Ecorr ECSA ED EDS EDTA EDX EE eecc EFEC EFM Eh EH+/H EHR MFL EIC EIP EIS EMAT EMF [Emul.] EN Eo EOR EPDM Epp EPR

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

8.28

8.2.2.b

11.3 7.4

8.26 8.2.4 14.5 3.2.3 2.10 3.2.3 8.2.4 4.44

7.6

6.39 8.3.14 6.7.6 5.2 8.4.7 4.8 4.3.2 8.2.2.b 11.5.2.d 5.2 7.4 8.2.2.b. 5.6 2.7 9.2.2.i 8.28 8.2.8

6.11

12.3.14 6.5.1.b. 10.2.2.b., 11.3

Appendix I: Abbreviations

927

dContinued

Abbreviation

Description

Eprot

Potential at which passive layers are stable and protective Electrochemical quartz crystal microbalance Electrical resistance probe Relative error Electric resistance welding Environmental sensitivity Electric submersible pump Equivalent weight Faraday constant (96,487 C/mol) Friction factor Transmission factor (dimensionless) e reciprocal of friction Failure assessment diagram Fusion-bonded epoxy Flammability of content Calcite correction factor Face-centered cube Fugacity of carbon dioxide Correction factor for water condensation Design factor Front end engineering design Front End Loading Flow factor Fitness for service Fugacity of gas Factor for accounting for the effect of glycol Mass fraction of an element i in an alloy Flow-induced localized corrosion Corrosion inhibitor film thickness in mil Fluorescent in situ hybridization European Fitness for Service Thematic Network Joint factor Location factor

EQCM ER ER ERW Es ESP EW F f 1/f FAD FBE Fc Fcalcite FCC FCO2 Fcond Fdesign FEED FEL FF FFS Fg Fglyc fi FILC finh FISH FITNET-TN Fjoint Flocation

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

8.28

8.2.2.b

8.2.2.b

10.2.2.b

8.3.2 12.6 3.3.1.c 14.7 2.4 8.22 5.5 4.7 4.14

12.3.14

14.3.3.f 9.2.1.e 14.6 6.28 3.2 6.13 6.55

6.5, 8.1 4.30, 4.42

6.28

2.2 14.3.3.b 14.3.3.b 6.44 14.3.3.f. 6.12 6.15 8.25 4.5.2 7.7 8.2.4 14.3.3.f

6.5, 8.2.2

2.2 2.2 (Continued)

928

Appendix I: Abbreviations

dContinued

Abbreviation

Description

fmic [Foam] fq Fr FRP Fsat Fscale Ftemperature FV g GALL GHG GOR gpm H [H2S] hA

Factors influencing MIC Effect of foaming Frequency of the quartz crystal Froude number Fiber-reinforced plastic Saturation factor Factor for accounting for surface layer Temperature factor Future value Acceleration due to gravity Gallionella cultures Greenhouse gas Gas to oil ratio Gallons per minute Head Effect of H2S partial pressure Depth below the surface to the center of the anode Height (or, if horizontal, the width) of the accessory (used for calculating pressure drop) Heat-affected zone Hazardous materials Hydrogen blistering Brinell hardness measured using tungsten carbide ball Hexagonal-close packed Hydrocacking Unit Downstream elevation High-density polyethylene Hydrodesulfurization Hydrogen embrittlement Hydrofluoric alkylation unit Heavy gas oil Hydrogen induced cracking Hydrogen induced disbondment Jet nozzle tip to specimen surface distance in the jet impingement apparatus Higher heating value

Haccessories

HAZ HAZMAT HB HBW HCP HCU Hd HDPE HDS HE HFAU HGO HIC HID HJet

HHV

First Used in Eqn./Section Table/Figure 6.45 7.4 10.4 4.50 2.19.2 6.3.6 6.13 2.2 14.8 4.40 6.43 2.41.1 1.4 4.5 4.2 7.2 9.13

Also Used in Eqn./Section Table/Figure

6.30 2.31.20 6.28

6.30

6.3.2.h

4.4

8.2.1.a 1.7.4 5.18 8.2.1.a 3.2 2,31,7 4.11 2.30 2.31.4 5.18 2.31.14 2.17 5.18 2.31.4 8.18

1.2

3.18, 9.2.1.c 8.2.1.c

6.2.1, 8.2.1.c 5.18

Appendix I: Abbreviations

929

dContinued

Abbreviation

Description

HL HMCS HPIC HR MFL HRC HRBS

Liquid hold up Harmonized Mandatory Control System Hydrogen pressure induced cracking High resolution magnetic flux leakage Rockwell hardness Scale C Rockwell hardness Scale B using steel ball Rockwell hardness Scale B using tungsten carbide ball Hydrogen stress cracking Height of soil High temperature hydrogen induced cracking High temperature high-pressure jet impingement High temperature high-pressure rotating cage High temperature high-pressure rotating cylinder electrode High temperature high-pressure rotating disk electrode Upstream elevation Hydrotreating unit Vickers Hardness 10 or 10 kgf Vickers Hardness 5 or 5 kgf High vapor pressure Hertz (unit of frequency) Current Current density The current at redox potential of anode Current density at the redox potential of anode International Air Transport Association The current at redox potential of the cathode Current density at the redox potential of the cathode Critical current density (minimum current required before surface layers are formed)

HRBW HSC hsoil HTHIC HTHPJI HTHPRC HTHPRCE HTHPRDE Hu HTU HV HV 5 HVP Hz I i Ia ia IATA Ic ic Icc

First Used in Eqn./Section Table/Figure 4.6 7.4 5.9 8.4.7 6.2.1. 8.2.1.a

Also Used in Eqn./Section Table/Figure

8.2.1.a

8.2.1.a 5.18 10.1 2.31.25 8.8 8.8 8.8 8.8 4.11 2.17 8.2.1.a 8.2.1.a 2.37 5.23 5.2 5.2 9.5 9.6

9.23, 11.13

13.1 9.5 9.6 8.28

(Continued)

930

Appendix I: Abbreviations

dContinued

Abbreviation

Description

ICoat ICoatRCoat

Current flowing across the coating Commonly known as IRcoat drop across the coating Current density (at corrosion potential) Corrosion current DC current from a rectifier in the cathodic protection system. Inhibitor efficiency Current efficiency of an anode in the cathodic protection system Intergranular stress corrosion cracking Current density at the redox potential of hydrogen Inline inspection Inline Inspection e Ultrasonic The peak current density, (mA/cm2) in the hydrogen permeation measurement Absolute value of the mean coupling current (between the identical electrodes) Iron oxidizing bacteria Current output of an anode in the cathodic protection system Passive current (current of the electrode in the passive state). Institute of Petroleum (UK); now called as Energy Institute International Pipeline Conference Interest rate Iron reducing bacteria The amount of current to apply cathodic protection The amount of current density to apply cathodic protection Root mean square current noise Initial rate of return IR drop across the soil Individual inhibitor without cost Current flowing across soil (to calculate IR drop across soil)

icorr Icorr Idc I.E Ieff.a IGSCC IH+/H ILI ILI-UT Imax Imean

IOB Iout.A Ip IP IPC iR IRB Ireq ireq Irms IRR IRSoil IS IS

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

9.23 9.23 8.21 6.7 9.16

6.8, 8.17, 8.33

7.1 9.15 14.3.3.f 5.2 7.2 8.4.8 6.5

10.2.5, 11.5 8.1

8.34

4.9 9.9

5.14, 11.7.6 9.15

8.28 12.3.11 13.5.9 14.8 4.9 9.5 9.6 8.32 14.3.2.d 9.23 7.3 9.23

5.14, 11.7.6

Appendix I: Abbreviations

931

dContinued

Abbreviation

Description

ISC ISS

Individual inhibitor ranking with cost Individual inhibitor ranking without cost but with secondary inhibitor properties Individual inhibitor ranking with cost and with secondary inhibitor properties Theoretical current output of an anode in the cathodic protection system International Union of Pure and Applied Chemistry Current density at the redox potential of zinc Jet impingement Proportionality constant Stress intensity factor threshold intensity factor for SCC Pipeline resistance to flow in segments 1, 2, 3, and total respectively in a series pipeline with different diameters Pipeline resistance to flow in segments 1, 2, and total respectively in a parallel pipeline Mass transfer coefficient Proportionality constant to convert corrosion current to corrosion rate Deposition (of liquid from gas) mass transfer coefficient Effective roughness Knife-line attack (type of intergranular corrosion Kilometer Proportionality constant to convert mass loss to corrosion rate Material fracture toughness. Proportionality constant to convert corrosion current to mass loss rate Key performance indicator or key point indicator Susceptibility of the flaw to fracture Precipitation rate constant Kinetic parameter for trapping reaction

ISSC Ith.a IUPAC iZnn+/Zn JI K K1 K1SCC k1,S, k2,S, k3,S and kT,S k1,P, k2,P, and kT,P kcoeff Kcorr kd Ke KLA KM Kmass Kmat KMR KPI Kr Ksp ktrap

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

7.2 7.5 7.4 9.15 5.2 5.2 8.8 6.11 14.16 14.3.3.f 4.31, 4.32, 4.33, and 4.34

12.1

4.37 through 4.39

8.22 4.54 4.3 5.6 11.2 8.16 14.16 8.23 14.3.3.d. 14.12 6.25 6.4 (Continued)

932

Appendix I: Abbreviations

dContinued

Abbreviation

Description

First Used in Eqn./Section Table/Figure

L

Length

2.1

LA [Lab] LACT lb LC50

Length of anode Effect of laboratory methodology Lease automatic custody transfer Pound Concentration of chemical (e.g., corrosion inhibitor) required to kill 50% of a species Life cycle cost Limiting corrosion rate Local distribution center Low-density polyethylene Likelihood of a risk even happening Equivalent length of accessories to calculate pressure drop Location in which the failure occurs. Lifetime of the pipe Light gas oil Lower heating value Duration, in years, the coating is effective in protecting the structure based on laboratory performance liquid metal cracking Liquid metal embrittlement Maximum duration the coating is effective in protecting the infrastructure Liquid natural gas Logarithm of the octanol/water partition coefficient (measure of bioaccumulation) Layers of Protection Analysis Lock-out tag-out Liquid petroleum gas Linear polarization resistance Susceptibility of a flaw to plastic collapse Defined in Eqn. 14.14 Langemuir Saturation Index Metal

9.12 7.2 2.18 1.2 7.4

LCC LCR LDC LDPE LE Lequivalent LF LField LGO LHV LLab

LMC LME LMax LNG logPo/w

LOPA LOTO LPG LPR Lr Lr(max) LSI M

14.3.3.a 6.3.9 2.2.1.a 3.18 14.3 4.4

Also Used in Eqn./Section Table/Figure 3.3., 4.7, 6.1, 7.9, 11.8, 14.17

12.2.2.e

9.2.1.c

14.5 10.24 2.17 1.2 10.16

5.19 4.14 10.16 1.5 7.4

5.19

2.26

14.2.1.c 13.2.2.b 1.5 8.2.2.b. 14.12 14.14 6.7.6 5.1

6.8.1, 6.11

Appendix I: Abbreviations

933

dContinued

Abbreviation

Description

M M3 ma

Molarity Meter cube Anode mass in the cathodic protection system Maximum allowable operating pressure Rate of deposition of liquid phase from gas phase (mass per unit peripheral area per unit time) Methyldiethanolamine Monoehtanolamine Monoethylene glycol Magnetically Assisted Electrochemical Impedance Spectroscopy Methanol Material factor. Magnetic flux leakage Microbiologically influenced corrosion Microbiological factor Millions of cubic meter (mega meter cubed) Minerals Management Service (USA Department of Interior) Million standard cubic feet Maximum allowable operating pressure Management of change Maximum operating pressure Mass of particles Magnetic particle inspection Mass loss rate Manner in which the contents are released Thousand standard cubic feet (M here stands for roman numeral ‘M’ which stands for one thousand) Material safety data sheets Mass of soil Manufacturers Standardization Society Molecular weight Materials-water factor

MAOP mD

MDEA MEA MEG MEIS MeOH MF MFL MIC MiF Mm3 MMS MMSCF MOAP MOC MOP mp MPI MR MR MSCF

MSDS msoil MSS MW MWF

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

8.4 6.3.2.h 9.15 2.21 4.54

2.14.2 2.14.2 6.3.1.f 11.3.9 7.8 6.44 8.3.10 5.14 6.44 6.3.2.h

3.3.1.c

7.8

8.4.7, 11.5 6.5.1.r , 7.5

1.6 2.14.3 8.4.8 13.3 14.2.2.b 6.40 8.4.5 8.23 14.5

4.2.3. 7.4

6.3.2.h

7.12 10.1 2.24 7.4 6.42 (Continued)

934

Appendix I: Abbreviations

dContinued First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

5.5, 6.54, 8.24

Abbreviation

Description

MWFe MWscale N n

Molecular weight of iron Molecular weight of scale Number of measurements number of electrons required to oxidize an atom of the element in the corrosion process, i.e., the valence of the element Number of anodes in the cathodic protection system Non-classical localized pitting corrosion Non-destructive evaluation Non-destructive technique No Effect Concentration Natural gas liquid Number of samples used in an experiment Number of major properties Number of minor properties Normally occurring radioactive materials Flow exponent in pipeline in series Net present value NPV corrected for probability of failure Numerical risk assessment Nitrate-reducing bacteria Concentration of traps in steel Oil Country Tubular Goods Operation factor Operation and maintenance Operating expenditure Office of Underground Storage Tanks Oil in water Pressure

6.56 6.54 11.3 5.1

Pressure drops in parallel pipeline segments 1 and 2 respectively Pressure drops at segment 1, 2, 3, and 4 of pipeline in series Pressure drop of laminar flow in the annular space

4.37 through 4.39 4.31 through 4.35 4.42

NA NCLPC NDE NDT NEC NGL NM NMaj NMin NORM nPD NPV NPVc NRA NRB Ntrap OCTG OF O&M OPEX OUST O/W P P1,P and P2,P P1,S, P2,S, P3,S and P4,S PAnn.Lam

9.13 6.5 14.3.3.f 7.4 1.5 12.2

2.14

10.8 10.8 1.4 4.35 14.3.2.a 14.11 14.2.2.b 7.5.1. 6.4 2.10 6.42 1.7.2 13.2.2.a 1.7.4 6.5.1.b. 2.3

14.3.2.a

4.3, 6.12, 6.8 10.41

Appendix I: Abbreviations

935

dContinued

Abbreviation

Description

PAnn.Tur

Pressure drop of turbulent flow in the annular space Effect of partitioning Average pressure Pressure at base condition Pilling and Bedworth Ratio Potential corrosivity in Crolet model Critical pressures of the corresponding gases in a gas mixture Partial pressure of CO2 Effective partial pressure of CO2 Pressure drop at pipeline contraction Polymerase chain reaction Effect of additional parameters Average localized pitting corrosion rate Effect of bicarbonate on Pitting corrosion rate Effect of chloride on Pitting corrosion rate Effect of CO2 on Pitting corrosion rate Final localized pitting corrosion rate based on the combined effect of MIC and non-MIC activities Effect of gas on Pitting corrosion rate Effect of H2S oil on Pitting corrosion rate Mean localized pitting corrosion rate Localized pitting corrosion rate based on all effects of non-microbes Effect of oil on Pitting corrosion rate Effect of pressure on Pitting corrosion rate Effect of solid on Pitting corrosion rate Effect of sulfate on Pitting corrosion rate Effect of temperature on Pitting corrosion rate Effect of water on Pitting corrosion rate Critical pressure Pressure downstream Population density

[Part] Pave Pb PBR PC Pca , Pcb, etc pCO2 pCO2(eff) Pcon PCR PCRadditional PCRAverage PCRbicarbonate PCRchloride PCRCO2 PCRfinal

PCRgas PCRH2S PCRmean PCRnon-MIC PCRoil PCRpressure PCRsolid PCRSulphate PCRtemperature PCRwater Pcrit Pd PD

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

4.43 7.4 4.17 4.14 6.54 6.3.3 4.18 4.87 6.18 4.41 8.2.4 6.8 6.36 6.8

6.6; 6.8 6.11

6.8 6.8 6.37

6.8 6.8 6.35 6.5.1.r 6.8 6.8 6.8 6.8 6.8 6.8 4.2.1.b 4.7 14.7 (Continued)

936

Appendix I: Abbreviations

dContinued

Abbreviation

Description

Pdesign PDiff

Design pressure (of pipeline) Percentage difference between the maximum operating pressure and hydrostatic test pressure Point defect model Polyethylene Probability of an event Predicted Environmental Concentration Polyetheretherketone Pressure drop at expansion of pipeline Calculated failure pressure Probability of failure (0 to 100), and Pitting factor Percentage fluctuation of operating pressure Partial pressure of H2S pH at saturation in calcite or calcium carbonate Hydrostatic test pressure Pitting index Piping and Instrumentation Diagram Pipeline Integrity Gauge Pipe-in-pipe Maximum operating pressure. Minimum operating pressure Percentage duration when no CP was applied Profit of the oil and gas industry Payback period Pre-project planning Reduced pressure Precipitation rate Probabilistic risk assessment Pitting Resistance Equivalent Number Effect of total pressure Load (to apply stress) on the specimen Pressure at standard temperature and pressure

PDM PE PE PEC PEEK PEx Pf PF PF PFluc pH2S pHs PH.Test PI P&ID PIG PIP PMax PMin Pno.CP POGI PP PPP Pr PR PRA PREN [Pressure] Ps PSTP

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

2.2 10.29

6.4.3.a 2.11 14.2 7.4 3.18 4.40 10.24 14.9 6.31 10.29 4.87 6.47 10.29 8.32 2.31 11.5 9.2.4 10.29 10.29 10.30 14.1 14.3.2.b 14.3.3.b 4.2.1.b 6.57 14.2.2.b 6.4.1 7.2 3.2 4.52

9.2.1, 9.2.1.c

8.33

6.6; 6.8

10.24

8.4

Appendix I: Abbreviations

937

dContinued

Abbreviation

Description

PTFE Pu puntrap

Polytetrafluoroethylene Pressure upstream Kinetic parameter for untrapping reaction Present value Polyvinyl chlorides Post-weld heat-treated Probability of corrosion rate reaching a particular value Yield Pressure Heat transfer rate Quality control Quartz crystal microbalance Metal loss rate Quantitative risk assessment quarternary ammonium compounds Radius Resistance Organic group; aliphatic, aromatic, or naphthenic Gas constant Resistance of the cable connecting to the negative terminal in the cathodic protection system Resistance of cable connecting to the positive terminal in the cathodic protection system Resistance between the anode and environment (ground or seawater or electrolyte) in the cathodic protection system Percent reduction in area Risk based inspection Resistance between the cathode and the environment in the cathodic protection system Reactivity of the content Rotating cage Rotating cylinder electrode

PV PVC PWHT P(X) PY Q QC QCM Qerosion QRA Quats r R R’ R R(-)

R(+)

Ra

RA% RBI Rc

Rc RC RCE

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

3.18 4.7 6.4

8.2.2

14.8 2.11 2.41.1 14.4

9.2 13.2.2.d 10.2.2.b 6.40 14.2.2.b 7.5.1. 2.3 8.2.2.b 4.88 5.7 9.21

3.18, 7.9.1

3.3.1.c , 14.17

5.15, 6.25

9.21

9.10

3.6 14.3.3.e 9.10

14.6 8.8 8.8

8.9 (Continued)

938

Appendix I: Abbreviations

dContinued

Abbreviation

Description

Rcoat Rcorr

Resistance of coating Polarization resistance (inversely proportional to corrosion rate). Also designated as Rp Rotating disk electrode Reference electrode Reynolds number Reynolds number of rotating cylinder electrode Efficiency of the rectifier in the cathodic protection system Reynolds number of rotating disk electrode Oxidation-Reduction Reynold’s number of jet Reynolds number of pipe Reynolds number of rotating cage Rate of growth of iron carbonate surface layer Electromagnetic e Remote Field Technique Resistance of half the length of the anode portion of the groundbed in the cathodic protection system Resistance between horizontal anode and ground in the cathodic protection system Risk Radius of jet, m Risk factor due to microbiologically influenced corrosion Resistance from electrochemical noise measurement and is equivalent to RP (as determined by polarization resistance method). Resistance between group anodes and ground in the cathodic protection system Ribonucleic acid Rate of return on investment Remotely operated vehicle Polarization resistance (inversely proportional to corrosion rate)

RDE RE Re Rec Receff ReD Redox Rejet Rep ReRC RFeCO3 RFT Rgb

Rh

Ri rjet RMIC Rn

RN

RNA ROI ROV Rp

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

9.23 10.2.2.b

10.2.2.b

8.8 8.1 4.5 8.9

8.5

9.16 8.5 5.2 8.14 8.5 8.11 6.25 8.2 9.21

9.11

14.2 8.14 6.37

6.44

8.31

9.11

8.2.4 14.3.2.d 11.4 8.17

9.14

Appendix I: Abbreviations

939

dContinued

Abbreviation

Description

rp RPD Rpipe ‘R ratio’

Radius of piston Resistance to flow of pipelines in series Resistance of pipe length Ratio of the minimum to the maximum pressure Radius of the rotating cage Radius of the rotating cylinder electrode Radius of rotating disk electrode Radial distance in the jet impingement apparatus (ratio of radius of spcimen to radius of jet) Production rate of gas Production rate of oil Production rate of water Production rate of sand Solution resistance Ryznar stability index Effect of solid; equal to 1 if the solid is present or 0 if no solid is present Resistance of the span, i.e., a known length between two measuring pins or probes Resistance between anode and cathode or cathodic protection circuit resistance (typically in a cathodic protection system) Resistance between vertical anode and ground in the cathodic protection system Resistance of metallic wire connecting the cathode and anode in the cathodic protection system Adhesion score Sulfuric acid alkylation unit Accessories scores Center to center spacing between anodes in the cathodic protection system Additional survey score Above-ground survey score Steam assisted gravity drainage

rRC rRCE rRDE r/rjet

P.R.gas P.R.oil P.R.water P.R.Sand Rs RSI Rsolid Rspan

RT

Rv

Rw

SA SAAU SACC SAC.CP

SADD SAG SAGD

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

10.1 4.35 11.9 10.3.2 8.11 8.9 8.2.2.b 8.18

4.48 4.48 4.48 6.12 8.2.2.b 6.53 6.8

8.5

6.33 6.33 6.33 9.23, 10.2.2.b

11.3

9.9

9.11

9.10

10.9 2.31.14 10.19 9.14

10.29 10.25 1.4.2.a

10.34

10.28 2.9 (Continued)

940

Appendix I: Abbreviations

dContinued

Abbreviation

Description

SAR SAW SB SBC SBCBC SBCCa SBCCi SBCMA

Abrasion resistance score Submerged arc welding Bend score Blast cleaning score Beneath coating bicarbonate score Beneath coating carbonate score Beneath coating chloride score Beneath coating microbial anaerobic score Beneath coating microbial acid producing score Beneath coating microbial heterotrophic aerobic score Beneath coating microbial sulfate reducing score Beneath coating sulfate score Beneath coating sulfide score Coated or bare pipe score Backfill type score Schmidt number Supervisory Control and Data Acquisition Casings score Stress corrosion cracking

SBCMAP SBCMHA SBCMSR SBCSa SBCSi SBP SBT Sc SCADA SCasing SCC SCD SCE SCEM Scf SChem/Micro SCO SCoating SCoatingSoil SComptibility SConsequence SConstruction SContent SCorrosion SCorrosion.C

Cathodic disbondment score Saturated calomel electrode Synergism due to corrosion enhanced mechanical forces Standard cubic feet Chemical/microbial category score Synthetic crude oil Coating category score Coating-soil category score Compatibility score Consequence survey score Construction category score Contents score Corrosion category score Corrosion feature cluster score

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

10.10 3.3.1.c 10.19 10.7 10.35 10.35 10.35 10.35 10.35 10.35 10.35 10.35 10.35 10.18 10.19 8.5 12.2.2. 10.19 2.2 10.9 5.2 8.36 6.3.2.h 10.32 2.17 10.6 10.6 10.10 10.25 10.17 10.26 10.32 10.36

13.3.6

5.17, 10.2.4.a , 11.2.2.b 8.4

10.8, 10.32

10.26 10.19

Appendix I: Abbreviations

941

dContinued

Abbreviation

Description

SCoupon SCP SCPDemand SCPDemand.S SCPEC SCPS SCPT SCR SCU SDepth SDia SDrain SDWCP SE SEM SET

Coupon survey score CP category score. CP current demand score CP current demand survey score CP evaluation criteria score CP standard score CP type score Coating removal score. Steam cracking unit Corrosion feature depth score Diameter score Drainage score Duration without CP score Elevation profile score Scanning electron microscope Resistance to elevated temperatures score Silt factor representing the amount of sludge and silt present at the sampling site Overall score for the FBGM Proximity to other features score. Supersaturation rate of iron carbonate Flexibility score Overall score for the field parameters Freeze thaw stability score Specific gravity Gas gravity (dimensionless) Specific gravity of liquid Sherwood number, a dimensionless mass transfer rate defined for each geometry System Head Curve Holiday Detection score Standard hydrogen electrode Hydrotesting score. Saturation index Saturation index for calcium carbonate deposition

SF

SFBGM SFeature SFeCO3 SFl SField SFT SG SGgas SGl Sh

SHC SHD SHE SHT SI SIc

First Used in Eqn./Section Table/Figure 10.29 10.17 10.27 10.25 10.22 10.22 10.22 10.34 2.31.8 10.36 10.18 10.20 10.22 10.19 3.2.3 10.12

Also Used in Eqn./Section Table/Figure 10.22

6.43

10.32 10.19 6.25 10.9 10.17 10.11 4.3 4.14 4.43 4.59

4.2.1 10.14 8.4 10.21 4.76 6.29

4.7

10.19

(Continued)

942

Appendix I: Abbreviations

dContinued

Abbreviation

Description

SILI SIR SLab SLeak SLength SLocation SLR SMaj SMC SME SMEC

Inline inspections score Impact resistance score Total laboratory performance score Leak survey score Corrosion feature length score Location score Leak/rupture score Sum of the major properties scores Moisture content score Subject matter expert Synergism due to mechanical forces enhanced corrosion Synergistic interaction between corrosion and mechanical forces Sum of the minor properties scores Mainline-repair coating compatibility score Microbial resistance score Steam methane reforming Specified minimum yield strength Number of surveys score Non-visual contamination score. Sulfide oxidase Stress-oriented hydrogen induced cracking Effect of solubility Standard operating procedure Operational category score Other surveys score. Score for the entire category Patrol survey score Pattern of defect score pH score. pH below coating score Pipe category score Pipe-soil category score. Simple payback period Pressure score Corrosion products score Pipe to soil potential score

SMech.Corr SMin SMLR SMR SMR SMYS SNS SNVC SO SOHIC [Solu.] SOP SOperational SOther.S SOthers SPatrol SPD SpH SpHBC SPipe SPipe-Soil SPP SPressure SProduct SPSP

First Used in Eqn./Section Table/Figure 10.25 10.10 10.6 10.29 10.36 10.26 10.21 10.8 10.33 13.2.3.d 8.36

Also Used in Eqn./Section Table/Figure

14.2.2.a

8.35 10.8 10.37 10.10 2.33.22 2.2 10.27 10.7 8.2.4 5.9 7.4 13.2.2.b 10.17 10.25 10.29 10.29 10.34 10.33 10.34 10.17 10.6 14.3.2.b 10.21 10.36 10.33

10.3.2 10.28 8.39 6.1

10.21

10.18

Appendix I: Abbreviations

943

dContinued

Abbreviation

Description

First Used in Eqn./Section Table/Figure

SR SRB

Saturation ratio Sulfate reducing bacteria

4.76 2.6

SRC SRci SRET

Repair coating score Initial repair coating score Scanning reference electrode technique Repair score Repair category score Soil resistivity score Survey result score Standard resolution magnetic flux leakage Route change score Steam reforming unit River or road crossing score Soil bicarbonate score Sulfide stress cracking Soil classification score Soil carbonate score SCC susceptibility score. Soil chloride score Stray current source score Solids below coating score Steel grade score Solution below coating score Soil microbial anaerobic score Soil microbial acid producing score Soil microbial heterotrophic aerobic score Soil microbial sulfate reducing score Soil category score Soil category score (Below-ground measurement) Surface profile score Average of the two most recent survey results Slow strain rate test Soil sulfate score

10.37 10.38 8.2.2.b

SRepair SRepair.C SResis SResult.S SR MFL SRTC SRU SRVC SSBC SSC SSC SSCa SSCC SSCi SSCS SSdBC SSG SSlBC SSMA SSMAP SSMHA SSMSR SSoil SSoil.B SSP SSR SSRT SSSa

Also Used in Eqn./Section Table/Figure 4.6, 5.14, 6.43. 7.5.1., 8.2.4, 10.2.2.a, 11.7.6

10.21 10.32 10.33 10.27 8.4.7 10.19 2.31.22 10.19 10.35 2.2 10.33 10.35 10.20 10.35 10.22 10.34 10.18 10.34 10.35 10.35 10.35 10.35 10.17 10.32

4.6, 5.18, 6.2.1

10.20

10.7 10.28 8.2.1.c 10.35 (Continued)

944

Appendix I: Abbreviations

dContinued

Abbreviation

Description

First Used in Eqn./Section Table/Figure

SSSi SST SST.seam SSteel SSteelCoating SSurveys STCD STP SV SVC SWC SWF SYI Synbit SYM SZC t

Soil sulfide score Soil type score Seam type score Steel category score Steel-coating category score Overall score for the surveys Type of coating defect score Standard Temperature and Pressure Visual score Visual contamination score Step-wise cracking Water-filled coating score Year installed score Synthetic bitumen Year manufacture score Soft-zone cracking Time period or duration

10.35 10.20 10.18 10.6 10.6 10.25 10.34 4.51 10.34 10.7 5.9 10.33 10.19 2.17 10.18 5.9 8.16

T tl

Temperature Time at which the permeation rate reaches 63% of the steady state rate Half-life time for hydrogen diffusion to reach steady state Total acid number (measure of naphthenic acid) Anode life in the cathodic protection system Age of the pipe Average temperature Temperature at base condition Coating thickness Toxicity of the content. Critical temperatures of the different gases in a gas mixture Trillion cubic feet trillion cubic meters Duration with CP Thermal cracking unit Critical temperature, Total dissolved solids

4.87 6.1

t1/2 TAN tanode TAge Tave Tb tc Tc Tca, Tcb, etc TCF TCM TCP TCU Tcrit TDS

Also Used in Eqn./Section Table/Figure

10.9

6.1

6.1 8.2.2.b., 10.2, 10.3, 10.41, 14.4, 14.8, 14.9, 14.10 5.7 , 6.6, 6.25, 9.2

6.2

8.2

2.32.2

4.13.2

9.15 10.30 4.14 4.14 11.1 14.6 4.19 1.2 1.2 10.30 2.17 4.2.1.b 6.7.6

4.17

2.31.6 6.11

Appendix I: Abbreviations

945

dContinued

Abbreviation

Description

TE TEG TEM [Temp] Tf

Thermal efficiency Triethylene glycol Transmission electron microscope Effect of temperature Temperature at base and is equal to 520oR Temperature factor Total hours in a year Transgranular stress corrosion cracking Toe to head air injection Hydrogen measurement break-through time Effect of thermal stability Total initial investment Anticipated life of the infrastructure to be protected by cathodic protection system Top-of-the-line corrosion Effect of toxicity Thickness of the quartz crystal Reduced temperature Remaining wall thickness Transwave system Thermal sprayed aluminum Transportation Safety Board (Canada) Scaling temperature Total suspended solids Temperature at standard temperature and pressure Wall thickness or thickness of material Initial pipe wall thickness Flow rate Percentage area of structure uncoated Gas flow rate at base conditions Critical velocity constant for erosion to occur Critical velocity for flow to change between scouring and moving dunes Flow rate in the smaller (downstream) pipeline segment after contraction Erosion velocity

TF tfunc TGSCC THAI tH,b [Ther.] TII tlife

TLC [Toxi.] tq Tr tR TS TSA TSB Tscale TSS TSTP tw twi U UA Ub Ucrit,E Ucrit,SM Udown, Ue

Con

First Used in Eqn./Section Table/Figure 1.2 2.14.3 3.2.3 7.2 4.36 6.42 9.15 14.3.3.f 1.4.2.a 6.3

Also Used in Eqn./Section Table/Figure 6.3.1.f , 7.8

2.9 8.3

7.4 14.10 9.19

2.21.a 7.4 10.4 4.2.1.b 10.37 11.3 9.2.5 1.6 6.14 6.7.6 4.52

5.24, 6.1, 6.10

2.2 10.24 4.5 9.7 4.14 6.40

8.1, 10.41

6.11

4.7, 6.39, 8.6

4.41 6.38 (Continued)

946

Appendix I: Abbreviations

dContinued

Abbreviation

Description

UFa Ug Ul UNS Uo Uo,jet UP USA UST UT Uup,Ex

Utilization factor Gas flow rate Liquid flow rate Unified Numbering System Overall heat transfer coefficient Mean fluid velocity in the jet Velocity of particles United States of America Underground storage tanks Ultrasonic technique Flow rate in the smaller (upstream) pipeline segment before expansion Ultraviolet Volume Potential of anode in the cathoic protection system Vapor extraction process Core friction velocity Potential to which the cathodically protected metal is shifted DC potential from a rectifier in the cathodic protection system Vacuum distillation unit Visual factor representing a visual estimate of the amount of deposit or tubercle formation at the sampling site Voltage required for detecting the holiday in polymeric coating Volume of inhibitor required in gallons Velocity of flow in the jet impingement apparatus Velocity of liquid Measured potential between the structure and reference electrode Volume of oil Rectifier voltage in the cathodic protection system Volume of sand Potential between the structure and the environment (this potential should be -850 mV Vs. CCS)

UV V VA VAPEX V) C VCPS Vdc VDU VF

Vholiday Vinh VJet VL Vmeasured Vo Vrectifier Vsand VSE

First Used in Eqn./Section Table/Figure 9.15 4.3 4.22 3.4 9.2 8.14 6.40 10.3.1 1.7.4 8.3 4.40

Also Used in Eqn./Section Table/Figure 4.22 4.42

11.5.1

9.2.1.c 4.15 9.8 1.4.2.a 4.55 9.8

2.9

9.16 2.17 6.43

2.13.3

11.1 7.6 8.18 2.1 9.23 4.29 9.20 4.47 9.23

6.30

Appendix I: Abbreviations

947

dContinued

Abbreviation

Description

VSR

Potential between soil and reference electrode Volume at standard temperature and pressure Volume of water Mass lost AC power from a rectifier in the cathodic protection system Water and gas process Water condensation rate Working electrode Occurrence of a risk event, e.g., corrosion, cracking, material degradation, improper operation, improper material selection, material damage, third party damage, and earth movement Woven polyolefin geotextile fabric Amount of glycol Whole life cost Wear or erosion or abrasion rate in the absence of corrosion Weightage for major category Percentage of water Water-in-oil emulsion Load in the slippage test Effect of wall shear stress Wall shear stress Constant Indication of strength of steel Value of a property obtained during a measurement Individual value measured on each sample in an test that used several identical samples Lockhart-Martinelli two phase modulus Mean value of the data X-ray diffraction True or accepted value Relative frequency of occurrence

VSTP Vw W Wac WAG WCR WE WE

WGF Wglyc WLC Wmech wmaj W% W/O wslip [WSS] Wss x X Xa xi

XLM XM XRD xt y

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

9.23 4.52 4.29 8.16 9.16

8.35

2.7 6.56 8.1 14.3

9.2.1.c 6.15 14.3.3.a 8.35 10.8 6.8 6.5.1.b. 10.2 7.2 2.1 11.1 3.3.1.b 12.1 12.2

6.12

4.62, 6.5.1.f , 6.8

12.5

4.22 12.2 3.2.3 12.5 12.8 (Continued)

948

Appendix I: Abbreviations

dContinued

Abbreviation

Description

YI Ya,Yb, etc

Year (and month) the pipe was installed Percentages of various gases in a gas mixture Young Modulus Year (and month) in which the survey is conducted Impedance average compressibility factor (dimensionless) Gas compressibility factor Zero-resistance ammeter

YM YS Z Zave Zgas ZRA

First Used in Eqn./Section Table/Figure

Also Used in Eqn./Section Table/Figure

14.30 4.18 3.1 14.30 10.2.2.b. 4.14 4.16 8.3.7

Greek Symbols Abbreviation

Description

a aA ba bc gso gsw gwo ) DDo-s

Impact angle Attenuation constant Anodic Tafel constants Cathodic Tafel constants Interfacial tension between surface and oil Interfacial tension between surface and water Interfacial tension between oil and water Liquid film thickness Density difference between oil and sand or solid particles Density difference between oil and water Driving potential (the difference between OFF and ON potential) Change in the resonance frequency of the quartz crystal Gibb’s free energy change Line current (the difference between ON and OFF current) Length of the segment Mass change on a quartz crystal Pressure drop

DDo-w DE DF DG DI DLpipe Dm DP

First Used in Eqn./Section

Also Used in Eqn./Section

6.40 11.8 8.18 8.18 4.70 4.70 4.70 6.57 4.47 6.30 8.2.2.b

11.3.3

10.4 5.2 8.2.2.b 4.12 10.4 4.63

11.3.3 4.63

Appendix I: Abbreviations

949

Greek SymbolsdContinued Abbreviation

Description

DPE,G

Difference in pressure due to elevation change in single phase gas flow Difference in pressure due to elevation change in single phase liquid flow Pressure drop in single phase gas flow Pressure drop in liquid flow Pressure drop in liquid-gas flow Pressure drop in liquid containing solids (e.g., hydrotransportation pipeline) Difference in temperature Driving potential of anode in the cathodic protection system Polarization potential (the difference between OFF potential and corrosion potential) Strain in material Initial dielectric constant Roughness of pipe wall Dielectric constant at time t Overpotential Anodic overpotential Cathodic overpotential Viscosity of gas Viscosity of liquid‘ Viscosity of oil Viscosity of water Contact angle (wettability) Critical angle (water accumultation) Liquid fraction Empirical parameter used in Baker flow regime map

DPE,L DPG DPL DPL-G DPSolid DT DVDP DVp ε εo εpipe εt h ha hb hg hl ho hw qCaw qCA l lGLflow m mpopulation mq n vtr nwater P

Population mean Shear modules of quartz (2.947 x 1011 dyne/cm2) Kinematic viscosity Transverse velocity of sound in quartz, 3.34 x 104 m/s (1.1 x 105 ft/s). Volume of water in coating or volume water fraction Density

First Used in Eqn./Section

Also Used in Eqn./Section

4.20 4.11 4.21 4.30 4.21 4.30 9.2 9.8 11.3.3 3.1 10.3

3.2 8.5

10.3 8.26 8.27 8.28 4.22 2.1 4.29 4.29 4.70 4.51 4.57 4.45

4.6, 4.29, 4.42

6.8

12.7 10.4 4.5 10.5

8.6

10.3 4.62 (Continued)

950

Appendix I: Abbreviations

Greek SymbolsdContinued Abbreviation

Description

rCarbonsteel rg rl rmetal rnormalized

Density of carbon steel Density of gas Density of liquid Density of metals or alloys Constant to represent the normalized resistivity and is typically 1,000 U-cm Density of particles Density of quartz (2.648 g/cm3 or 0.957 lb/in.) Density of solids Density of scale Resistivity of soil Solution density Density of water Stress Standard deviation of potential noise Material flaw stress, i.e., the average of the ultimate tensile stress and yield stress) Standard deviation of current noise Resistivity of metal Reference stress Standard deviation Material yield stress Surface tension Interfacial shear stress in absence of interface mass transfer Wall shear stress of rotating cage Wall shear stress of RCE Wall shear stress of jet impingement stagnant region Wall shear stress due to vortex formation in the rotating cage Wall shear stress of jet impingement in the jet region Two phase flow modulus and is calculated based on flow regime of the pipe phase angle (EIS) Inclination angle Empirical parameter used in Baker flow regime map Angular velocity

rparticle rq rs rscale rsoil rsolution rw s sE sf sI smetal sref sstd sy T si sRC sRCE sstag svortex sw 4 F Q jGLflow U

First Used in Eqn./Section 6.56 4.22 4.6 6.54 11.12 6.40 10.4 4.30 6.54 9.12 8.9 6.56 2.3 8.31 14.14

Also Used in Eqn./Section

4.30 8.22

10.42, 11.12

3.1, 8.4, 10.41

8.31 8.40 14.15 12.7 14.14 4.46 4.56 8.11 8.9 8.13 8.11 8.14 4.21 8.2.2.b 4.58 4.46 8.8

4.66

Appendix I: Abbreviations

951

Chemical Symbol First Used in Eqn./Section

Formula

Substance

Ag/AgCl Ali.COOH) Ar.COOH) As Ba2+ BaSO4 C C2H5COOH C2H5SH or CH3CH2SH Ca2+ [Ca2+] [Ca2+]satn.

Silver-silver chloride (reference electrode) Aliphatic acid Aromatic acid Arsenic Barium Barium sulfate Carbon Propionic acid Ethanethiol or ethyl mercaptans Calcium ion Concentration of calcium ion Concentration of calcium ion at the saturation point Calcium bromide Calcium chloride Calcium carbonate (commonly known as calcite scale) Calcium sulfate Hydrated calcium sulfate Cencentration of chloride Carbon monoxide Carbon dioxide Concentration of carbonate in solution Concentration of carbonate ion at the saturation point Carboxylic group Propyl mercaptan or propanethiol Acetic acid Methyl mercaptan or methanethiol Chromium Copper Iron Pyrrhotite Mackinawite

4.13 2.31.9 2.5 2.31.9 4.10 4.10 5.8 4.8 4.8

Concentration of iron Cementite Greigite Trolite

5.8 6.3.1.h 4.8 4.8

CaBr2 CaCl2 CaCO3 CaSO4 CaSO4.2H2O [Cl ] CO CO2 [CO23 ] [CO23 ]satn.. -COOH CH3CH2CH2SH CH3COOH CH3SH Cr Cu Fe Fe1 xS Fe1+xS (x ¼ 0 to 0.1, e.g., Fe9S8) [Fe2+] Fe3C Fe3S4 FeS

8.4 4.13 4.13 4.10 4.4.2 4.4.3 4.10 4.13 2.4 4.4.2 4.77 4.77 7.4 7.4 4.4.3

Also Used in Eqn./Section

2.5 6.51

6.8.1

4.4.3 4.73 6.8 2.31.12 6.3 4.77 4.77

4.13 6.4.1

6.56

(Continued)

952

Appendix I: Abbreviations

Chemical SymboldContinued Formula

Substance

FeS2 H+ [H+] H2O HCl [HCO3 ] HCOOH HF Hg H2PO4 HPO24 H2S H2SO4 H2SxO6 K+ KCl KOH Li+ Mg2+ Mn Mn+ Mo N or N2 Na+ NaCl Nap.COOH) Na2SO3 NH4HSO3 Ni Nig Nih Nig’

Marcasite or pyrite Hydrogen ion Concentration of hydrogen ion Water Hydrochloric acid Concentration of bicarbonate ion Formic acid Hydrofluoric acid Mercury Dihydrogen phosphate ion Hydrogen phosphate ion Hydrogen sulfide Sulphuric acid Polythionic acid Potassium Potassium chloride Potassium hydroxide Lithium Magnesium ion Manganese Metallic ion Molybdenum Nitrogen Sodium Sodium chloride Naphthenic acid Sodium sulphite Ammonium bisulphite Nickel Nickel secondary phase e gamma prime Nickel secondary phase e eta Nickel secondary phase e gamma double prime Nickel secondary phase e mu Nickel secondary phase esigma Nitrous oxide Oxygen Hydroxyl ion Activity (concentration) of oxidized species

Nim Nis NOx O or O2 OH [OX])

First Used in Eqn./Section 4.8 5.3 6.27 5.3 2.5 4.87 2.5 2.5 4.14 4.4.1 4.4.1 1.4 2.31.14 2.31.4 4.4.2 8.4 4.13.2 4.4.2 4.4.2 4.10 5.1 4.4.2 2.7 4.4.2 10.2.2.b 4.13 2.6 2.6 4.10 3.3.6 3.3.6 3.3.6 3.3.6 3.3.6 1.12 5.3 5.3 5.7

Also Used in Eqn./Section 5.8, 6.27

6.6; 6.17; 6.8 2.31.14

2.2, 6.3

6.4.1 6.4.1, 7.4

7.4

Appendix I: Abbreviations

953

Chemical SymboldContinued Formula

Substance

First Used in Eqn./Section

Also Used in Eqn./Section

P PO34 Pt Rb+ [RED]) S Se SO2

Phosphorous Phosphate ion Platinum Rubidium ion Activity of reduced species Sulfur Selenium Sulfur dioxide Concentration of sulfate

4.10 4.4.1 11.7.6 4.4.2 5.7 4.10 7.4 2.6 6.8

7.4

Concentration of solid Strontium Strontium sulfate Titanium oxide Tungsten Zinc

4.30 4.4.2 4.4.3 3.3.7 6.4.1 9.2.5

½SO42 Š [Solid]) Sr2+ SrSO4 TiO, TiO2, Ti2O3 W Zn )

7.4

Not chemical formula

Trade Name Trade Name)

Section First Used

Nitrile Viton Teflon Monel Inconel Hastelloy Tygon Ni-Resist Nitralloy

2.4 2.4 2.4 2.1 2.7 2.7 2.41.2 2.7 2.7

)

Indicated by:

TM

2.31.23 2.31.23

2.11

954

Appendix I: Abbreviations

Industry and Professional Associations American Bureau of Shipping American Gas Association American Institute of Mining Engineers American Iron and Steel Institute American National Standards Institute American Petroleum Industry American Public Works Association American Society of Mechanical Engineers American Society of Petroleum Engineers American Water Works Association American Welding Society Association Francaise de Normalisation Association of Oil Pipelines Association Suisse de Normalisation ASTM International (formerly American Society of Testing and Materials) Badan Kerjasama Standardisasi Lipi-Ydni (Indonesia standard organization) British Standards Institute Canadian Association of Petroleum Producers Canadian Energy Pipelines Associations Canadian Gas Association Canadian Standards Association China Association for Standardization Chinese National Standards Commission Venezolana de Normas Industriales (Venezuela) Composites Engineering and Applications Center Deutsches Normenausschub (Germany) Deutsche Institut Fur Normung (Germany) Direccion General de Normas (Maxico) Energy Institute (See Institute of Petroleum) Ente Nazionale Italiano de Unificazione (Itali) Gas Research Institute Gas Technology Institute (formerly Gas Research Institute) Interstate Natural Gas Association of America Indian Standards Institute Institute of Petroleum (UK) (now called as Energy Institute) International Organization for Standards

ABS AGA AIME AISI ANSI API APWA ASME ASPE AWWA AWS AFNOR AOP SNV ASTM

1.18 1.18 2.15 3.4 1.18 1.18, 3.4 1.6 1.18, 3.4 1.18 1.18, 10.2.2 1.18, 9.2.5 1.18, 12.3.11 1.18 1.18 1.18, 3.4, 12.2.1.f , 13.5.9 1.18

GB COVENIN

1.18 1.18 1.18 1.18 1.18, 3.4, 9.2.1.d 1.18 3.4 1.18

CEAC DIN DIN DGN IP UNI GRI GTI

1.18 3.4, 1.18, 12.3.11 12.3.11 1.18 12.3.11 1.18 1.18 1.18

INGAA ISI IP

1.18, 13.5.9 1.18 12.3.11

ISO

1.18, 3.4, 10.2.2.

BSI CAPP CEPA CGA CSA

Appendix I: Abbreviations

955

Industry and Professional AssociationsdContinued Japan Industrial Standards (Tokyo) Japanese Industrial Standards Committee National Bureau of Standards (USA) National Fire Protection Association National Institute of Standards and Technology (USA) Nederlands Normalisatie Instituut Norges Standardiseringsforbund NACE International (Formerly National Association of Corrosion Engineers) NORSOK/Standard Norge Oesterreichisches Normungsinstitut (Austria) Organization of the Petroleum Exporting Countries Oslo Paris Commission Paris Commission (on environmental evaluation of corrosion inhibitors) Pipeline Research Council International Small Explorers and Producers Association of Canada Standards association of Australia Saudi Arabian Standards Organization Singapore Institute of Standards and Industrial Research Spill Prevention Countermeasure and Control Standardisering Kommissionen (Sweden) Society of Protective Coating United Kingdom Offshore Operators Association

JIS JISC NBS NFPA NIST

3.4, 12.3.11 1.18 10.3.1 1.18 12.2.1.f

NNT SSF NACE

1.18 1.18 1.18, 10.2.2, 13.5.9

NORSOK ONORM OPEC OSPARCOM PARCOM

1.18 1.18 1.6 7.4 7.4

PRCI SEPAC

1.18, 13.5.9 13.5.9

SAA SASO SIRU

1.18 1.18 1.18

SPCC SIS SSPC UKOOA

1.7.4 1.18 1.18, 9.2.5, 13.5.9 1.18

Some Regulators in Canada and USA Alberta Energy Regulator (Formerly Energy Resources Conservation Board (ERCB) or Alberta Energy Utility Board (AEUB)) Federal Energy Regulatory Commission National Energy Board National Transportation Safety Board Office of Pipeline Safety Pipeline and Hazards Materials Safety Administration Transportation Safety Board US Coast Guard

AER

1.15

FERC NEB NTSB OPS PHMSA TSB USCG

1.15 1.15 1.15 1.15 1.15 1.15 1.15

Appendix II: Unit Conversions

Corrosion rate conversion factors (When metal density “d” is in grams per cubic centimeter (g/cm3)) Factor for conversion to Unit

mdd

g/m2/d

mm/y

mpy

Milligrams per square decimeter per day (mdd) Grams per square meter per day (g/m2/d) Millimeters per year (mm/y) Mils per year (mpy)

1

0.1

0.0365/d

1.437/d

10

1

0.365/d

1.44/d

27.4d 0.696d

2.74d 0.0696d

1 0.0254

1

General conversion factors Measurement

From

To

Multiply by

Angle Area Area Bending moment or torque Concentration Current density Current density Current density Energy Energy Energy Flow rate Flow rate Flow rate Flow rate Force Force Force per unit length Force per unit length Fracture toughness

Degree in.2 ft.2 lbf.in mg/L A/in.2 A/in.2 A/ft.2 Btu kW.h W.h ft3/h ft3/min gal/h gal/min lbf kgf lbf/ft lbf/in. ksiOin.

Rad mm2 m2 N.m ppm A/cm2 A/mm2 A/m2 J J J L/min L/min L/min L/min N N N/m N/m MPaOm

1.745 6.451 6.451 1.129 1.000 1.550 1.550 1.076 1.054 3.600 3.600 4.719 2.831 6.309 3.785 4.448 9.806 1.459 1.751 1.098

x 10-2 x 102 x 10-2 x 10-1 x 10-1 x 10-3 x 101 x 103 x 106 x 103 x 10-1 x 101 x 10-2

x 101 x 102

(Continued)

957

958

Appendix II: Unit Conversions

dContinued Measurement

From

To

Multiply by

Heat content Heat input Impact energy Impact energy per unit area Length Length Length Length Length Mass Mass Mass Mass per unit area Mass per unit length Mass per unit time Mass per unit volume (Density) Mass per unit volume (Density) Mass per unit volume (Density) Power Power Pressure Pressure Pressure Pressure Pressure Pressure Temperature Temperature Temperature Temperature Thermal conductivity Velocity Velocity Velocity Velocity Velocity Velocity of rotation Viscosity Viscosity

Btu/lb J/in. ft.lbf ft.lbf/ft2 mil in. ft. mile, international mile, USA lb ton (short, 2,000 lb) ton (long, 2,240 lb) lb/ft2 lb/ft lb/h g/cm3 lb/ft3 lb/in3 Btu/h hp (electric) atm. Bar psi psi psi ksi o F o R K o C Btu/ft.h.oF ft/h ft/s in./s Km/h mph rev/min (rpm) poise Stokes

kJ/kg J/m J J/m2 Mm mm m Km Km Kg kg Kg kg/m2 kg/m kg/s kg/m3 kg/m3 g/cm3 W Kw Pa Pa Pa KPa MPa MPa o C K o C K w/m.K m/s m/s m/s m/s Km/h rad/s Pa.s m2/s

2.326 3.937 x 101 1.355 1.459 x 101 2.540 x 10-2 2.540 x 101 3.048 x 10-1 1.609, 344 1.609, 347 4.535 x 10-1 9.071 x 102 1.016 x 103 4.882 1.785 x 101 1.260 x 10-4 1.000 x 103 1.601 x 101 2.767 x 101 2.928 x 10-1 7.460 x 10-1 1.013 x 105 1.000 x 105 6.894 x 103 6.894 6.894 x 10-3 6.894 5/9.( oF-32) 5/9 K-273.15 o C+273.15 1.730 8.466 x 10-5 3.048 x 10-1 2.540 x 10-2 2.778 x 10-1 1.609 1.047 x 10-1 1.000 x 10-1 1.000 x 10-4

Appendix II: Unit Conversions

959

dContinued Measurement

From

To

Multiply by

Volume Volume Volume Volume Volume Volume Volume Volume Volume Volume Volume per unit time Volume per unit time

in.3 ft3 Gal (U.S. Liquid) Barrel Barrel (oil) Barrel (USA) Quart Pint Liter Liter ft3/min ft3/min

m3 m3 m3 m3 Gallon (oil) Gallon Liter Liter cm3 m3 m3/s m3/s

1.638 2.831 3.785 1.159 4.200 3.150 9.463 4.732 1.000 1.000 4.719 2.831

x 10-5 x 10-2 x 10-3 x 10-1 x 101 x 101 x 10-1 x 10-1 x 10-3 x 10-4 x 10-2

References 1. ASM Handbook, Volume 13C, “Corrosion: Environments and Industries”, S.P. Cramer and B.S. Covino, ISBN: 978-0-87170-709-3, 2006, ASM International, Materials Park, OH 44073–0002. 2. ASTM G102, “Standard Practice for Calculation of Corrosion Rates and Related Information from Electrochemical Measurements”, ASTM International, 100 Barr Harbor Drive, West Conshohocken, PA, USA, 19428–2959. 3. EW. McAllister “Pipeline Rules of Thumb”, Gulf Professional Publishing, Imprint of Elsevier, 6th Edition, 2005, ISBN: 978-0-7506-7852-0

Index

Note: Page numbers with “f” denote figures; “t” tables; and “b” boxes.

A AAS. See Atomic Absorption Spectrometry Above-ground markers (AGM), 737 Above-ground monitoring techniques AC techniques, 717 ACVG, 718, 729–730, 730f cautions in using, 734 CC techniques, 724–729 CIS, 718–720 coating defects detectable by, 735t coating performance measurement, 736t CPCR technique, 721–724 DC techniques, 718 DCVG technique, 720–721 ECAT, 731–732 EIS, 733 infrared camera, 734 Pearson survey, 730–731 situations, 717t TS technique, 732–733 Above-ground surveys, 682, 684t. See also Below-ground measurements corrosion rate prediction, 682–686 modeling using, 680 scoring system development, 680 calculation, 680 consequence corrosion control measures, 680 coupon surveys, 682, 686t CP current demand, 682, 683t inline inspections, 682, 686t scores for consequence, 681t Aboveground storage tanks (ASTs), 34–35 Abrasion resistance, 413, 651, 651t Absolute error, 757–758 AC. See Alternating current Access fitting assembly, 763 Access port, 763–765, 764f Accuracy, 757 Acid gas removal, 71–72 Acid gases, 789 Acid number. See Total acid number (TAN) Acid producing bacteria (APB), 235, 276, 650–651

Acidizing pipe, 55 Actuators, 87, 767 ACVG technique. See Alternating current voltage drop technique Ad hoc maintenance, 804 Adenosine triphosphate assay (ATP assay), 484 Adenosine-5’-phosphosulfate assay (APS assay), 484 Adhesion, 413, 622, 644–645, 646t Adhesive intermediate layer, 555 Adsorption scale inhibitors, 403 ADU. See Atmospheric distillation unit AE. See Auxiliary electrode AER. See Alberta Energy Regulator AFNOR. See Association Franc¸aise de Normalisation or French National Organization for Standardization AGA. See American Gas Association Agar deep test, 483 AGM. See Above-ground markers Air drying, 373 Air permeation, 622 AISI. See American Iron and Steel Institute ALARP. See As low as reasonably possible Alberta Energy Regulator (AER), 18, 23t Alberta Transportation and Utilities (ATU), 18 Aliphatic acids, 238 Alkanes, 4, 4t Alkyds, 410 Alkylation unit, 112–113. See also Isomerization unit Allotropes, 134 Alloy, 135 Alloy steel, 152. See also Stainless steels Alpha phase, 158–159 Alternating current (AC), 593 corrosion, 295–297, 297f, 711 stray current, 613 techniques, 717 Alternating current voltage drop technique (ACVG technique), 718, 729–730, 730f Aluminium anode, 587 Aluminum, 603

961

962

Index

Amalgam, 239 Ambrose model, 331 American Gas Association (AGA), 189 American Iron and Steel Institute (AISI), 156, 159–160, 160t American Petrochemical Institute gravity (API gravity), 7, 8t American Petroleum Institute (API), 159–164, 161t, 752 American Public Works Association (APWA), 17, 18t American Society of Mechanical Engineers (ASME), 159, 164, 170t American Society of Testing and Materials (ASTM), 159, 164, 165t American Welding Society Committee (AWS Committee), 575 Amine gas treating process, 72 Amines, 550 Ammeter clamp access, 614 Ammonia pipelines, 123 Ammonia plant, 117–118. See also Hydrogen plant Analysis of variance (ANOVA), 522–523 Anderko model, 326 Anhydrous ethanol, 124 Annealing, 148–149 Annular flow, 199 Annular space, 196 Annular-annular mist flow, 202 ANOVA. See Analysis of variance Anti-agglomerate inhibitors, 406 APB. See Acid producing bacteria API. See American Petroleum Institute API gravity. See American Petrochemical Institute gravity APS assay. See Adenosine-5’-phosphosulfate assay APWA. See American Public Works Association Aromatic hydrocarbons, 6 Arrhenius equation, 236 As low as reasonably possible (ALARP), 856 ASME. See American Society of Mechanical Engineers Asphalt, 534–538 bleeding of asphalt enamel, 536–538 conditions of asphalt coatings, 538t enamel, 535t, 534 field performance, 536–538, 538t field problems with, 538 laboratory performance, 534–536 mastic, 534 methods for testing, 537t state-of-the-art, 538 Asphaltenes, 233 inhibitors, 404–405

Associated gas, 6–7 Association Franc¸aise de Normalisation or French National Organization for Standardization (AFNOR), 159 ASTM. See American Society of Testing and Materials ASTs. See Aboveground storage tanks Ateya model, 334 ATF. See Aviation turbine fuel Atmospheric distillation unit (ADU), 75, 102–104 Atomic Absorption Spectrometry (AAS), 785 ATP assay. See Adenosine triphosphate assay ATU. See Alberta Transportation and Utilities Austenite, 144, 146f Austenitic stainless steel, 156, 157t Auto-refrigeration, 92 Automatic random data mode, 828 Automation, 769, 770t Auxiliary electrode (AE), 453 Aviation turbine fuel (ATF), 783 AWS Committee. See American Welding Society Committee

B Backfill material, 613 Bacterial control, 422 Bainite, 145, 147f Baker flow regime map, 197, 197f Barium sulfate (BaSO4), 219 Baroux model, 332 Barrel per day (BPD), 13–17 Basic sediment and water (BS&W), 75–76 BaSO4. See Barium sulfate Batch arrival, 94 Batches, 76 Batteries, 67, 597 bbl. See Blue barrel BCC. See Body-centered cubic BD factor. See Biocide decay factor Beck model, 334 Below-ground inspection, 744 chemical analysis, 746–747 corrosion characterization, 747 microbial analysis, 747 moisture content, 746 parameters, 744 pH, 746 soil resistance, 744–745, 745f visual inspection, 745–746 Below-ground measurements, 686–687 corrosion rate prediction, 694 scoring system development, 687 chemical/microbial category, 687–693, 690t coating category, 687, 689t corrosion category, 693, 693t

Index

repair category, 694 soil category, 687, 688t Ben Rais model, 334 Benzene, 6f Bernoulli principle, 182f Bertocci model, 332 BF. See Biocide factor Bidirectional pigs, 368, 370f Bio-competitive enhancers, 402 Bio-dispersants, 400 Bioaccumulation, 382 Biocide decay factor (BD factor), 346 Biocide factor (BF), 346 Biocides, 400 application, 400, 402 bio-competitive enhancers, 402 oxidizing, 401, 401f poisons, 401 selection, 402 types, 400, 400t Biodiesel, 12, 13f, 126–127, 127f Bioethanol, 11–12, 12t, 124–126, 125t Biofuel infrastructure, 123–127 Bitumen, 9–10, 61–62, 62t Black powders, 82, 233 Blast cleaning, steel, 628–630 Blister formation, 638 Blistering, 623, 657, 660f, 661t resistance, 413 Blowout preventer (BOP), 42 Blue barrel (bbl), 13–17 Body-centered cubic (BCC), 133–134, 134f Boilers, 114–115 BOP. See Blowout preventer Boroscopy, 515 BPD. See Barrel per day Brinell hardness test, 428 British Standards Institute (BSI), 159 British Thermal Unit (BTU), 3 Brittle temperature test, 641, 642t Broth bottle test, 482 bacterial count, 483t results in, 483f standards, 482 Brush pigs, 366–368, 367f, 368f BS&W. See Basic sediment and water BSI. See British Standards Institute BTU. See British Thermal Unit Bubble flow, 199, 202 Bubble test, 441 Butterfly discs, 369, 371f Bypass pigs, 371, 372f

C C-ring specimens, 433f Calcium carbonate (CaCO3), 219 Calcium sulfate (CaSO4), 219 Caliper tools. See Geometry tools Canadian Energy Pipeline Association (CEPA), 795–796 Canadian environmental protection agencies, 20 Canadian General Standards Board (CGSB), 127 Canadian Standards Association (CSA), 159, 546 Capillary pressure, 8 Capital expenditure (CAPEX), 361, 805 Capital recovery factor (CRF), 862 Capitalization, 860 Carbon dioxide (CO2), 220 H2S effect, 224 microstructure effect, 221–224 pH effect, 224 pipeline, 121–122, 122t temperature effect, 221 velocity effect, 221 Carbon steel, 46, 91, 142, 841 fabrication, 149–150 localized pitting corrosion, 334, 336t Papavinasam model, 337–341 sour gas pipeline failure statistics, 335f microstructure, 142–145, 142t production, 145–149, 147f Carbon steel corrosion, 305–306 Anderko model, 326 carbon steel acid gas effect, 315f carbon steel velocity effect, 316f CO2 partial pressure variation, 311f combination effects, 306f–309f corrosion rate, 306, 320f crude oil type on, 319f flow effect, 317f Crolet model, 319–322 crude oil wettability effect, 318f Dayalan model, 323–326 de Waard-Milliams models, 307–312 Garber model, 327 H2S and CO2 partial pressures effect, 305f H2S effect, 315f Mishra model, 323 Nesic model, 322–323 nomogram to predict sweet corrosion, 310f Oddo model, 326 Pots model, 327 Srinivasan model, 312–319, 313f Carburization, 281 Cash flow, 860

963

964

Index

Casing, 44–47 pipes, 615 Cast irons, 151–152, 153t gray irons, 152 malleable cast irons, 152 pipes, 77 white irons, 152 Cast pigs, 365–366, 366f CAT. See Current attenuation technique Catalytic cracking unit (CCU), 75, 106–108, 107f Catalytic hydrocracking unit (CHU), 108 Catalytic polymerization, 117 Catalytic reforming unit (CRU), 109–110 Cathodic disbondment test (CD test), 645–647, 647t Cathodic protection (CP), 67, 261, 283, 294, 421, 529, 582, 622. See also Coating amount of current, 584–587, 586f applicability, 605 category, 676, 679t cathodic current demand, 624f current demand, 682 current source, 587 impressed current method, 592–595 sacrificial anode, 587–592 disbondment and passage, 623 disbondment and prevention, 623–624 electrical shielding effect, 606f increase of, 624 influencing factors of effectiveness, 605–607 materials and accessories, 613–615 polyurethane foam properties, 573t potential criteria, 597–598 E-Log I curve, 604–605 100 mV polarization, 601–603 –850 mV OFF, 600 –850 mV ON, 598–600 –950 mV ON, 600 net protective current, 604 300 mV potential shift, 604 principle, 583–584, 585f side effects, 613 stray currents, 607 AC, 613 DC, 607–612 telluric current, 613 thermal insulation properties, 572t Cathodic protection current requirement technique (CPCR technique), 718, 721 current density, 723f DE vs. polarization potential, 723f pipe distance function, 722f

pipelines, 724 using plots, 721 polarized ON and OFF potentials, 721 potential readings during CP, 722f standards, 724 Cathodic reaction, 249–256 Cavitation-corrosion, 271–272, 474 Cavitation-erosion. See Cavitation-corrosion CBM. See Coal bed methane CC. See Coating conductance CCS electrode. See Copper/copper sulfate electrode CCU. See Catalytic cracking unit CD test. See Cathodic disbondment test CDF. See Critical Dilution Factor CE. See Counter electrode Cement, 174–175 Cementite, 144, 144f CEN. See European Committee for Standardization Central controller, 768f CEPA. See Canadian Energy Pipeline Association CFD. See Computational fluid dynamics CFR. See US Code of Federal Regulations CGSB. See Canadian General Standards Board CGSP. See Cyclic galvno-staircase polarization CH3CH2CH2SH. See Propanethiol CHARM model. See Chemical hazard assessment and risk management model Charpy tests, 139f Checkworks model, 346 Chemical analysis, 746–747 Chemical hazard assessment and risk management model (CHARM model), 382 Chemical methods, 414–415 Chemical reaction-controlled process, 323 Chemical resistance, 638, 638t, 650 Chemical-based gels, 371–373, 372f Chemical/microbial category, 687–693, 690t Chinese National Standards (GB), 159 Chlorination, 280 CHOPS. See Cold heavy oil production with sand Christmas tree, 65–66, 66f CHU. See Catalytic hydrocracking unit Churn flow, 199 CIE. See Corrosion-influenced erosion Circumferential MFL Tools, 742 CIS. See Close interval survey City gate, 120 Clad materials, 418–419, 419f Classical pitting corrosion mechanism, 335 Claus Sulfur plant, 114 Cleaning pigs, 361 CLOS cultures. See Clostridia cultures

Index

Close interval potential survey (CIPS). See Close interval survey (CIS) Close interval survey (CIS), 718 ON and OFF potentials, 718 CCS electrode, 718 data-logging equipment, 720 standards, 720 structure with cathodic protection, 719f structure without cathodic protection, 719f Clostridia cultures (CLOS cultures), 346 CNG. See Compressed natural gas Co-extruded tapes, 541 Coal bed methane (CBM), 11 Coal tar, 531 coatings, 627 field performance, 533 laboratory performance, 533 state-of-the-art, 534 types, 532–533 Coated pipeline, 720 Coating, 529, 633 blister formation, 638 brittle temperature test, 641, 642t category, 664–669, 666t, 687, 689t chemical resistance, 638, 638t coating thickness, 640–641, 641t cohesion tests, 639 composition, 641 compressive properties, 640 concrete coatings, 578–582 curing, 644 density/specific gravity, 643–644 dielectric strength, 633, 634t disbondment, 623 electrical resistivity, 633–634, 635t environmental stress cracking resistance, 639 filler content, 643 flow, 643 gas permeation, 637 gel time, 642 girth weld coatings, 557–566 indentation hardness, 634–635, 635t insulators, 566–574 particle size, 642 penetration resistance, 635–636, 636t pliability, 642 polymeric coatings, 529–557 porosity, 643 repair coatings, 566 resistance to oxidation, 639 sag, 641 shelf life, 643

965

softening point, 643 tear strength, 644 thermal conductivity, 633 thermal expansion, 640 thermal spray coatings, 574–578 thickness, 640–641, 641t total volatile content, 642 viscosity, 643 water permeation, 636–637, 637t weathering, 638–639 Coating conductance (CC), 718, 724 current attenuation method, 728–729 data obtained during, 727t DC current, 724 general method, 724–727 Ohm’s law, 724 potential attenuation method, 727–728 potential drop, 725f properties of steel, 726t qualitative relationship, 729t setup to measuring line current and, 725f standards, 729 Coating evaluation standards, 627–628, 629t coal tar coatings, 627 composite, 628 FBE, 627 tape, 627 three layer, 628 two layer, 627–628 Coating-environment interface, 650 abrasion resistance, 651, 651t chemical resistance, 650 freeze thaw stability, 652 impact resistance, 652, 653t microbial resistance, 650–651 resistance to elevated temperature, 652, 654t Coating-soil interface, 650, 669 Coefficient of variation (CV), 471 COGD. See Combustion overhead gravity drainage Cohesion tests, 639 Coker, 111 drums, 111 Cold heavy oil production with sand (CHOPS), 10, 65 Cold-spot corrosion (CPC corrosion). See Top-of-the line corrosion (TLC) Collection, 825 data, 827 issues, 827 modes, 828 operations team, 827 range of concentration, 827 search for data, 827

966

Index

Combustion overhead gravity drainage (COGD), 63–65 Commission errors, 823 Commissioning, 910 Committee on Metallizing. See American Welding Society Committee (AWS Committee) Common-sense approach, 830 Communication, 771, 832 corrosion team, 833 external, 916 general, 838 general public, 836–837 human to human, 832 integrity team, 833 internal, 916 lawyers and court, 837–838 media, 832, 837 peers, 835–836 regulators, 835 with self, 832–833 stakeholders, 836 subordinates, 833–834 suppliers and service providers, 834 upper management, 834 workers, 834–835 Comparison hardness test, 428 Compliance engineer, 815–816 Composite, 628 coating, 529–582 Compressed natural gas (CNG), 35–36, 120 Compressibility factors correlation between, 189f for mixed gases, 188f for natural gases, 187f Compressive stress, 284–285 Compressor stations, 83–85, 84f Computational fluid dynamics (CFD), 211, 445–446 Conceptual designer, 813–814 Concrete, 174 Concrete coatings, 578–579 in cold northern regions, 580–581 concrete durability approaches to increasing, 581 factors affecting, 580f field performance, 581–582 laboratory performance, 581 modeling effect, 697–698 state-of-the-art, 582 type, 581 Condition-based maintenance, 804 Constant extension rate test (CERT). See Slow strain rate test (SSRT)

Constant load method, 431 Constituents, 406 Construction category, 671, 673t Construction materials, 908 Contact sensors, 767 Continuous flow compressors, 84–85 Continuous maintenance, 802 Control external corrosion, 911 Controller, 767 Conventional sources, 7–8 Cooling towers, 115–116 Copper, 603 Copper alloys, 115, 152–153, 155t, 156t Copper/copper sulfate electrode (CCS electrode), 258–260, 718 Corrective maintenance, 804–805 Corrosion, 91, 846 allowance, 843, 908, 910 alternating current, 295–297 category, 693, 693t cavitation, 271–272 characterization, 747 control activities, 825 corrosion under protective coating and CUI, 294 crevice, 270–271 current, 307 data, 809 reliability, 521 deposition, 270 electrochemical nature, 249–263 fatigue, 282–283, 282f fretting, 274–275 galvanic, 265 general, 264–265 high temperature, 279–282 hydrogen effect, 287–293 intergranular, 267–269 LMC or LME, 293–294 management, 842f, 843, 867 mechanical forces, 272–274 mechanisms, 909 microbiologically influenced, 276–279 pitting, 265–267 potential, 510–512 professionals, 621, 771–773 under protective coating, 294 SCC, 283–287 selective leaching, 269–270 stray current, 294 team, 833 telluric current, 294–295 TLC, 297

Index

types, 250t underdeposit, 275–276 Corrosion cost optimization, methods to, 864 CAPEX vs. OPEX, 872–873 corrosion control activities cost, 867f corrosion professionals, 864 failure, 864 FEED, 872 FFS, 880–882 influence of probability of failure, 871f KPI, 873 LCC, 865–872 NPV comparison, 860, 870f RBI, 873–880, 879f Corrosion inhibitors, 374–375. See also Scale inhibitors active ingredients for, 378 anchoring groups in, 377t application, 388–391, 391t availability, 397, 398t batch inhibitor treatment, 392t batch treatment frequency, 392t characteristics of, 376t, 391 classification of, 375, 375f concentration, 377t downhole tubular batch treatment, 392–393 continuous treatment, 394 squeeze treatment or tubing displacement, 393 efficiency, 378–379 injection ports for, 394f laboratory methodologies, 379t in oil and gas industry, 375–378 organic constitution, 377t ranking, 384–388 relationship, 395f secondary inhibitor properties, 379–384 selection, 378 surface pipeline batch treatment, 393 and refinery continuous treatment, 394 types, 397 volume, 395–397 weighted factors, 386t, 389t Corrosion management activities, 883, 893t–907t accessories installation, 909–910 commissioning, 910 communication strategy external, 916 internal, 916 construction materials, 908 corrosion

allowance, 908, 910 mechanisms, 909 risks, 892 cost-benefit analysis, 890 data management, 915–916 external corrosion mitigation strategy, 911 monitoring techniques, 912 rate, 912, 914 facilitate management, 883 failure frequency, 917 frequency of inspection, 913 infrastructure life, 908 location, 908 segmentation, 891–892 internal corrosion monitoring techniques, 911 rate, 912, 914 KPIs, 873 maintenance activities, 914 maximum corrosion rate external, 909 internal, 909 measurement data availability, 913 mitigated corrosion rate, 910–911 mitigation to control external corrosion, 911 internal corrosion, 910 operating conditions, 908 percentage difference, 913–915 potential upset conditions in sector, 909 in upstream sector, 909 probes to monitor external corrosion, 912 internal corrosion, 911 procedures for, 914 review, 916 risk quantification, 908 validity and utilization, 913 workforce, 915 Corrosion monitoring, 513 electrochemical techniques, 513–514 external, 912 internal, 912 mass loss coupons, 513 Corrosion resistant alloy (CRA), 46, 159, 361 cladding process, 294 pitting corrosion, 327 electrochemical models, 329–334 initiation models, 331–333

967

968

Index

Corrosion resistant alloy (CRA) (Continued ) laboratory evaluation, 329 passivity models, 330–331 PREN, 329 propagation models, 333–334 Corrosion risks, 883, 892 corrosion issues, 884t limitations of, 892t parameters, 883, 891t upstream sectors, 883 Corrosion under insulation (CUI), 100–102, 294 Corrosion-influenced erosion (CIE), 234, 794 Cost estimation methods, 859–860 capitalization, 860 discounting, 860 EAC, 862–863 economic methods, 861t illustration, 862t, 863f IRR, 863–864 NPV, 860 PP, 862 Cost-benefit analysis, 890 Costin use (CIU). See Life cycle cost (LCC) Counter electrode (CE), 453, 484 Coupons, 452–452 surveys, 682, 686t CP. See Cathodic protection CPCR technique. See Cathodic protection current requirement technique CPP. See Critical pitting potential CPT. See Critical pitting temperature CRA. See Corrosion resistant alloy Crack detection tools, 741 circumferential MFL Tools, 742 eddy current tools, 742 EMAT tools, 742 external crack detection tools characteristics, 743t liquid-coupled tools, 741 wheel-coupled tools, 742 Cracking process, 105 Cracks, 741 Creeping, 199 Crevice corrosion, 271f Crevice formers, 491f CRF. See Capital recovery factor Critical Dilution Factor (CDF), 383 Critical pitting potential (CPP), 329 Critical pitting temperature (CPT), 329 Critical temperature, 148–149 Crolet model, 319–320 conditions for localized corrosion, 322 corrosion rate and corrosivity comparison, 321f

potential corrosivity, 321 types, 320–321 water contact with metal, 321 CRU. See Catalytic reforming unit Crude pour point temperature, 233 Crude tankers, 90 CSA. See Canadian Standards Association CSS. See Cyclic steam stimulation CUI. See Corrosion under insulation Culture methods, 482 agar deep test, 483 broth bottle test, 452 Curing, 644 Curing agent, 549–550 influence of, 550t Curing elements, 171 Curing time. See Dryingdtime Current attenuation technique (CAT), 731 Current interrupter, 613 CV. See Coefficient of variation Cycle-time, 94 Cyclic galvno-staircase polarization (CGSP), 465–466 Cyclic potentiodynamic polarization, 465 Cyclic steam stimulation (CSS), 10, 62–63 Cycloaliphatic epoxy resin, 549, 550f Cycloalkanes, 5 Cyclohexane, 5, 5f, 6f

D Data, 825. See also Communication collection, 825 issues, 827 modes, 828 operations team, 827 range of concentration, 827 search for data, 827 corrosion control activities, 825 databases, 829 management, 915–916 output and display, 831 processing, 830–831 storage, 831–832 structure, 829–830 verification, 828 Data-logging equipment, 720 Dayalan model, 323 corrosion rate computed steps, 324 FeCO3 absence factors, 324t FeCO3 presence factors, 325t DC. See Direct current DC stray current, 607

Index

dynamic stray current, 608–612 static stray current, 607 backfill material, 590t bond to overcome, 612f from CP, 608f sacrificial anode use, 608 typical testing system, 609f DC voltage gradient (DCVG), 718 DCVG technique. See Direct current voltage gradient technique de Waard-Milliams Models, 307–312, 309t De-aeration chambers, 117 DEA. See Diethanolamine Dealloying. See Selective leaching process Deflected sample method, 431–434 DEG. See Diethylene glycol Dehydrocyclization, 110 Density/specific gravity, 643–644 Deoxyribonucleic acid sequencing (DNA sequencing), 484 Deposition accumulation monitor, 513 Deposition corrosion, 270 Desalter unit, 102, 103f Desalting, 102 Desiccants, 72 Design engineer, 813–814 Design standards, 626–627 Destructive monitoring technique, 495 Determinate error. See Systematic error Deutsches Institut fu¨r Normung (DIN), 159 Devanathan-Stachursk test. See Electrochemical test DF. See Discount factor DG-ICDA. See Dry Natural Gas Internal Corrosion Direct Assessment DGEBA. See Digylcidyl Ether of Bisphenol-A Resin Diaminoethoxyethanol, 71 Dielectric strength, 633, 634t Diethanolamine (DEA), 71 Diethylene glycol (DEG), 312, 405 DiF. See Discontinuity factor Differential scanning calorimetry (DSC), 644 Differential thermal analysis (DTA), 644 Diffusion profile, 491 Diglycolamine (DGA). See Diaminoethoxyethanol Digylcidyl Ether of Bisphenol-A Resin (DGEBA), 548 Diluent pipeline, 121 DIN. See Deutsches Institut fu¨r Normung Direct current (DC), 456, 593, 717 Direct current voltage gradient technique (DCVG technique), 720–721 Direct detection methods, 483–484 Direct monitoring techniques, 495

969

Direct variables, 378 Direct volume meters, 88 Discontinuity factor (DiF), 346 Discount factor (DF), 860 Discount payback period (DPP), 862 Discounting, 860 Dispersed flow, 202 Dissipation rate, 595 Distribution sector, 35–36 DNA sequencing. See Deoxyribonucleic acid sequencing Domino theory, 846, 846f DOT. See US Department of Transportation Double whammy effect, 238 Double-hulled ship, 90–91 Double-submerged arc welding (DSAW), 149 Downhole stability test, 381 Downhole tubular, 47 batch treatment, 392–393 components, 48f continuous treatment, 394 hydraulic pumping system, 50f power fluid properties, 50t selection of materials, 53f squeeze treatment, 393 submersible pumps, 51f DPP. See Discount payback period Drill pipe, 42–44 Dry abrasion, 477 abrasion test apparatus, 478f gouging abrasion, 478 pin abrasion machines, 479f standards, 478 Dry gas, 4 Dry insulation. See Pipe-in-pipe insulation (PIP insulation) Dry milling process, 124. See also Wet milling process Dry Natural Gas Internal Corrosion Direct Assessment (DG-ICDA), 207, 337 Drying, 373. See also Corrosion inhibitors air, 373 glycol injection, 373 pigging operation, 373 purging with nitrogen, 374 time, 415 vacuum, 373–374, 374f DSAW. See Double-submerged arc welding DSC. See Differential scanning calorimetry DTA. See Differential thermal analysis Ductile cast irons, 152, 155f Ductileto-brittle transition curve, 139f Duplex stainless steel, 157–158

970

Index

Dynamic compressors, 84–85 Dynamic load method, 434 CSSR, 434–435 HID, 436 methods to U-bend specimens, 433f SSRT, 434, 435f Dynamic pressure, 179 Dynamic stray current, 608–612

E E-Log I curve, 604–605 EAC. See Equivalent annual cost ECAT. See Electromagnetic current attenuation technique Eccentricity of tube, 196 ECSA assay. See Epifluorescence cell surface antibody assay Eddy current tool, 521, 742 EDS. See Energy dispersive spectrometry EDTA. See Ethylenediaminetetraacetic acid EDX. See Energy dispersive X-ray EE. See Enzyme electrode EFM. See Electrical field mapping Eh. See Redox potential EHR MFL. See Extra high resolution magnetic flux leakage EIC. See Erosion-influenced corrosion EIP. See Emulsion inversion point EIS. See Electrochemical impedance spectroscopy Elastomeric coating, 565 Elastomers, 384 Electric resistance welding (ERW), 149 Electric submersible pump (ESP), 47 Electrical conductivity. See Electrical resistivity Electrical field mapping (EFM), 509 Electrical resistance probe (ER probe), 794 Electrical resistivity, 8, 633–634, 635t Electro-osmosis, 622 Electrochemical corrosion, 249 ACME corrosion, 256f cathodic reaction, 249–256 copper and zinc experiment, 260f corrosion potential, 258–260 electrolyte types, 249–256 energy required to convert ore to metal, 257t Evans diagram, 262f exchange current density, 261 galvanic series, 260–261 EMF series vs., 261t Gibbs free energy change, 256 Gibbs-Stockholm convention, 257–258 hydrogen Ion solution concentration diagram, 263f metal corrosion reduction reaction changes, 262f Nernst-Latimer convention, 257 reference electrode, 258–260

short-circuiting, 258 standard electrode potential, 259t standard potential, 258 standard reference electrodes, 260t Electrochemical impedance spectroscopy (EIS), 451–452, 469, 469f, 501, 733 equivalent circuit of corroding surface, 470f standards, 470 usefulness of, 636 Electrochemical liquid hydrogen probe, 510 Electrochemical models, 329–334 Electrochemical noise (EN), 451–452, 470–471, 499–500 Electrochemical quartz crystal microbalance (EQCM), 663 Electrochemical reactivation test (EPR test), 492, 493f Electrochemical solid hydrogen probe, 510 Electrochemical techniques, 453, 513–514 AE, 453 characteristics of, 458t corrosion rates, 457 EIS, 457 electrodes, 454–455 polarization, 456–457 guidelines on regions, 456f mounting specimen in static test, 454f potentials of standard RE, 454t requirement, 455 setup to connect RE, 455f standards, 455 Electrochemical test, 429 current response of oxidizing side, 430f diffusion coefficient, 430 hydrogen permeation cell, 429f Electromagnetic eddy current technique, 507 RFT, 507–508 Electromagnetic acoustic transducer tools (EMAT tools), 742 Electromagnetic current attenuation technique (ECAT), 731 AC current, 731 accuracy, 732 coating conductance calculation, 733f rate of attenuation, 731, 732f standards, 732 survey point during, 731f transmitter, 731 Electromotive force (EMF), 258 EMAT tools. See Electromagnetic acoustic transducer tools EMF. See Electromotive force

Index

Emulsification tendency, 380, 381t Emulsion inversion point (EIP), 214, 214f Emulsion process. See Latex process Emulsions, 73–74 EN. See Electrochemical noise Energy dispersive spectrometry (EDS), 141 Energy dispersive X-ray (EDX), 141 Engine generator, 595 Enhanced oil recovery (EOR), 59 Entropy, 846 Environmental factors, 179, 180t, 810 carbon dioxide, 220–224 flow, 179–211 H2S, 224–227 mercury effect, 239, 239t microorganisms, 234–236 oil phase, 211–217 organic acids, 237–239 oxygen, 227–231 pH, 236–237, 237t pressure, 236 sand and solids, 231–234 temperature, 236 water phase, 217–220 Environmental properties, 796–797. See also Measurement properties daily average temperature, 797f daily rainfall record, 798f daily snowfall record, 798f UV index, 796f Environmental stress cracking resistance, 639, 640t Environmental testing, 382 Enzyme electrode (EE), 484, 486f Enzyme poisons, 401 EOR. See Enhanced oil recovery EPDM. See Ethylene propylene diene monomer Epifluorescence cell surface antibody assay (ECSA assay), 484 Epoxy coating, 548 application characteristics, 551t comparison of properties, 555t curing process, 549–550 field performance, 553–554 influence of curing agent, 550t laboratory performance, 552–553 novolac resin, 549f state-of-the-art, 554 types, 550–552 Epoxy inner layer, 555 Epoxy resins, 406 EPR test. See Electrochemical reactivation test EQCM. See Electrochemical quartz crystal microbalance

971

Equivalent annual cost (EAC), 862–863, 863t Equivalent weight (EW), 459 ER probe. See Electrical resistance probe Erosion, 474 cavitation erosion, 474 liquid impingement erosion, 474–475 solid impingement erosion, 475–477, 477f Erosion-corrosion, 341–344 laboratory testing results, 344 Nesic model, 345 Shadley model, 345 Zhou model, 344–345 Erosion-corrosion enhancement factor, 344–345 Erosion-influenced corrosion (EIC), 234, 794 ERW. See Electric resistance welding ESP. See Electric submersible pump Ethylene propylene diene monomer (EPDM), 565 Ethylenediaminetetraacetic acid (EDTA), 403 European Committee for Standardization (CEN), 159 European Fitness for Service Thematic Network (FITNET TN), 882 Evans diagram, 262f Event-tree model, 847, 848f EW. See Equivalent weight Expansion joints, 87 Expert analysis. See Qualitative risk assessment process Extent of damage, 853–854 External corrosion, 96, 96f, 529. See also Cathodic protection (CP); Coating External corrosion mitigation strategy, 911 External monitoring techniques, 715 External polymeric coatings, 621–622 failure modes, 622–624 ranking of failure modes, 624–625 Extra heavy oil. See Venezuelan oilsands Extra high resolution magnetic flux leakage (EHR MFL), 517 Extraction plants. See Recovery centers Extreme value analysis, 523 Extruded polyolefins, 546 extrusion process, 546f field performance, 547–548 laboratory performance, 547 mechanical properties of, 548t state-of-the-art, 548 types, 546–547 Extrusion, 171

F Face-centered cubic (FCC), 133–134, 133f Failure assessment diagram (FAD), 880 Failure frequency, 917

972

Index

Failure modes, 622 adhesion loss, 622 air permeation, 622 blistering, 623 cathodic protection cathodic current demand, 624f disbondment and passage, 623 disbondment and prevention, 623–624 increase of, 624 cohesion loss, 622–623 cohesive coating failure, 623f ranking, 624–625 water permeation, 622 FAME. See Fatty amino acid methyl esters Fatigue cracking, 138 Fatigue resistance, 138–140 Fatty acid sequencing, 484 Fatty amino acid methyl esters (FAME), 127 Fault-tree model, 847, 848f FBE coating. See Fusion bonded epoxy coating FBPE. See Fusion bonded low density polyethylene FCC. See Face-centered cubic Federal Energy Regulatory Commission (FERC), 20 FEED. See Front-end engineering design FERC. See Federal Energy Regulatory Commission Ferrite, 143, 143f Ferritic stainless steel, 156–157 FFS. See Fitness for service FIA. See Flow injection analysis Fiber reinforced plastic (FRP), 76–77 Fiberglass rods, 53–54, 55t Fiberscopy, 516 Field coatings characteristics of, 568t environmental and safety considerations, 567t performance characteristics of, 570t Field inspection, 514 boroscopy, 515 corrosion data reliability, 521 fiberscopy, 516 ILI tools, 521 ILI-MFL, 516–517 ILI-UT, 517–521 liquid penetrant inspection, 516 MPI, 516 physical inspection, 514–515 thermography, 516 Field monitoring, 493. See also Internal corrosion monitoring corrosion potential, 510–512 destructive vs. non-destructive technique, 495 direct vs. indirect monitoring techniques, 495

eddy current technique, 507 EFM, 509 EIS, 501 EN, 499–500 ER probe, 497–498 galvanic couples, 501–502 general vs. localized corrosion technique, 495 hydrogen probe, 509–510 intrusive vs. non-intrusive technique, 495 leading vs. lagging technique, 495 LPR, 498–499 mass loss method, 496–497 MFL technique, 506–507 MIC monitoring techniques, 512–514 monitoring and inspection techniques, 494t monitoring vs. inspection, 493–495 multielectrode technique, 502–505 online vs. offline technique, 495 pit depth comparison, 496f potentiodynamic polarization, 501 probe monitoring vs. structural monitoring technique, 495 radiography, 508–509 residual corrosion inhibitors, 514 RFT, 507–508 UT technique, 505–506 Field operating conditions, 671 corrosion rate prediction, 676–680 SCC susceptibility score, 676t scoring system development, 671 construction category, 671 CP category, 676 operational category, 672 pipe category, 671 soil category, 672 FILC. See Flow-induced localized corrosion Filler, 171, 643 Finance manager, 813–814 Finish coat, 532–533 Fireflooding. See Toe to heel air injection (THAI) FISH. See Fluorescent in situ hybridization Fitness for service (FFS), 880–882 FITNET TN. See European Fitness for Service Thematic Network Flash Point by Modified Continuously Closed Cup (MCCCFP), 776 Fleischmann model, 330 Flexi-coking process, 111 Flexibility, 647–650, 650t flexible pipes, 149–150, 151f test, 413

Index

Flow, 643 froth, 200 regimes, 196–205 Flow injection analysis (FIA), 793 Flow-induced localized corrosion (FILC), 71, 209, 334 Fluid catalytic cracking, 106–107 Fluid coking process, 111 Fluid saturation, 8 Fluorescent in situ hybridization (FISH), 484 Foam pigs, 365, 365f, 371 Foaming tendency, 381 Formal qualitative risk assessment process, 849 Fouling, 795 Four layer coating, 556 Freeze thaw stability, 652 Fretting corrosion, 274–275, 275f Front-end engineering design (FEED), 872 Front-end loading (FEL). See Front-end engineering design (FEED) Froth flow, 200 Froude number (Fr), 205–206 FRP. See Fiber reinforced plastic Fuel cell, 597 Functional quality. See Human quality Furans, 409–410 Fusion bonded epoxy coating (FBE coating), 529–531, 550, 560, 627 advantages and disadvantages, 552t compositions of commercial, 551t field inspections, 554 field performance of, 553t performance, 554, 554t surface preparation and coating process, 552t Fusion bonded low density polyethylene (FBPE), 547 Fusion bonding, 547 Future value (FV), 860

G GALL cultures. See Gallionella cultures Gallionella cultures (GALL cultures), 346 Galvanic corrosion, 265 Galvanic couples, 501–502 Galvanic series, 260–261 Galvele model, 334 Gas chemical properties, 789 dehydration facilities, 71–72 generators, 59–61 hydrates, 11 permeation, 637, 662–663, 663f

physical properties, 780 plants, 111–112 storage, 93–94 stripping, 57, 57f treating unit, 113 turbine, 597 volume, 775 Gas sweetening. See Acid gas removal Gas to oil ratio (GOR), 6–7, 770 Gas transmission pipelines, 81–82. See also Oil transmission pipelines Gas-dominated systems, 319 Gaseous hydrocarbon. See Natural gas Gassy oil, 73 GB. See Chinese National Standards Gel pigs, 371–373, 372f Gel time, 642 Gelled liquids, 371–373, 372f General corrosion, 264, 436–438 laboratory methodologies, 438–451 monitoring techniques, 451–472 surface layers, 264 uniform corrosion illustration, 264f Geometry tools, 521–521 GHG. See Greenhouse gas Gibbs-Stockholm convention, 257–258 Girth weld coatings, 557. See also Polymeric coatings elastomeric coating, 565 heat shrinkable coating, 559–560 liquid epoxy coating, 561 in oil and gas industry, 558f polyolefin coatings, 563 powder epoxy coating, 560–561 tape coating, 557–559 urethane coatings, 561–562 vinylester coating, 562–563 visco-elastic coatings, 565–566 wax coating, 564 Glass cell experiments, 322 Global oil demand, 1 Global unconventional gas sources, 9t Glycerol displacement test, 431 Glycol, 312 test, 381 GOR. See Gas to oil ratio GOR ratios. See Gas-to-oil ratios Gouging abrasion, 478 Grains, 134 Gravel pack screens, 46–47 Gray irons, 152, 154f Green coke, 111

973

974

Index

Green rot, 281 Greenhouse gas (GHG), 124 Griffin model, 330 Gross error, 761 Gypsum, 219

H H2SxO6. See Polythionic acid Hard-facing, 44 Hardness, 137, 138t, 410 Hardness test, 426–427 Brinell hardness test, 428 comparison hardness test, 428 microhardness test, 428 Rockwell hardness test, 427 Vickers hardness test, 428 Harmonized Mandatory Control System (HMCS), 384 Hazardous materials (HAZMAT), 34–35 HB. See Hydrogen blistering HCl. See Hydrochloric acid HCP. See Hexagonal-close packed HCU. See Hydrocracking unit HDPE. See High density polyethylene; High-density polyethylene HDS. See Hydrodesulphurization HE. See Hydrogen embrittlement Heat exchangers, 114–115 Heat shrinkable coating, 559 characteristics of, 559t field performance, 560 laboratory performance, 560 state-of-the-art, 560 type, 559 Heat transfer resistance, 513 Heavy crude oil pipelines, 70 Heavy gas oil (HGO), 75 HEP. See Percentage of human error Heteroatoms, 375 Hexagonal-close packed (HCP), 133–134, 134f Hexane, 5f HF. See Hydrofluoric acid HFAU. See Hydrofluoric alkylation unit HGO. See Heavy gas oil HHV. See Higher heating value HIC. See Hydrogen induced cracking; Hydrogen-induced cracking HID. See Hydrogen induced disbondment High density polyethylene (HDPE), 539 High pH SCC, 702–703, 704t High pressure reference electrode, 511f High resolution magnetic flux leakage (HR MFL), 517 High temperature corrosion, 490–491

gaseous environments, 279–281, 280f liquid environments, 281–282 types, 279 High temperature hydrogen induced cracking (HTHIC), 117, 287–288, 292–293 High temperature oxidation. See High temperature corrosion High temperature scaling. See High temperature corrosion High temperature tarnishing. See High temperature corrosion High vapor pressure (HVP), 121 pipeline, 121 High-density polyethylene (HDPE), 96–97 High-speed autoclave test (HSAT). See Rotating cage (RC) Higher heating value (HHV), 3 Histogram, 522 HMCS. See Harmonized Mandatory Control System Holiday detection, 653, 715–717, 716t Hollow stem, 415–416 Horizontal flow regimes, 200–202, 201f Hot applied tapes, 339 Hot-tapping method, 120 HR MFL. See High resolution magnetic flux leakage HRBS. See Rockwell hardness Scale B HRC. See Rockwell hardness Scale C HSC. See Hydrogen stress-cracking HTHIC. See High temperature hydrogen induced cracking HTU. See Hydrotreating unit Huff-and-puff operation, 62–63 100 mV polarization, 601 aluminum, 603 characteristics of materials, 588t copper, 603 CP interruption, 601–603 disadvantage of, 603 Human and organizational error. See Human quality Human being functions, 823 Human factor. See Human quality Human quality, 822 Human resources, 810 Hutton platform inspections, 577–578 HVP. See High vapor pressure Hydrate inhibitors, 405–406. See also Corrosion inhibitors Hydraulic pumping system, 50f Hydrocarbons, 3t, 4–6, 5t, 374, 841 conventional sources, 7–8 renewables, 11–12 sources, 6 unconventional sources, 8–11 Hydrochloric acid (HCl), 55, 403 Hydrocracking unit (HCU), 108 Hydrodesulphurization (HDS), 105 Hydrodynamic parameter, 378

Index

Hydrofluoric acid (HF), 55, 112 Hydrofluoric alkylation unit (HFAU), 112 Hydrogen absorption tests, 429 electrochemical test, 429–430 glycerol displacement test, 431 Hydrogen atoms, 287 Hydrogen blistering (HB), 287–288 Hydrogen effect, 287, 301, 302t environment severity, 304–305, 304f HB, 288, 290f HE, 288–292 HIC, 288, 290f, 291f HID, 293 HTHIC, 292–293 hydrogen grooving, 293 material susceptibility, 302–304 SSC, 292 SWC, 288, 291f types, 287–288, 289t Hydrogen embrittlement (HE), 287–288, 288–292, 436 Hydrogen flaking. See Hydrogen induced disbondment (HID) Hydrogen grooving, 293 Hydrogen induced cracking (HIC), 69, 287–288, 302 Hydrogen induced disbondment (HID), 106, 287–288, 293 Hydrogen permeation cell, 429f Hydrogen pipeline, 122, 123t Hydrogen plant, 117 Hydrogen pressure induced cracking (HPIC). See Hydrogen induced cracking (HIC) Hydrogen probe, 509–510 Hydrogen stress-cracking (HSC), 287–288 Hydrogen sulfide (H2S), 42–44, 224–225 CO2 effect, 227 microstructure effect, 226 pH effect, 226, 227f temperature effect, 226 velocity effect, 226 Hydrogen-induced cracking (HIC), 436 Hydrogenase assay, 484 Hydrostatic tests, 744–744 Hydrotransport pipelines, 70–71 Hydrotreating unit (HTU), 75, 105–106 Hyperthermophile, 350

I IATA. See International Air Transport Association ICP. See Inductively Coupled Plasma ICP-AES. See Inductively Coupled Plasma Atomic Emission Spectrometry IGSCC. See Intergranular stress-corrosion cracking ILI. See Inline inspection

975

ILI tools. See In-line inspection tools ILI-MFL. See Inline inspection–magnetic flux leakage ILI-UT. See Inline inspection–ultrasonic Impact resistance, 138, 413, 652, 653t Impressed current method, 592 battery, 597 engine generator, 595 fuel cell, 597 gas turbine, 597 power source, 592–595 solar electric power generator, 597 thermo-generator, 596 thermoelectric generator, 596–597 wind power, 597 In situ combustion process, 10 In situ production, 62 CHOPS, 65 CSS, 62–63 SAGD, 63 THAI, 63–65 VAPEX, 65 In-line inspection tools (ILI tools), 715 characteristics of, 738t cost/benefit, 737 crack detection tools, 741–742 data maintenance, 737 detection, 736 external mass loss, 742 insertion and transportation, 736 interference, 737 location, 737 measurement, 736 metal loss tools, 741 PIG, 736 piggability, 736 side effects, 737 standards, 744 tool tracking, 737 types of fluids, 737 ultrasonic in-line inspection tools, 742t Inclined downward flow regimes, 201f Inclined upward flow regimes, 198f, 199f Indentation hardness, 634–635, 635t Indeterminate error. See Random error Indirect monitoring techniques, 495 Individual inhibitor ranking with cost (ISC), 388 Individual inhibitor ranking without cost (ISS), 388 Inductively Coupled Plasma (ICP), 785 Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES), 785 Industrial infrastructure, 843 Industry experience, 416–418

976

Index

Industry recommended practice (IRP), 149 Informal qualitative risk assessment process, 849 Infrared camera, 734 Infrastructure, 805 segmentation, 891–892 Initiation models, 331 Baroux model, 332 Bertocci model, 332 MacDonald model, 333 Okada model, 331 Oldfield-Sutton model, 332–333 pickering model, 333 Salvarezza model, 332 Shibata model, 331–332 Williams model, 332 Injection system, 394 Inline inspection (ILI), 361, 682 pipeline inspection data, 823–824 scores for ILI survey category, 686t Inline inspection–magnetic flux leakage (ILI-MFL), 516 comparison of characteristics, 518t standards, 517 Inline inspection–ultrasonic (ILI-UT), 517–521 Inner wrap, 532 Inorganic salts, 211–212 Instrument error, 762 Insulated joints, 615 Insulators, 566 field performance, 574 laboratory performance, 573–574 modeling effect, 695 state-of-the-art, 574 types, 572–573 Integrated primers, tapes with, 541 Integrity manager, 815–816 Integrity team, 833 Interference, 737 meters, 88 Intergranular corrosion, 267, 492–493 example of, 268f, 269t galvanic corrosion, special type of, 268 Intergranular stress-corrosion cracking (IGSCC), 880 Intermittent flow compressors. See Positive displacement compressors Internal coatings and linings, 406 application, 414–416 chemical compositions, 420t chemical properties, 414, 414t clad materials, 418–419, 419f industry experience, 416–418 internal liner insertion in pipeline, 418f

internal surface, 417f liners selection, 410 physical properties, 410–413, 414t polymeric liners, 406–418 refractive liners, 419–421 Internal corrosion, 96, 96f mitigation strategies to, 910 mitigation to, 910 NPV comparison, 870f, 868t–869t Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines (LP-ICDA), 211 Internal corrosion modeling carbon steel, localized pitting corrosion, 334–341 carbon steel corrosion, 305–327 corrosion professionals, 301 CRA pitting corrosion, 327–334 erosion-corrosion, 341–345 high-temperature corrosion, 353–354 hydrogen effects, 301, 302t environment severity, 304–305, 304f material susceptibility, 302–304 MIC, 346–351 scaling, 351–353 TLC, 354–355 Internal corrosion monitoring crevice corrosion, 491–492 general and localized corrosion, 436–438 laboratory methodologies, 438–451 monitoring techniques, 451–472 high temperature corrosion, 490–491 hydrogen effects, 426 hardness test, 426 hydrogen absorption tests, 429 stress tests, 431–436 intergranular corrosion, 492–493 laboratory measurement, 425–426 components, 426 laboratory methodologies, 437t monitoring techniques, 437t repeatability and reproducibility, 426 standardization organizations, 426 mechanical forces, 473 dry abrasion, 477–478 erosion, 474–477 parameters, 474 slurry abrasion, 478–479 standards, 474 wear resistance, 481 MIC, 481 microbial activity method, 484–488 microbiological methods, 481–484 simultaneous monitoring of corrosion, 484–488

Index

phases, 425 scaling, 488–490 techniques, 911 International Air Transport Association (IATA), 801 International Organization of Standardization (ISO), 159 International union of pure and applied chemistry (IUPAC), 257–258 Interstitial solid solution, 135 Intrusive monitoring technique, 911 Investment rate of return (IRR), 863–864, 864t IOB. See Iron-oxidizing bacteria iR drop correction, 462 IRB. See Iron-reducing bacteria Iron sulphide species, 226t Iron-oxidizing bacteria (IOB), 235, 276 Iron-reducing bacteria (IRB), 235, 276 IRP. See Industry recommended practice IRR. See Investment rate of return ISC. See Individual inhibitor ranking with cost ISC and with secondary inhibitor properties (ISSC), 388 ISO. See International Organization of Standardization Isocyanate coatings. See Urethane coatings Isomerization unit, 113 ISS. See Individual inhibitor ranking without cost ISSC. See ISC and with secondary inhibitor properties IUPAC. See International union of pure and applied chemistry

J Japanese Standard (JIS), 159 Jeepers. See Holiday detection Jet impingement, 447, 450f apparatus, 451f designs, 449–451 flow pattern of, 448f hydrodynamic boundary region, 448 stagnant region, 448, 449f standards, 451 turbulence wall jet region, 449 Joint coating modeling effect, 695, 695t

K Kettle test. See Bubble test Key performance indicators (KPI), 873, 874t Kinematic viscosity, 183 Kinetic inhibitors, 405 Kinetic pumps, 85 KLA. See Knife-line attack Knife lines, 221 Knife-line attack (KLA), 268–269 Knowledge, 820–822

KOH. See Potassium hydroxide KPI. See Key performance indicators Kraft paper, 532–533

L Laboratory data, 663–664 corrosion rate prediction, 670 life of pipe coating, 670t score assignment for property, 665t scoring system development, 664 calculation, 664 coating category, 664–669, 666t coating-soil interface category, 669 steel category, 664 steel-coating interface category, 669 steel-soil interface category, 670 Laboratory evaluation, 329 Laboratory measurement, 425–426 components, 428 laboratory methodologies, 437t monitoring techniques, 437t repeatability and reproducibility, 426 standardization organizations, 426 Laboratory methodologies, 625, 753 bubble test, 441 calibration and measurement, 756 coating, 633–644 coating-environment interface, 650–652 computation of results, 756 industry standards, 626t interference elimination, 755 jet impingement, 447–451 laboratory samples preparation, 755 non-standard tests, 653–663 pipeline coatings, 626 polymeric coatings, 625 RCE test, 443–444 RDE test, 442 replicate sample determination, 755 rotating cage, 444–447 selection, 754–755 sequence in, 754f standard methodologies, 626–653 static test, 438–440 steel, 628–633 steel-coating interface, 644–650 structure-environment interface, 652–653 variables simulated in, 439f for wall shear stress simulation, 438t wheel test, 441 Laboratory samples preparation, 755 LACT. See Lease automatic custody transfer

977

978

Index

Lagging monitoring technique, 495 Langemuir Saturation Index (LSI), 349 Laser profilometer, 472, 473f Latex process, 415 Layers of protection analysis (LOPA), 846–847 LC/MS/MS. See Liquid Chromatography/Tandem Mass Spectrometry LCC. See Life cycle cost LCR. See Limiting corrosion rate LDC. See Local distribution centers LDPE. See Low density polyethylene Leading monitoring technique, 495 Lease automatic custody transfer (LACT), 75–76, 769 Lease tanks, 75–76 LF. See Location of failure LGO. See Light gas oil LHV. See Lower heating value Life cycle cost (LCC), 865–872, 865f, 866t Light gas oil (LGO), 75 Limiting corrosion rate (LCR), 327 Linear polarization resistance (LPR), 451–452, 457, 498 boroscope, 500f differences in using, 498t standards, 499 three electrode polarization resistance probe, 499f Liners, 410 chemical properties, 414 physical properties, 410–413 Liquefied Petroleum (LP), 783 Liquid petroleum gases (LPGs), 4, 777 Liquid Chromatography/Tandem Mass Spectrometry (LC/ MS/MS), 794 Liquid environments, 281–282 Liquid epoxy coating, 561 Liquid hydrocarbon, 6–7, 774 Liquid impingement erosion, 474–475 arm-and spray-distributed impact apparatus, 476f impingement repetitive impact apparatus, 476f standards, 475 Liquid metal cracking (LMC), 293–294 Liquid metal embrittlement (LME), 239 Liquid naphtha, 110 Liquid natural gas (LNG), 91 regasification, 92 tanker, 93f Liquid penetrant inspection, 516 Liquid primers, 532 Liquid-coupled tools, 779t Liquids Internal Corrosion Direct Assessment (Liquids-ICDA), 337 LMC. See Liquid metal cracking

LME. See Liquid metal embrittlement LNG. See Liquid natural gas Local distribution centers (LDC), 81–82 Localized corrosion technique, 495 Location of failure, 855, 856t, 857t Lock-out tag-out process (LOTO process), 805 Loop lines, 80 Looping, 87 LOPA. See Layers of protection analysis LOTO process. See Lock-out tag-out process Low density polyethylene (LDPE), 539 Lower heating value (LHV), 3 LP. See Liquefied Petroleum LP-ICDA. See Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines LPG. See Liquefied petroleum gases LPGs. See Liquid petroleum gases LPR. See Linear polarization resistance LSI. See Langemuir Saturation Index Lutey model, 347, 347t

M Macdonald model, 331, 333 Mackinawite, 225–226 Magnesium anode, 587 Magnetic cleaning pigs, 373 Magnetic flux leakage technique (MFL technique), 506–507 Magnetic particle inspection (MPI), 516 Magnetic storms, 734 Maintenance, 801. See also Workforce activities, 808, 914 corrosion data, 809 environmental factors, 810 expert opinion, 809 health, safety, and security, 810 human resources, 810 implementation, 811 loss of productivity, 809–810 maintenance activities, 811–812 purchasing accessories, 810 quality assurance, 811 scheduling, 810 service history, 809 side effects, 811 structure availability, 809 structure details, 808 training and orientation, 811 trend analysis, 809 ad hoc maintenance, 804 associated activities, 838

Index

condition-based maintenance, 804 continuous maintenance, 802 corrective maintenance, 804–805 equipment, 802 intervals for, 802 in oil and gas industry, 803t extent of, 812 manager, 815–816 predictive maintenance, 804 preventive maintenance, 804 stages for implementation, 805 abandonment, 808 construction stage, 805 decision flow chart, 806f design stage, 805 maintenance activities, 807f modification, 807–808 non-scheduled shutdown, 808 normal operation, 806 operational changes, 807 refurbishment, 807 scheduled shutdown, 807 start-up activities, 806 types, 802 Malleable cast irons, 152 Mandrel pigs, 366, 367f Manifolds, 87, 88f Manner of release (MR), 854–855 Manual random data mode, 828 Manual regular data mode, 828 Manual sensors, 767 Manufacturers Standardization Society (MSS), 89 MAOP. See Maximum allowable operating pressure Mapping tools, 521 Martensite, 144, 146f Martensitic stainless steel, 157 Mass gain, 490 Mass loss coupons, 513 Mass loss rate (MR), 452–453, 459 Mass transfer process, 208–209, 325. See also Phase transfer Materials characterization, 881–882 chemical properties, 773–774 engineer, 813–814 metals and alloys classification, 159–170 properties, 133–141 types, 142–159 non-metals, 170–175 oil and gas industry, 133 physical properties, 771–773

quality, 822 Materials-water factor (MWF), 346 Maximum allowable operating pressure (MAOP), 80, 149 Maximum corrosion rate external, 909 internal, 909 Maxwell model, 348–349 MCCCFP. See Flash Point by Modified Continuously Closed Cup MDEA. See Methyldiethanolamine MEA. See Monoethanolamine Mean, 757 Measurement properties, 771 fouling, 795 gas chemical properties, 789 physical properties, 780 volume, 775 materials chemical properties, 773–774 physical properties, 771–773 multiphase flow, 781 oil chemical properties, 782–789 physical properties, 775–780 volume, 774 possible sources, 772t pressure, 781 sand measurement, 794 soil properties, 795–796 USA classification, 795f temperature, 781 water chemical properties, 789–794 physical properties, 780 Measurements, 751 data availability, 913 measured data for corrosion control, 797–799 measurement properties, 771–797 methods, 751 offline measurement, 751–763 reliability, 756, 770–771 accuracy and precision in measurement, 758f composition, 756–757 distribution frequency, 760f Gaussian curve, 762f gross error, 761 instrument error, 762 mean and median, 757 random error, 759–761

979

980

Index

Measurements (Continued ) relative and absolute errors, 758t systematic error, 757–759 Mechanical forces, 473 corrosion and mechanical forces interaction, 273f dry abrasion, 477–478 erosion, 474–477 erosion-corrosion, 272, 274 hard facing and weld overlays, 274 parameters, 474 pipe expansion, erosion-corrosion at, 274f slurry abrasion, 478–479 soft materials, 273 standards, 474 wear resistance, 481 Media, 837 Median, 757 MEG. See Monoethylene glycol Mercaptan Oxidation Unit (Merox), 109 Mesa corrosion, 221, 223f Metal dusting, 281 Metal loss tools, 741 magnetic flux leakage, 741 ultrasonic inspection, 741 Metallic coating modeling effect, 696 disbondment, 696–697 line of defense, 696 polymeric coating and CP system, 696 polymeric top-layer coating adherence, 696 Metallic crevice formers, 491–492 Metallic fasteners, 492–492 Metallography, 141, 490–491 Metals, 846 and alloys properties, 133–134 mechanical properties, 135–140 metallography, 141 phase diagram, 140–141 Meter-factor, 88 Methanol plant, 118 Methodology error, 763 Methyl tertiary butyl ether (MTBE), 117 Methyldiethanolamine (MDEA), 71 MFL technique. See Magnetic flux leakage technique MIC. See Microbiologically influenced corrosion Micro-alloying elements, 148t Microbial activity method, 484–488 Microbial analysis, 747 Microbial resistance, 650–651 Microbiological influence, 512–513 deposition accumulation monitor, 513 heat transfer resistance, 513 Microbiological methods, 481

corrosion monitoring methods, 484 culture methods, 482–483 direct detection methods, 483–484 microbiologically influenced methods, 484 Microbiologically influenced corrosion (MIC), 234 checkworks model, 346 classical mechanism, 276–277 classification, 481 formation of biofilm, 278f fouling, 795 Lutey model, 347 Maxwell model, 348–349 microbe activity, 276 microbial activity method, 484–488 microbial analysis, 747 microbiological methods, 481–484 modern mechanism, 277–279 pots model, 348 reactions, 278f simultaneous monitoring of corrosion, 484–488 Sooknah model, 349–351 standards, 747 union electric model, 346–347 Microelectrode technique. See Multielectrode technique Microhardness test, 428 Microorganisms, 234–236, 235t Mill-applied liners, 413 Miller number, 478, 480t –850 mV OFF, 600 –850 mV ON, 598 current requirements, 587t measured potential, 599 for poorly coated structures, 599–600 –950 mV ON, 600 Mitigated corrosion rate, 910 Mitigated external corrosion rate, 911 MMS. See US Department of Interior’s Minerals Management Service Modeling corrosion control, 621 above-ground surveys, modeling using, 680–686 concrete coating modeling effect, 697–698 effectiveness of, 621 external polymeric coatings, failure modes, 621–625 field operating conditions, modeling using, 671–680 insulators modeling effect, 695 joint coatings modeling effect, 695, 695t laboratory data, modeling using, 663–670 laboratory methodologies, 625–663 metallic coatings modeling effect, 696–697 strategies to mitigate external corrosion, 698 AC corrosion, 711 characteristics of soil in, 699t

Index

corrosion penetration rate variation, 702f maximum pitting corrosion rate, 700t modeling localized pitting corrosion, 698–701 modeling SCC, 702–710 Modeling localized pitting corrosion, 698–701, 699t Modeling stress corrosion cracking, 702–710, 703f axial and circumferential stress directions, 709f chemical compositions, 703t compositions, 706t distribution, 706t external near neutral pH SCC morphology, 705f high pH SCC morphology, 702–703, 705f internal pressure influence, 709f near neutral pH SCC, 703–710, 710f operating stress, 708t stress sources in pipeline, 707t Modern gas transmission pipelines, 418 Modified Postgate medium, 482 Moisture content, 746 Molten environments. See Liquid environments Momentum transfer, 209–210 Monitoring techniques, 451–452, 493–495, 512 corrosion monitoring, 513 electrochemical techniques, 513–514 mass loss coupons, 513 cyclic potentiodynamic polarization, 465 EIS, 469–470 electrochemical noise, 470–471 electrochemical techniques, 453–457 EQCM, 471 galvanic corrosion rate, 469 general, 495 laser profilometer, 472, 473f mass loss, 452–453 microbiological influence, 512–513 deposition accumulation monitor, 513 heat transfer resistance, 513 polarization resistance method, 457–462 potentiostatic polarization, 467–469 SRET, 471–472 Tafel extrapolation method, 462–465 Monoethanolamine (MEA), 71 Monoethylene glycol (MEG), 312, 405 Moody diagram, 184, 185f MPI. See Magnetic particle inspection MSS. See Manufacturers Standardization Society MTBE. See Methyl tertiary butyl ether Multi-diameter pigs, 369–371, 371f Multielectrode technique, 502 anodes and cathodes simulation, 504–505 electrodes in common joint, 503f in individual electrodes, 503f

981

in separated electrodes, 504f Multilayer, 554–555 composite coating, 556 field performance, 557 four layer coating, 556 laboratory performance, 557 state-of-the-art, 557 three layer coating, 555, 556f Multiphase flow, 781 Murphy’s law, 847–849 MWF. See Materials-water factor

N NACE. See National Association of Corrosion Engineers Naphtha, 112 Naphthenes. See Cycloalkanes Naphthenic acids, 238–239 National Association of Corrosion Engineers (NACE), 820 National Bureau of Standards (NBS), 699 National Energy Board (NEB), 18 National Fire Protection Associations (NFPA), 92 National Institute of Standards and Technology (NIST), 763 National Transportation Safety Board (NTSB), 26 Natural gas, 6–7, 93–94 Natural gas liquids (NGLs), 4, 71 Naturally occurring radioactive materials (NORM), 7 NBS. See National Bureau of Standards NCLPC mechanism. See Non-classical, localized, pitting corrosion mechanism NDT. See Non-destructive techniques Near neutral pH SCC, 703–710 NEB. See National Energy Board Neoprenes, 410 Nernst-Latimer convention, 257 Nesic model, 322–323, 345 Net cash flow, 860 Net present value (NPV), 860 Net protective current, 604 Neutralizing number, 238–239 Newtonian fluids, 77–78 NFPA. See National Fire Protection Associations NGLs. See Natural gas liquids Nickel alloys, 158, 158t. See also Titanium alloys NIST. See National Institute of Standards and Technology Nitrate-reducing bacteria (NRB), 402 Nitridation, 280. See also Sulfidation NOE. See Number of errors Noise probe, 499–500

982

Index

Non-classical, localized, pitting corrosion mechanism (NCLPC mechanism), 335 Non-destructive techniques (NDT), 880 Non-intrusive monitoring technique, 495 Non-metals, 170 cement, 174–175 concrete, 174 non-metallic crevice formers, 491–492 non-metallic tanks, 96–97 plastics, 170–171 non-Newtonian fluids, 77–78 Non-scheduled shutdown, 808 Non-solvent evaporation, 415. See also Solvent evaporation Non-standard tests, 653–654 blistering, 657 gas permeation, 662–663, 663f metallic structure, 661f piston arrangement to simulate soil stress, 655f samples from tenting test, 658f slipping, 656–657 tenting, 656, 657f water permeation, 657–662 wrinkling, 654–656, 655f Non-visual contamination, 632–633. See also Visual contamination NoOFE. See Number of opportunities for error NORM. See Naturally occurring radioactive materials Normal distribution, 522 Normal probability paper, 522 Normalization, 148–149 Novolac epoxy resin, 548 NPV. See Net present value NRA. See Numerical risk assessment NRB. See Nitrate-reducing bacteria NTSB. See National Transportation Safety Board Number of errors (NOE), 823 Number of opportunities for error (NoOFE), 823 Numerical risk assessment (NRA), 849–850

O O&M. See Operation and maintenance O/W. See Oil-in-water emulsion OCTG. See Oil Country Tubular Goods Oddo model, 326 OF. See Operation factor Office of Pipeline Safety (OPS), 20, 822 Office of Underground Storage Tanks (OUST), 34–35 Offline measurement, 751. See also Online measurement communication, 763 competency of laboratory, 753

ISO 17025 for testing laboratories, 754t laboratory methodology, 753–756 lag time, 761–762 measurement reliability, 756–761 property change during transportation, 752–753 sample collection, 752, 753f sampling point, 751–752 Offline monitoring technique, 452, 495 Offshore pipelines, 20 Oil chemical properties, 782–789 oil-gas separator, 73, 74t physical properties, 775–780 seep, 13–17 separators, 71–74 storage tanks, 94–97, 95t tankers, 90–91, 90f transmission pipelines, 82–83 volume, 774 Oil and gas industry, 1, 41–42 acidizing pipe, 55 annual corrosion cost, 27t approval requirements, 19t biofuel infrastructure, 123–127 in Canada and USA, 21t casing, 44–47 city gate and local distribution centers, 120 CNG, 120 CO2 pipeline, 121–122 compressor stations, 83–85 conservation board pipeline application procedure, 20t conventional crude oil paths, 41f corrosion significance and impact, 26–37 diluent pipeline, 121 downhole tubular, 47–55 drill pipe, 42–44 energy from hydrocarbons, 1–3, 1t, 2f energy resources application procedure, 20t failures types and causes, 27t gas dehydration facilities, 71–72 generators, 59–61 storage, 93–94 heavy crude oil pipelines, 70 high vapor pressure pipeline, 121 history, 13–17 hydrocarbons, 4–12 hydrotransport pipelines, 70–71 lease tanks, 75–76 LNG transportation, 91–92 natural gas paths, 42f oil

Index

separators, 72–74 storage tanks, 94–97 tankers, 90–91 open mining, 61–62 philosophies of Regulations, 22t pipeline accessories, 87–90 product pipeline, 118–119 production pipelines, 67–70 pump stations, 85–87 recovery centers, 74–75 refineries, 97–118 regulations, 17–26 in situ production, 62–65 tailing pipelines, 77–78 technical organizations, 25t terminals, 119 transmission pipelines, 78–83 transportation by railcars, 92–93 by trucks, 93 upgraders, 75 USA regulatory bodies, 20t waste water pipelines, 76–77 water generators and injectors, 56–59 wellhead, 65–67 Oil Country Tubular Goods (OCTG), 65 Oil phase, 211. See also Water phase chemical and physical constituents, 211–214 emulsion type, 214 partition of chemicals, 216–217, 217f wettability, 215–216 Oil-in-water emulsion (O/W), 214, 338 Oil-solid separator, 74 Oil-water partitioning, 379–380 Oil-water separator, 73–74 Oilsands, 9–10, 61–62 Oily gas, 71 Okada model, 331 Oldfield-Sutton model, 332–333 Omission errors, 823 Online and non-destructive monitoring techniques, 451–452 Online continuous data mode, 828 Online measurement, 763. See also Offline measurement access port, 763–765, 764f actuators, 767 automation, 769, 770t central controller, 768f communication, 771 drilling assembly, 765f electronics, 767–768

measurement reliability, 770–771 operator and regulator, 763 plug assembly, 766f SCADA, 769–770 sensor and automation, 763 sensors, 765–767 Online monitoring technique, 495 Online random data mode, 828 Online regular data mode, 828 Open mining, 61–62 Operation and maintenance (O&M), 31 Operation factor (OF), 346 Operational category, 672, 677t Operational expenditure (OPEX), 805 Operations engineer, 815–816 OPEX. See Operational expenditure OPS. See Office of Pipeline Safety Orangosol process, 415 Organic acids, 212, 237–239 Organizational error, 822 Oslo Paris Commission (OSPARCOM), 383 Osmosis, 622 OSPARCOM. See Oslo Paris Commission OUST. See Office of Underground Storage Tanks Outer wraps, 532 Outlier. See Gross error Oxidation, 279, 280f. See also Nitridation Oxidizing biocides, 401, 401f Oxygen (O2), 227, 228f control, 422 microstructure effect, 230, 231t pH effect, 231, 232f reduction, 422 temperature effect, 229, 230f velocity effect, 229, 230f

P P&ID. See Piping and Instrumentation Diagrams Papavinasam model, 337 bicarbonate ion effect, 339 carbon steel grade effect, 338 chloride ion effect, 339 CO2 partial pressure effect, 339 combined effects, 340, 340t duration effect, 341, 342t flow regime effect, 341, 343t H2S partial pressure effect, 339 microbes effect, 341, 343t oil wettability effect, 338 oil-water emulsion effect, 338 pressure effect, 339

983

984

Index

Papavinasam model (Continued ) solids effect, 338 sulfate ion effect, 339 temperature effect, 339 wall shear stress effect, 338 Paraffin, 214, 404–405, 404f Parallel pipelines, 193–194, 194f PARCOM. See Paris Commission Paris Commission (PARCOM), 382 Parting. See Selective leaching process Passive layers. See Surfacedlayers Passivity models Ambrose model, 331 Fleischmann model, 330 Griffin model, 330 Macdonald model, 331 Sarosala model, 330 Sato model, 330 Payback period (PP), 862 PBR. See Pilling Bedworth Ratio PC. See Potential corrosivity PCR. See Polymerase chain reaction PE. See Polyethylene Pearlite, 144, 145f Pearson survey, 730–731 Peers, 835–836 Penetration resistance, 635–636, 636t Percentage of human error (HEP), 823 Performance Test Code (PTC), 781 Permeability, 8 Personal error, 763 Petal flappers, 369, 371f Petroleum. See Crude oil Petroleum tanker. See Oil tankers PF. See Pitting factor pH control, 237t Phase diagram, 140–141, 140f Phase transfer, 210–211 Phenolics, 409, 409f PHMSA. See Pipeline and Hazardous Materials Safety Administration PI. See Pitting index Pickering model, 333 pig. See Pipeline integrity gauge Piggability, 736 Pigging, 361, 736. See also Drying bidirectional pigs, 368, 370f brush pigs, 366–368, 367f, 368f bypass pigs, 371, 372f cast pigs, 365–366, 366f cleaning applications configurations, 363t

cleaning pigs, 361 effective pig diameter, 363t foam pigs, 365, 365f gel pigs, 371–373, 372f launcher and receiver, 362–363, 362f mandrel pigs, 366, 367f multi-diameter pigs, 369–371, 371f operation, 361 physical damage, 363 pig launcher configuration, 362f pigs configurations, 364t pin wheel pigs, 368–369, 371f plow blade pigs, 368, 369f special pigs, 373 sphere pigs, 364–365, 364f suitability, 363 Pilling Bedworth Ratio (PBR), 353 Pin wheel pigs, 368–369, 371f PIP insulation. See Pipe-in-pipe insulation Pipe category, 671, 672t Pipe cross-section contraction, 195 expansion of, 194–195, 194f Pipe-in-pipe insulation (PIP insulation), 573 Pipeline accessories, 87–90 Pipeline and Hazardous Materials Safety Administration (PHMSA), 20 Pipeline coatings, 626 Pipeline integrity gauge (pig), 361, 736 Pipeline sector, 30–32 Pipes, 811 Piping and Instrumentation Diagrams (P&ID), 100, 100t, 101t Pitting corrosion, 221, 265 autocatalytic pit growth, 266–267 distribution, 222f passive layers features, 267f pit nucleation, 266 pits in stainless steel experimental result, 267f pits shapes, 266f stages, 265 surface layers, 266 Pitting factor (PF), 327, 471 Pitting index (PI), 471 Pitting Resistance Equivalent Number (PREN), 327 Planktonic organisms, 235 Plastics, 170 thermoplastics, 171 thermosets, 171 Pliability, 642 Plow blade pigs, 368, 369f Plug flow, 199 Plugging, 174–175

Index

Polarization resistance method, 457 advantages of, 462 constant B values, 457, 460t constants to converting corrosion current, 461t equivalent weight, 459 guidelines for measuring corrosion rate, 462 iR drop correction, 462 linear polarization resistance plot, 459f percentage error, 461f WE corrosion potential, 459 Poly vinyl chloride (PVC), 76–77, 539 Poly-pigs. See Foam pigs Polychloroprene, 565 Polyethylene (PE), 529–531, 539 cohesion, 544 disbondment, 544 mechanical properties, 556 requirements to apply CP, 543t tape coating, 544–545 in clay soil, 545 coating conductance, 542t failure mode, 539 layers, 539 pipeline coating properties, 541t tenting of, 545f Polygonal ferrite, 143 Polymer alloy tapes, 539 Polymerase chain reaction (PCR), 484 Polymeric coatings, 529, 624. See also Repair coatings asphalt, 534–538 coal tar, 531–534 coating conductance measurement, 724 dielectric strength, 633 epoxy coating, 548–554 extruded polyolefins, 546–548 FBE coatings, 529–531 methodologies, 625 multilayer, 554–557 oil and gas sectors, 530t, 532f requirements to apply CP of coated pipelines, 543t PE tape coated pipeline, 543t on pipelines coated with coating, 544t tape coating, 539–546 Polymeric liners, 406 alkyds, 410 constituents, 406 epoxies, 406 furans, 409–410, 409f liner materials, 411t

985

neoprenes, 410, 410f phenolics, 409, 409f properties of, 407t types, 406–410 vinyls, 409 Polymeric material, 415 Polymeric top-layer coating, 696 Polymerization unit, 117 Polyolefin coatings, 563, 564t Polyolefin outer layer, 556 Polythionic acid (H2SxO6), 106 Polyurethanes, 572 Polyvinyl acetate, 409 Porosity, 8, 643 Positive displacement compressors, 84 Positive displacement pumps, 85–86 Post-weld heat-treated welds (PWHT welds), 126 Potassium hydroxide (KOH), 238–239 Potential corrosivity (PC), 320–321 Potentiodynamic polarization (PP), 452, 457, 501 Potentiostatic polarization, 467–469 Pots model, 327 factors, 328t MIC, 348 pitting factor values, 328t TLC, 354 Powder epoxy coating, 560–561 PP. See Payback period; Potentiodynamic polarization PR. See Precipitation rate PRA. See Probabilistic risk assessment Pre-project planning (PPP). See Front-end engineering design (FEED) Precipitation hardened stainless steel, 158 Precipitation rate (PR), 355 Precision, 759 Predictive maintenance, 804 PREN. See Pitting Resistance Equivalent Number Pressure, 236 drop, 182–196 pipeline, 179 static, 179 Pressure, volume, and temperature (PVT), 865 Preventive maintenance, 804 Prime mover, 85 Probabilistic risk assessment (PRA), 849–850 Probe monitoring technique, 495 Procedural document, 824–825, 826t Process optimization, 421 bacterial control, 422 oxygen control, 422 pH control, 421–422

986

Index

Product pipeline, 118–119 Product tankers, 90 Production pipelines, 67–70 Production sector, 28–30 Professional associations, 820 Propagation models, 333 Ateya model, 334 Beck model, 334 Ben Rais model, 334 Galvele model, 334 Tester model, 333 Propanethiol (CH3CH2CH2SH), 109 Property evaluation standards, 628, 630f Propyl mercaptan. See Propanethiol (CH3CH2CH2SH) Protective coating, 606, 657–659 Protein denaturants. See Enzyme poisons Provers, 88 Ps. See Pearson survey PTC. See Performance Test Code Pulse generator, 614 Pump stations, 85–87 Purchase officer, 813–816 Purchasing accessories, 810 PVC. See Poly vinyl chloride PVT. See Pressure, volume, and temperature PWHT welds. See Post-weld heat-treated welds

Q QC. See Quality control QCM. See Quartz crystal microbalance QRA. See Quantitative risk assessment Qualitative approach. See Common-sense approach Qualitative risk assessment process, 849 Quality, 822–825 assurance tests, 384, 385t engineer, 813–814 during maintenance, 811 Quality control (QC), 806 Quantitative approach. See Statistical approach Quantitative risk assessment (QRA), 849–852 Quartz crystal microbalance (QCM), 662 Quenching, 148–149

R Radioactive method, 484 Radiography, 508–509 Railcars, transportation, 92–93 Random error, 759–761 Rate of return on investment (ROI). See Investment rate of return (IRR) RBI. See Risk based inspection RC. See Rotating cage

RCE test. See Rotating cylinder electrode test RDE test. See Rotating disc electrode test RE. See Reference electrode Real time technique. See Leading technique Recommended Practice 5L2 (RP 5L2), 418 Recovery centers, 74–75 Rectifier voltage, 592–593, 595 Redox potential (Eh), 351 Reference electrode (RE), 453 potentials of standard, 454t setup to connect, 455f simultaneously monitoring SRB activity, 484 Refineries, 97–118, 98f continuous treatment, 394 sector, 35 Refractive liners, 419–421 Refurbishment, 807 Regular enamel, 532 Regulators, 835 Rehabilitation coatings. See Repair coatings Remote field technique (RFT), 507–508 Remote monitoring, 768 Remote sensor, 767 Remote thermography, 781 Remotely operated vehicles (ROV), 736 Repair category, 694 Repair coatings, 566. See also Thermal spray coatings environmental and safety considerations, 567t field application, 566 steel pipeline transporting oil, 566 Repeatability, 426 Reproducibility, 426 Residual corrosion inhibitors, 514 Resistance to oxidation, 639 RFT. See Remote field technique Rheogram, 77–78, 78f Ribonucleic acid sequencing (RNA sequencing), 484 Risk assessment, 843, 845 bathtub curve, 845f consequence, 852 domino theory, 846, 846f event-tree model, 847, 848f extent of damage, 853–854, 853f failure pressure probabilities variation, 851f fault-tree model, 847, 848f location of failure, 855, 856t, 857t manner of release, 854–855 Murphy’s law, 847–849 occurrence, 845

Index

qualitative method, 849 quantification, 855–856, 858f quantitative method, 849–852 risk occurrence types, 849 semi-quantitative method, 852 statistical distributions, 850f Swiss-cheese theory/LOPA, 846–847, 847f thermodynamics second law, 846 type of contents, 854, 854t Risk based inspection (RBI), 873–880 Risk management, 856 methods to corrosion cost optimization, 859–882 risk-cost relationship, 856–859 Risk-cost relationship, 856–859 Rockwell hardness Scale B (HRBS), 427 Rockwell hardness Scale C (HRC), 427 Rockwell hardness test, 427 Rotating cage (RC), 444 assessment, 446–447 CFD analysis, 445–446, 447f corrosion rates in, 452–453 flow characteristics, 445 flow patterns, 446f schematic diagram, 445f standards, 447 Rotating cylinder electrode test (RCE test), 443–444 Rotating disc electrode test (RDE test), 442 Rotating probe. See Rotating cage (RC) ROV. See Remotely operated vehicles RP 5L2. See Recommended Practice 5L2 Ryznar stability index (RSI), 352

S SAAU. See Sulfuric acid alkylation unit Sacrificial anode, 587 actual energy output, 591 anode life, 592 cathodic current demand comparison, 579t cathodic disbondment comparison, 578t, 579t CP circuit resistance, 589–590 current efficiency, 591 current output, 589 driving potential, 589 theoretical energy output, 590–591 use in static stray current, 608 utilization factor, 591 Safe-fill allowance, 94 Sag, 641 SAGD. See Steam-assisted gravity drainage Sales person, 813–814 Salt crock test, 645–647 Salvarezza model, 332

Sample collection, 752, 753f Sampling point, 751–752 Sand, 231–234, 234f, 794 SAR number. See Slurry Abrasion Response number Sarosala model, 330 Sato model, 330 Saturated calomel electrode (SCE), 258–260 Saturated gases, 111 Saturation factor, 325–326 Saturation index (SI), 219, 326 Saturation ratio (SR), 219 SAW. See Submerged arc welding SCADA. See Supervisory control and data acquisition Scale inhibitors, 403–404, 489t Scaling, 351, 488–490 indices, 353 indices to predict scale formation, 353t LSI, 351–352 RSI, 352 tendency to form scale, 352t Scanning electron microscopes (SEM), 141 Scanning reference electrode technique (SRET), 471–472 SCC. See Stress-corrosion cracking SCE. See Saturated calomel electrode SCO. See Synthetic crude oil Scratching abrasion, 477 SCU. See Steam cracking unit Sealing pigs, 361 Seamless pipes, 149 Secondary cementing process, 174–175 Secondary inhibitor properties, 379 compatibility with materials, 384 emulsification tendency, 380 emulsion test result presentation, 381t foaming tendency, 381 oil-water partitioning, 379–380 quality control and assurance tests, 384, 385t solubility, 380 thermal stability, 381 toxicity/environmental friendliness, 382–384 UK color scheme for, 383t Secondary recovery. See Water flooding Selective dissolution. See Selective leaching process Selective leaching process, 269–270 SEM. See Scanning electron microscopes Semi-quantitative approach. See Weighing framework Sensors, 765–767 Separators, 67 Series pipeline, 192–193, 193f Service providers, 834 SF. See Silt factor

987

988

Index

Shadley model, 345, 345t Shale gas, 10–11. See also Tight gas Shale oil, 10 SHC. See System Head Curve Shelf life, 643 Shibata model, 331–332 SI. See Saturation index Silt factor (SF), 346 Simple payback period (SPP), 862 Simultaneously monitoring SRB activity, 484 biocorrosion probe for, 486f EE function, 486f equivalent circuit of corroding surface, 487f multielectrode system, 488f principle of, 485 Single hulled ship, 90–91 Single phase gas, 186–189 Single phase liquid, 183–186 16-probe microelectrode, 505f Slipping, 656–657, 658f, 659f, 660f Slow strain rate test (SSRT), 434, 435f Slug flow, 202 Slurry abrasion, 478–479 Slurry Abrasion Response number (SAR number), 478 Slurry pipelines. See Tailing pipelines SME. See Subject matter expert SMYS. See Specified minimum yield strength Sodium sulfite (Na2SO3), 57–58 Soft zone cracking (SZC). See Hydrogen blistering (HB) Softening point, 643 SOHIC. See Stress-oriented hydrogen induced cracking Soil category, 672, 675t below-ground measurements, 687 scores for, 688t Soil properties, 795–796 resistance, 728, 744–745, 745f Solar electric power generator, 597 Solid hydrate, 405 Solid impingement erosion, 475–477, 477f Solid phase micro extraction (SPME), 793 Solids, 213, 231–234, 232t Solubility, 219, 380 Soluble spheres, 365 Solvent evaporation, 415. See also Non-solvent evaporation Solvents, 116 extraction unit, 116 solvent-containing liquid epoxy, 550 solvent-less liquid epoxy, 552

Sooknah model, 349–351 Sour, 7 corrosion, 225 environments, 225 water stripper, 113 SPCC. See Spill Prevention Countermeasure and Control Special pigs, 373 Special sector, 36–37 Specification engineer, 813–814 Specified minimum yield strength (SMYS), 80 Spent acid, 55 Sphere pigs, 364–365, 364f Spill Prevention Countermeasure and Control (SPCC), 34–35 Spiral welding process, 149 SPME. See Solid phase micro extraction Sponge oil, 112 SPP. See Simple payback period Squeeze treatments, 393 Squeezing, 174–175 SR. See Saturation ratio SR MFL. See Standard resolution magnetic flux leakage SRB. See Sulfate reducing bacteria; Sulphate-reducing bacteria SRET. See Scanning reference electrode technique Srinivasan model, 312–319 SRU. See Steam reforming unit SSC. See Sulfide stress cracking SSRT. See Slow strain rate test Stainless steels, 155–158, 157t, 384 Stakeholders, 836 Standard discs, 370 Standard reference materials, 762–763 Standard resolution magnetic flux leakage (SR MFL), 517 Standard temperature and pressure (STP), 206 Static pressure, 179 Static stray current, 607 backfill material, 590t bond to overcome, 612f from CP, 608f sacrificial anode use, 608 typical testing system, 609f Static test, 438, 439f mounting specimen in, 440f, 454f standards, 440 Statistical analysis, 830 Steam cracking unit (SCU), 109 Steam reforming unit (SRU), 116–117 Steam-assisted gravity drainage (SAGD), 10, 63, 64t Steel, 628, 703–704 blast cleaning, 628–630 category, 664

Index

methanation, 292 requirements of, 631t surface profile, 630–632 visual contamination, 632 Steel-coating interface, 644 adhesion, 644–645, 646t category, 669 CD test, 645–647, 647t comparison, 648t flexibility, 647–650, 650t Steel-soil interface category, 670 Step-wise cracking (SWC), 69, 288 Sticky deposits test, 381 Stirred corrosion test. See Bubble test Storage tank sector, 34–35 STP. See Standard temperature and pressure Strain-based design, 80–81 Stratified flow, 202 Stratified-wavy flow, 202 Stray currents, 607 AC, 613 corrosion, 294 DC, 607–612 telluric current, 613 Stress tests, 431 bend beam specimen and holder configuration, 432f C-ring specimens, 433f constant load method, 431 deflected sample method, 431–434 dynamic load method, 434–436 Stress-based design, 80 Stress-corrosion cracking (SCC), 44, 283 austenitic stainless susceptibility, 286t chloride, 285 compressive stress, 284–285 environmental factors, 285–287 stresses types, 287f susceptibility of materials, 285t threshold stress level, 285 transgranular nature, 284f Stress-oriented hydrogen induced cracking (SOHIC), 288, 292f Stress-strain curve, 137, 137f Structural monitoring technique, 495 Structure-environment interface, 652–653 Subject matter expert (SME), 809, 849 Submerged arc welding (SAW), 149 Submersible pumps, 51f, 54t Subordinates, 833–834 Subsea production pipelines, 68 Substitutional solid solution, 135 Sucker rod pumps, 48, 52f, 52t, 54t

989

Sulfate reducing bacteria (SRB), 59, 276, 346, 401, 650–651 Sulfidation, 279 Sulfide stress cracking (SSC), 42–44, 225, 287–288, 292, 302 Sulfites, 57–58 Sulfur content, 212, 213f Sulfur dioxide (SO2), 57–58 Sulfuric acid (H2SO4), 112 Sulfuric acid alkylation unit (SAAU), 112 Sulfurous acid (H2SO3), 106 Sulphate-reducing bacteria (SRB), 235 Super duplex stainless steels, 157–158 Supervisory control and data acquisition (SCADA), 763, 769–770 Suppliers, 834 Surface layers, 264 mining, 62 pipeline batch treatment, 393–394 profile, 630–632 SWC. See Step-wise cracking Swiss-cheese theory, 847f Synthetic crude oil (SCO), 75 Synthetic zeolytes, 106–107 System Head Curve (SHC), 182, 183f Systematic error, 757–759

T Tafel extrapolation method, 462–465 Tafel regions, 462–463, 464 Tailing pipelines, 77–78 TAN. See Total acid number Tape coating, 539, 557, 627 characteristics of, 558t comparison, 540t field performance, 541–545, 559 laboratory performance, 541, 558–559 requirements to apply CP pipelines, 543t state-of-the-art, 559 types, 539–541, 558 TCF. See Trillion cubic feet TCM. See Trillion cubic meters TCU. See Thermal cracking unit TDS. See Total dissolved solids TE. See Thermal efficiency Tear strength, 644 TEG. See Triethylene glycol Telluric current corrosion, 296f TEM. See Transmission electron microscopes Temperature factor (TF), 236, 346 Tempering, 148–149 Tensile strength, 136–137, 136f. See also Yield strength

990

Index

Tension leg platform (TLP), 575 Tenting, 656 Teritiary recovery. See Gas generators Terminals, 119 Test station, 613, 614f Tester model, 333 TF. See Temperature factor TGSCC. See Transgranularstress-corrosion cracking THAI. See Toe to head air injection Thermal conductivity, 633 Thermal cracking unit (TCU), 75, 108 Thermal efficiency (TE), 3 Thermal expansion, 640 Thermal polymerization, 117 Thermal spray coatings, 574–575 field performance, 577–578 laboratory performance, 576–577 state-of-the-art, 578 type, 576 Thermal sprayed aluminium coating (TSA coating), 575 Thermal stability, 381 Thermo-generator, 596 Thermodynamic inhibitors, 405 Thermodynamic scale inhibitors, 403 Thermoelectric generator, 596–597 Thermography, 516 Thermoplastics, 171, 173t, 546 Thermosets, 171, 174t 300 mV potential shift, 604 Three layer coating, 556f, 628, 555 Three-phase liquid-liquid-gas, 192 Threshold-based approach, 830 Tight gas, 11 Titanium alloys, 115, 158–159 Titanium oxide (TiO2), 159 TLC. See Top-of-the line corrosion TLP. See Tension leg platform Toe to head air injection (THAI), 10, 63–65 Tool tracking, 737 Top-of-the line corrosion (TLC), 82, 297 DeWaard model, 354 Gunaltum model, 355 key parameters, 354 Nyborg model, 355 Pots model, 354 Top-ranked inhibitor, 388 Total acid number (TAN), 238–239 Total dissolved solids (TDS), 349 Total suspended solids (TSS), 349 Total volatile content, 642 Town gas, 13–17 Toxicity/environmental friendliness, 382–384

Traffic signal method, 873 Transesterification, 126–127 Transgranularstress-corrosion cracking (TGSCC), 880 Transient flow, 196 Transition temperature, 138 Transmission electron microscopes (TEM), 141 Transmission factors, 190t pipelines, 78–83 Transmit time, 82–83 Transmitter pig. See Special pigs Transmix materials, 83 Transportation Safety Board (TSB), 26 Transwave system technique (TS technique), 732–733 Trend analysis, 809 Triethylene glycol (TEG), 72, 312, 405 Trillion cubic feet (TCF), 3 Trillion cubic meters (TCM), 3 Trunk lines. See Oil transmission pipelines TS technique. See Transwave system technique TSA coating. See Thermal sprayed aluminium coating TSB. See Transportation Safety Board TSS. See Total suspended solids Tubing displacement. See Downhole tubular squeeze treatment Turbo-compressors. See Continuous flow compressors Turn-key engineer, 815–816 Turn-key process, 805 Two-phase gas-solid, 192, 205 Two-phase liquid-gas, 189–191 Two-phase liquid-liquid, 192, 202 Two-phase liquid-solid, 192, 202–204

U U-bend specimens, 433f Ultrasonic technique (UT technique), 493–495, 505–506 Ultraviolet index (UV index), 796f Ultraviolet light (UV light), 54–55 Umbilicals, 384 Unconventional sources, 8–11 Underdeposit corrosion, 275–276, 276f Underground storage tanks (USTs), 34–35 Unified Numbering System (UNS), 159, 170, 171t, 172t Uniform corrosion. See General corrosion Union electric model, 346–347 Unit cell, 133–134 United Kingdom Scheme, 383 United States of America (USA), 699 Upgraders, 75 Upper management, 834 Urethane coatings, 561–562

Index

US Code of Federal Regulations (CFR), 22, 823 US Department of Interior’s Minerals Management Service (MMS), 20 US Department of Transportation (DOT), 20

V Vacuum de-aeration process, 57, 58f Vacuum distillation unit (VDU), 75, 105 Vacuum drying, 373–374, 374f Van der Waal’s equation, 205, 207 Vapor extraction process (VAPEX), 10, 65 Vapor phase corrosion, 96 VDU. See Vacuum distillation unit Vehicle, 406 Venezuelan oilsands, 10 Vertical downward flow regimes, 200, 200f Vertical upward flow regimes, 197–200, 198f VF. See Visual factor Vibratory cavitation erosion apparatus, 475f Vickers hardness test, 428 Vinyl acetate liners, 416 Vinyl resins, 409 Vinylester coating, 562–563 Visbreaker unit, 110–111 Visco-elastic coatings, 565–566 Visual contamination, 632. See also Non-visual contamination Visual factor (VF), 346 Visual inspection, 745–746

W W/O emulsion. See Water-in-oil emulsion WAG. See Water and gas Wall shear stress, 210 Waste water pipelines, 76–77 Water accumulation, 205 multiphase, 207–208 single phase gas, 206–207 single phase oil, 205–206 chemical properties, 789–794 flooding, 56 generators and injectors, 56–59 handling systems, 60t permeation, 622, 636–637, 637t, 657–662 phase anions effect, 218 cations effect, 219 combination, 219–220 physical properties, 780 removal, 72 stripper, 113–114

991

Water and gas (WAG), 59 Water flooding, 7–8 Water condensation rate (WCR), 354 Water-in-oil emulsion (W/O emulsion), 214, 338 Wax coating, 564 Wax inhibitors, 404. See also Hydrate inhibitors Wax tapes, 541 WCR. See Water condensation rate WE. See Working electrode Wear resistance, 481 Wear-out phase, 845 Weathering, 638–639 Weighing framework, 830, 852 Wellhead, 65–67, 67t Wet Gas Internal Corrosion Direct Assessment (WG-ICDA), 337 Wet milling process, 124–125 Wet natural gas, 4 Wettability, 215 using contact angle measurement, 215f using spread method, 216f WG-ICDA. See Wet Gas Internal Corrosion Direct Assessment WGF materials. See Woven polyolefin geotextile fabric materials Wheel tests, corrosion rates in, 452–453 Wheel-coupled tools, 779t White irons, 152, 154f Whole life costing (WLC). See Life cycle cost (LCC) Williams model, 332 Wind power, 597 Wispy annular flow, 200 Workers, 834–835 Workforce, 812–813. See also Data capacity, 816, 818f corrosion degree courses, 819t education pyramid, 818f issues, 813–814 knowledge, 816, 817f development or levels stages, 821t education, 816–817 experience, 820 human error effect, 822t integrated teams, 815 knowledge, 820–822 oil and gas industry functions, 813 procedural document, 826t quality, 822–825 training, 820

992

Index

Working electrode (WE), 453 corrosion potential of, 459 SRB activity and corrosion, 484 stagnation region, 449 Workman, 813–814 Worldwide oil production, 2t Woven polyolefin geotextile fabric materials (WGF materials), 541 Wrinkling, 654–656, 655f

X X-ray diffraction (XRD), 141

Y Yield strength, 135 Young’s Modulus (YM), 135

Z Zero resistance ammeter method (ZRA method), 501 Zhou model, 344–345 Zinc (Zn), 574–576 anode, 587 ZnBr2, 46–47