Equipment and Components in the Oil and Gas Industry Volume 1: Equipment [1 ed.] 103273907X, 9781032739076

Citation preview

Equipment and Components in the Oil and Gas Industry Volume 1 Equipment and Components in the Oil and Gas Industry Volume 1: Equipment provides an overview of the equipment used in the oil and gas industry, as well as various stages of the oil and gas industry, including geology, exploration, drilling, transportation, and refining. Using practical industry examples and an accessible approach, the book is a key reference point for those seeking to learn more about the industry. The equipment used in the oil and gas industry is wide ranging, from drilling equipment and wellhead equipment, such as casings, tubing, and wellhead Christmas trees, to equipment for the transportation of fluids and gases, such as pumps and compressors. The book presents a simplified method to choose the correct equipment for each task, as well as covering the selection of heat exchangers and storage tanks. Finally, this book covers turbines, motors, and other prime movers, alongside a flare system for disposing of unwanted or waste gases in oil and gas refineries and petrochemical plants. This book will be of interest to mechanical and chemical engineers working in the oil and gas industry.

Equipment and Components in the Oil and Gas Industry Volume 1 Equipment

Karan Sotoodeh

Designed cover image: Shutterstock First edition published 2024 by CRC Press 2385 NW Executive Center Drive, Suite 320, Boca Raton FL 33431 and by CRC Press 4 Park Square, Milton Park, Abingdon, Oxon, OX14 4RN CRC Press is an imprint of Taylor & Francis Group, LLC © 2024 Karan Sotoodeh Reasonable efforts have been made to publish reliable data and information, but the author and publisher cannot assume responsibility for the validity of all materials or the consequences of their use. The authors and publishers have attempted to trace the copyright holders of all material reproduced in this publication and apologize to copyright holders if permission to publish in this form has not been obtained. If any copyright material has not been acknowledged please write and let us know so we may rectify in any future reprint. Except as permitted under U.S. Copyright Law, no part of this book may be reprinted, reproduced, transmitted, or utilized in any form by any electronic, mechanical, or other means, now known or hereafter invented, including photocopying, microfilming, and recording, or in any information storage or retrieval system, without written permission from the publishers. For permission to photocopy or use material electronically from this work, access www.copyright.com or contact the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, 978–750–8400. For works that are not available on CCC please contact [email protected] Trademark notice: Product or corporate names may be trademarks or registered trademarks and are used only for identification and explanation without intent to infringe. Library of Congress Cataloging-in-Publication Data Names: Sotoodeh, Karan, author. Title: Equipment and components in the oil and gas industry / Karan Sotoodeh. Description: Boca Raton : CRC Press, 2024. | Includes bibliographical references and index. Identifiers: LCCN 2023051960 (print) | LCCN 2023051961 (ebook) | ISBN 9781032739076 (hbk ; volume 1) | ISBN 9781032739991 (pbk ; volume 1) | ISBN 9781032731476 (hbk ; volume 2) | ISBN 9781032737799 (pbk ; volume 2) | ISBN 9781003465881 (ebk ; volume 2) | ISBN 9781003467151 (ebk ; volume 1) Subjects: LCSH: Petroleum engineering—Equipment and supplies. Classification: LCC TN871.5 .S626 2024 (print) | LCC TN871.5 (ebook) | DDC 681/.7665—dc23/eng/20231122 LC record available at https://lccn.loc.gov/2023051960 LC ebook record available at https://lccn.loc.gov/2023051961 ISBN: 978-1-032-73907-6 (hbk) ISBN: 978-1-032-73999-1 (pbk) ISBN: 978-1-003-46715-1 (ebk) DOI: 10.1201/9781003467151 Typeset in Times by Apex CoVantage, LLC

Contents Preface................................................................................................................... ix Author................................................................................................................... xi Chapter 1 An Introduction to the Oil and Gas Industry����������������������������������� 1 1.1 Introduction�������������������������������������������������������������������������� 1 1.2 Oil and Gas Formation and Characteristics�������������������������� 1 1.3 Exploration��������������������������������������������������������������������������� 4 1.3.1 Petroleum Geology�������������������������������������������������� 4 1.3.2 Exploration Techniques������������������������������������������� 7 1.3.3 Exploration Drilling���������������������������������������������� 11 1.4 Drilling������������������������������������������������������������������������������� 14 1.5 Well Completion����������������������������������������������������������������� 16 1.6 Production��������������������������������������������������������������������������� 19 1.7 Processing��������������������������������������������������������������������������� 19 1.8 Hydrocarbon Storage���������������������������������������������������������� 21 1.9 Oil and Gas Metering��������������������������������������������������������� 22 1.10 Hydrocarbon Transportation����������������������������������������������� 22 1.11 Refineries���������������������������������������������������������������������������� 23 Further Reading����������������������������������������������������������������������������� 27 Chapter 2 Drilling and Well Completion Equipment������������������������������������� 29 2.1 Introduction������������������������������������������������������������������������ 29 2.2 Rotary Drilling Subsystems������������������������������������������������ 29 2.3 Main Components and Equipment for Rotary Drilling����������31 2.4 A Detailed Description of Some of the Main Components of Drilling������������������������������������������������������ 34 2.5 Well Completion����������������������������������������������������������������� 55 2.5.1 Well Casing����������������������������������������������������������� 55 2.5.2 Cementing������������������������������������������������������������� 57 2.5.3 Perforating������������������������������������������������������������� 58 2.5.4 Packer and Tubing Installation������������������������������ 59 2.5.5 Wellhead Installation��������������������������������������������� 60 2.6 Artificial Lift����������������������������������������������������������������������� 62 Further Reading����������������������������������������������������������������������������� 64 Chapter 3 Production and Processing Equipment������������������������������������������ 66 3.1 Introduction������������������������������������������������������������������������ 66 3.2 Separators��������������������������������������������������������������������������� 66 3.2.1 Separator Configuration���������������������������������������� 67 v

vi

Contents

3.2.2 Separation Mechanisms����������������������������������������� 69 3.2.3 Separator Components������������������������������������������ 72 3.2.4 Separation Process������������������������������������������������� 78 3.3 Pressure Vessels������������������������������������������������������������������ 78 3.3.1 Design and Safety�������������������������������������������������� 80 3.4 Distillation Columns (Towers)������������������������������������������� 81 3.4.1 Distillation Process������������������������������������������������ 81 3.4.2 Laboratory Distillation Process����������������������������� 82 3.4.3 Distillation Towers������������������������������������������������ 84 3.5 Filters���������������������������������������������������������������������������������� 94 3.5.1 Introduction and Applications������������������������������� 94 3.5.2 Filtration Media����������������������������������������������������� 95 3.5.3 Types of Oil and Gas Filters���������������������������������� 96 Further Reading��������������������������������������������������������������������������� 103 Chapter 4 Equipment for Pressurizing Fluids���������������������������������������������� 105 4.1 Introduction���������������������������������������������������������������������� 105 4.2 Pumps������������������������������������������������������������������������������� 105 4.2.1 Types of Pumps��������������������������������������������������� 106 4.2.2 Pumping Terms���������������������������������������������������� 115 4.2.3 Pump Parts����������������������������������������������������������� 121 4.3 Compressors��������������������������������������������������������������������� 124 4.3.1 Types of Compressors����������������������������������������� 125 4.3.2 Compressor Selection������������������������������������������ 138 4.3.3 Compressor Terms����������������������������������������������� 140 4.3.4 Compressor Parts������������������������������������������������� 146 Further Reading��������������������������������������������������������������������������� 152 Chapter 5 Equipment for Fluid Temperature Changes�������������������������������� 155 5.1 Introduction���������������������������������������������������������������������� 155 5.2 Heat Exchangers��������������������������������������������������������������� 155 5.2.1 Introduction��������������������������������������������������������� 155 5.2.2 Thermodynamics of Heat Exchangers���������������� 156 5.2.3 Heat Transfer Mechanisms���������������������������������� 157 5.2.4 Classifications of Heat Exchangers��������������������� 160 5.2.5 Types of Heat Exchangers����������������������������������� 163 5.3 Boilers������������������������������������������������������������������������������� 181 5.3.1 Introduction��������������������������������������������������������� 181 5.3.2 Boiler Terms�������������������������������������������������������� 183 5.3.3 Boiler Types or Classifications���������������������������� 184 5.3.4 Boiler Selection��������������������������������������������������� 188 5.3.5 Boiler Mountings������������������������������������������������� 188 5.3.6 Boiler Accessories����������������������������������������������� 189

vii

Contents

5.4

Air Coolers (Air-Cooled Heat Exchangers)��������������������� 193 5.4.1 Introduction��������������������������������������������������������� 193 5.4.2 Air Cooler Advantages and Disadvantages��������� 193 5.4.3 Air Cooler Design Considerations���������������������� 194 5.4.4 Air Cooler Components�������������������������������������� 198 5.4.5 Air Cooler Types������������������������������������������������� 204 Further Reading��������������������������������������������������������������������������� 209 Chapter 6 Prime Movers������������������������������������������������������������������������������ 211 6.1 Introduction���������������������������������������������������������������������� 211 6.2 Gas Turbines��������������������������������������������������������������������� 211 6.2.1 Introduction��������������������������������������������������������� 211 6.2.2 Working Principles���������������������������������������������� 211 6.2.3 Efficiency Improvements and Technology Advancements����������������������������������������������������� 215 6.2.4 Advantages and Disadvantages��������������������������� 216 6.2.5 Gas Turbine Main Sections��������������������������������� 217 6.2.6 Gas Turbine Performance������������������������������������ 218 6.2.7 Gas Turbine Types����������������������������������������������� 221 6.3 Steam Turbines����������������������������������������������������������������� 222 6.3.1 Introduction��������������������������������������������������������� 222 6.3.2 Steam Turbine Components�������������������������������� 224 6.3.3 Principles of Operation���������������������������������������� 233 6.3.4 Classifications of Steam Turbines����������������������� 233 6.4 Reciprocating Engines������������������������������������������������������ 236 Further Reading��������������������������������������������������������������������������� 240 Chapter 7 Storage Tanks������������������������������������������������������������������������������ 242 7.1 Introduction���������������������������������������������������������������������� 242 7.2 Storage Tank Types����������������������������������������������������������� 242 7.2.1 Atmospheric Tanks���������������������������������������������� 242 7.3 Storage Tank Components������������������������������������������������ 248 7.3.1 Foundations��������������������������������������������������������� 248 7.3.2 Shells������������������������������������������������������������������� 251 7.3.3 Bottoms (Floors)������������������������������������������������� 253 7.3.4 Roofs������������������������������������������������������������������� 255 7.3.5 Accessories���������������������������������������������������������� 255 7.4 Fire Water Storage Tanks�������������������������������������������������� 271 Further Reading��������������������������������������������������������������������������� 276 Index.................................................................................................................. 277

Preface The purpose of this book is to provide a general overview of oil and gas equipment and components. The first volume focuses on the main and most important equipment. Oil and natural gas play a critical role in the global economy as the world’s primary fuel source and a major part of the energy industry. Several sectors make up the petroleum industry, including exploration, drilling, production, refining, and transportation. The purpose of Chapter  1 is to provide a general overview of the oil and gas industry. In the first chapter, a number of exploration techniques are discussed, including gravity and magnetic surveys. For oil and gas to be formed, five conditions must be met, including source rock, reservoir rock, and migration. After a well has been drilled and completed, oil is extracted from it. In the process of producing oil and gas, steps such as separation are carried out in order to separate the three phases of oil, gas, and water. Furthermore, it is necessary to further treat all three phases in order to ensure that they meet selling quality and are impurity free. Metering of oil and gas is essential in order to determine the amount of oil and gas available for sale. The storage and transportation of oil and gas are also important topics discussed in this chapter. Drilling equipment is discussed in Chapter 2 of the book. The drill pipe (the drill bit) is rotated during rotary drilling in order to create the well bore. An overview of the rotary drilling system is provided in Chapter 2. It consists of six subsystems, a power system, a hoisting system, a rotating system, a circulating system, a controlling system, and a monitoring system. As described in Chapter 3, four types of equipment are used to produce and process fluids: separators, pressure vessels, distillation columns or towers, and filters. This chapter discusses separation configurations, including vertical and horizontal separations, as well as separation mechanisms and separator internals. The term “pressure vessel” refers to a wide range of equipment, such as heat exchangers and separators. Distillation towers or columns are used to separate different products from crude oil based on their boiling points. Last but not least, filters and the different types of filters are discussed. Liquids and gases flow through channels and pipes from one point to another, which is why they are called fluids. Pumps and compressors are used to move fluid through piping systems or pipelines, which are discussed in Chapter 4. As part of the oil and gas industry, it is common to change the temperature of oil and gas, as well as other media, such as water. This category includes both cooling and heating. In Chapter 5, three types of equipment are discussed that are used to alter the temperature of fluids and gases: heat exchangers, coolers, and boilers. Pumping units, compressors, chillers, and other types of equipment are driven by prime movers in the energy industry. Chapter 6 describes the most common prime movers in the oil and gas industry, which are natural gas turbines and reciprocating engines. Last but not least, Chapter  7 discusses the different types of storage tanks as well as their main components and accessories. ix

Author Karan Sotoodeh, an Iranian author and engineer, formerly worked for Baker Hughes in his last position as a senior– lead valve and actuator engineer in the subsea oil and gas industry. He earned a PhD in safety and reliability in mechanical engineering at the University of Stavanger in 2021. Karan Sotoodeh has almost two decades of experience in the oil and gas industry, mainly with valves, piping, actuators, and material engineering. He has written 11 books about piping, valves, actuators, corrosion, and material selection and approximately 50 papers in peer-reviewed journals. Dr. Sotoodeh has also been selected for international conferences in the United States, Germany, and China to talk about valves, actuators, and piping. He has worked with many valve suppliers in the United Kingdom, Italy, France, Germany, and Norway. He loves traveling, running, swimming, and spending time in nature.

xi

1

An Introduction to the Oil and Gas Industry

1.1 INTRODUCTION Oil and natural gas play a significant role in the global economy as the world’s primary fuel sources and are major industries in the energy sector. There are several sectors within the petroleum industry, including exploration, drilling, production, refining, and transportation. There are complex and costly processes, and equipment used in different sectors of the oil and gas industry. In general, the oil and gas industry can be divided into three segments: upstream, midstream, and downstream. Exploration and identifying oil and gas reservoirs, drilling wells, and extracting raw materials from underground are all part of upstream oil and gas production and operations. The terms exploration and production company are also often used to describe them. Geologists, geophysicists, service rig operators, engineering firms, scientists, and seismic and drilling contractors are among the many individuals employed in the upstream portion of the industry. The downstream operations are those that involve the conversion of crude oil and gas into finished products. They consist of refining crude oil into gasoline, natural gas liquids, diesel, and other forms of energy. Oil and gas companies are considered downstream if they are located as close as possible to the process of supplying consumers with petroleum products. As a point of clarification, refineries and petrochemical plants are considered downstream. The primary difference between downstream and upstream operations relates to the stage of the process by which crude oil is delivered to the consumer. The term “midstream” refers to points in the oil production process that fall between upstream and downstream. Transportation and storage are essential aspects of midstream; once resources are recovered, they must be transported to refineries, which are often located in completely different geographical regions from the oil and gas reserves. Tanker ships, pipelines, and trucking fleets can all be considered modes of transportation. As shown in Figure 1.1, the oil industry is composed of three different sectors. The two pictures on the left depict a ship or platform that is used to produce natural gas and oil, which is considered upstream. The tanker in the middle and the storage tanks are related to the midstream. Finally, the refinery on the right represents the downstream section of the process.

1.2 OIL AND GAS FORMATION AND CHARACTERISTICS Millions of years ago, sea animals and plants lived in shallow waters. As the organic material died and sank to the seafloor, it mixed with other sediments and DOI: 10.1201/9781003467151-1

1

2

Equipment and Components in the Oil and Gas Industry

FIGURE 1.1  Oil and gas industry sectors. (Courtesy: Shutterstock)

FIGURE 1.2  Natural gas and oil formation processes. (Courtesy: Shutterstock)

became buried. The remains of these organisms have been transformed over millions of years under high pressure and high temperature into what we know today as fossil fuels. All fossil fuels, including coal, natural gas, and petroleum, were formed under similar conditions. In Figure 1.2, the formation of natural gas and oil is illustrated. It is believed that petroleum was discovered in vast underground

An Introduction to the Oil and Gas Industry

3

reservoirs where ancient seas once existed. It is possible to find petroleum reservoirs on land as well as on the ocean floor. Petroleum, also known as crude oil, is usually black or dark brown but can also be yellowish, reddish, tan, or green in color. Carbon and hydrogen constitute the majority of the elements in crude oil, along with oxygen, nitrogen, sulfur, and nickel in minor quantities. Crude oil supplies differ in chemical composition, as indicated by the color variations. After passing through surface separation facilities, crude oil remains liquid at atmospheric pressure because it is a mixture of hydrocarbons that exist in liquid phase in natural underground reservoirs. Generally, oil at the surface is more viscous than oil in the reservoir, and it is less dense than water. Oil can provide a great deal of energy and can be converted into different fuels, including gasoline, kerosene, and heating oil. Additionally, most plastics and ink are made from petroleum. We do not consider petroleum a renewable energy source since petroleum was made millions of years ago, and it probably takes a million years for it to form since we cannot make it in a short period of time. As natural gas is petroleum in a gaseous state, it must always be accompanied by oil, which is petroleum in a liquid state. Generally speaking, natural gas is a subcategory of petroleum that consists of hydrocarbons that are naturally occurring and contain a small amount of inorganic compounds as well. Among the cleanest, safest, and most useful sources of energy, natural gas is one of the most common. The main components of natural gas are methane CH 4 , ethane (C2 H6 ) , propane (C3 H8 ) , butane (C4 H10 ) , oxygen, nitrogen, carbon dioxide, and others. Historically, natural gas was a by-product of crude oil production. Many years ago, natural gas was regarded as undesirable, and today it is flared in large quantities in many countries, including the United States. Flaring refers to the combustion of associated gases generated during various processes. It is common for flares to be composed of a boom or stack that collects the unwanted gases to be flared. A major environmental concern today is gas flaring, which contributes significantly to global warming by generating a large quantity of greenhouse gases. A natural gas can be classified into three types: non-associated gases, associated gases, and gas condensate. Gas that is not associated with oil is derived from reservoirs that contain little or no oil. In an oil reservoir, associated gas is the gas that dissolves in the oil under natural conditions. An example of a gas-condensate is a gas with a high concentration of liquid hydrocarbons at reduced pressures and temperatures. There are three types of hydrocarbon reservoirs: gas wells, condensate wells, and oil wells. During the process of producing oil at surface temperatures and pressures, some natural gas usually emerges out of solution. The gas/oil ratio (GOR) measures the proportion of gas (standard cubic feet [scf]) that emerges from solution to oil (barrels at standard conditions). A greater depth under the crust of the earth results in a higher temperature, and at higher temperatures, more natural gas can be generated than oil. In general, natural gas is found primarily in deposits or reservoirs very deep underground. As opposed to deep deposits, shallow deposits are more likely to produce oil than gas when temperatures are low.

4

Equipment and Components in the Oil and Gas Industry

1.3 EXPLORATION The process and methods involved in finding potential locations for the drilling and extraction of oil and gas are known as oil and gas exploration. Exploration for oil and gas can be time consuming and requires detailed analysis of extensive geologic information, which may take a considerable amount of effort and time. During exploration and production cycles, the first step is to find hydrocarbon deposits or reservoirs that can be produced if technical and economic conditions are met. In the past, oil and gas explorers relied on surface signs, such as the presence of natural oil seeps. However, technological advances have allowed oil and gas exploration to become more efficient. Exploration and production companies use advanced tools and techniques to obtain a detailed picture of the subsurface. There are many methods available to conduct geological surveys. These methods range from testing subsurface oil for onshore exploration to performing seismic imaging for offshore exploration.

1.3.1 Petroleum Geology In petroleum geology, hydrocarbon fuels (oil and gas) are studied in terms of their origin, occurrence, movement, and accumulation. In order for oil and gas to be formed underground or underwater, there are five essential factors that must exist. If one of these factors is absent, oil and gas cannot be formed. The five conditions are: 1. Source rock: Typically, these rocks are sedimentary rocks containing a significant amount of organic content. In most cases, fine-grained, clayrich sedimentary rocks, such as mudstones, shale, marls, limestones, and coaly rocks (especially when mining natural gas), are considered possible source rocks, as coarse-grained sediments are too porous and permeable to retain organic material. They may have been deposited in a variety of environments, including marine, coastal, and riverine environments. A source rock is classified based on the type of organic compounds it contains, such as plankton or plants, which determines the type of hydrocarbons it will generate. A further requirement for the formation of oil is the accumulation and burial of organic materials under sufficient pressure and temperature. The required depth could range from 2 to 6 kilometers, and the temperature should be in the range of 60° to 160°C. The maturity of the source rock is an important parameter for the generation of hydrocarbons. A rock that contains total organic carbon is referred to as a source rock that will change under increasing temperatures so that the organic molecules slowly transform into hydrocarbons. It is also possible to determine the hydrocarbon potential of a source rock by its maturity. There are four broad categories of source rocks: immature (no hydrocarbons are generated), sub-mature (limited hydrocarbon generation), mature (extensive hydrocarbon generation), and over-mature (most hydrocarbons have been generated). Therefore,

An Introduction to the Oil and Gas Industry

if a rock is sub-mature, it has a much greater potential to generate additional hydrocarbons than an over-mature rock. 2. Reservoir rock: Generally speaking, a reservoir rock is any volume of rock that has sufficient porosity and permeability to facilitate the migration and accumulation of petroleum in an adequate trap environment. Porosity is defined as the percentage of void spaces in a rock in relation to the total volume of the rock. Porosity is crucial because it indicates the reservoir rock’s ability to store oil, gas, and water. The greater the porosity and capacity of a reservoir rock to store hydrocarbons, the greater its potential to produce oil and gas. Sand rocks, which are highly porous, typically have 5% to 25% porosity. Additionally, well-sorted materials (grains of the same size) have a higher porosity than poorly sorted materials (grains of dissimilar sizes). Another important term is effective porosity, which refers only to interconnected pore spaces capable of creating a flow path for hydrocarbons. A material’s permeability refers to its ability to permit liquids, gases, or specific chemicals to pass through it. Hydraulic conductivity is a property of permeable materials, such as soils and rocks, that describes how easily a fluid (usually water) can be moved through the pore space or fracture network. The higher the permeability, the higher the hydraulic conductivity. There is no porosity or permeability in the rock shown in Figure 1.3, which means that it cannot contain oil and cannot be considered a reservoir rock. 3. Migration: Migration is the movement of hydrocarbons from the source rock to the reservoir or from the reservoir to the surface and seepage. Migration consists of two stages or steps. The primary migration of petroleum involves the ejection of petroleum from fine-grained source rocks, whereas secondary migration involves the movement of petroleum through a coarse-grained carrier bed or fault to a reservoir, or the hydrocarbon moves to the surface and seeps. In geology, tertiary migration refers to the movement of petroleum from one trap to another or from one seep to another. Remigration is another term that describes the movement of hydrocarbon from one reservoir to another. Figure 1.4 illustrates how hydrocarbons migrate. While some hydrocarbons migrate to the surface as oil seepage, others remain trapped, making them suitable locations for drilling wells and producing oil. 4. Trap: Generally, a trap in petroleum geology is a geological structure that affects the reservoir rock and allows hydrocarbons to accumulate in the reservoir. The hydrocarbon trap must be covered by an impermeable rock known as a seal or cap rock in order to prevent hydrocarbons from escaping from the reservoir to the surface. Because hydrocarbons have a lower density than water, they constantly attempt to ascend and eventually reach the surface of the earth unless they are stopped by a trap. Due to the fact that hydrocarbons seek the highest point they can reach, geologists often find oil at the tops of underground structures with a hilllike shape.

5

6

Equipment and Components in the Oil and Gas Industry

FIGURE 1.3  Due to its lack of porosity and permeability, the rock shown in the figure cannot be a reservoir rock. (Courtesy: Shutterstock)

FIGURE 1.4  Hydrocarbon migration. (Courtesy: Shutterstock)

An Introduction to the Oil and Gas Industry

7

FIGURE 1.5  Since the oil was not trapped underground, it seeped onto the surface. (Courtesy: Shutterstock)

5. Seal: To prevent hydrocarbons from escaping from the reservoir to the surface, the hydrocarbon trap must be covered with an impermeable rock known as a seal or cap rock. As can be seen from Figure 1.5, the oil seeped to the surface since it was not trapped underground. There could be either an absence of a trap or an absence of a seal, or both could be lacking.

1.3.2 Exploration Techniques Occasionally, if oil seeps into the surface, it may be an indication that petroleum exists beneath the ground. It is important to note, however, that this is not always the case. Due to the fact that the underground formations cannot be seen,

8

Equipment and Components in the Oil and Gas Industry

extrapolating surface characteristics will not give an accurate representation of subsurface properties. It is therefore necessary to investigate the subsurface using geophysical methods. It involves the measurement of fundamental physical parameters, the gravitational field, magnetic field, electromagnetic field, and acoustics and the interpretation of these parameters in terms of geology. Gravity survey: The force of gravity keeps us on the ground. In the absence of our planet’s gravitational attraction, we and everything else in the universe would be swept into space. The gravity field is reassuringly simple, unipolar, and nearly vertical. There is a common gravity unit in exploration geophysics called the milliGal. This unit refers to acceleration due to gravity, and the average value at the earth’s surface is around 980,000 mGal or 9.8 m/s2. The extra gravitational attraction of dense and heavy rocks underfoot increases the downward pull and results in positive gravity anomalies (“gravity highs”). Light rocks have a diminished gravitational pull and result in negative anomalies (“gravity lows”). Moving from a gravity high to a gravity low can literally lead to weight loss, if only very slightly! In order to determine what could lie beneath the surface, gravity readers (gravimeters) measure the gravitational pull in certain rock formations. On the earth’s surface, gravitational pull is measured in milliGal units. For rock formations that do not contain oil reserves and minerals, a typical measurement is 980,000 milliGal, almost equal to a g force (9.8 newton force per kilogram mass or 9.8 m/s2); however, for rock formations that contain crude oil reserves, the measurement will rarely exceed 300–400 milliGal units. An advantage of this type of survey is that it is simple and reasonably inexpensive. In most cases, it is done on the ground in the most accurate manner. Magnetic survey: A magnetometer, a sensitive instrument that can be used on land, at sea, or in an aircraft, is used to measure variations in the intensity of the earth’s magnetic field. The underlying rocks have different magnetic properties, which cause localized magnetic variations. Considering the dipolar nature of the magnetic field and the fact that it is usually non-vertical, magnetic survey is more complex than gravity survey. In addition, it is possible for rocks to be magnetized in a vast and unpredictable variety of ways. Numerous studies have demonstrated an association between low-amplitude local anomalies of gravity and magnetic field and oil and gas deposits. A survey of this type is particularly useful in difficult-to-access areas, such as mountainous regions. A land magnetic survey may sometimes be carried out locally, but it is more commonly conducted by fixed-wing aircraft or helicopters. Helicopters can provide rapid access to remote survey areas, and their maneuverability makes them ideally suited to small-scale surveys. Another advantage of magnetic surveying is that data can be collected quickly from the air. Alternatively, gravity surveys conducted from land require more time

An Introduction to the Oil and Gas Industry

and effort to collect data. The use of magnetic surveys can be used prior to the use of expensive seismic surveys to establish the regional framework for locating possible oil and gas reserves. It should be noted that magnetic and gravity methods are only used in primary surveys in which little information is available regarding the subsurface geology and/or the thickness of sediments of potential prospective interest. Electromagnetic survey: The controlled source electromagnetics (CSEM) method as illustrated in Figure  1.6 is a geophysical method for mapping the subsurface resistivity of a marine environment. CSEM, also known as seabed logging, is a remote sensing technique that uses electromagnetic (EM) signals emitted from a source on or near the seabed. EM signals propagate through the subsurface to the seabed receivers. The information from electromagnetic signals is recorded by receivers placed on the seabed at regular intervals. As a result of the resistivity distribution within the subsurface, the electromagnetic field measured by the receivers is affected. If there is a resistive layer present, such as a hydrocarbon-charged reservoir, the EM signal can propagate with little attenuation. In the absence of a resistive layer at the seafloor receivers, the EM field will have a higher amplitude. Seismic survey: With large oil and gas fields becoming increasingly difficult to discover, geologists, geophysicists, and engineers use new technologies, such as seismic imaging, to discover resources that were unimaginable just decades ago. While this technology has been used in the industry for decades, it is constantly evolving and adapting to

FIGURE 1.6  Electromagnetic survey. (Photo by author)

9

10

Equipment and Components in the Oil and Gas Industry

new challenges. Using seismic technology, it is now possible to image deep rock formations that had previously been invisible. This technique is based on the propagation of sound waves through the earth’s rocks to the reservoir targets. As a matter of fact, sound waves originate at the surface (onshore) or on the water (offshore) and travel through the earth’s subsurface (see Figures 1.7a and b). Upon striking rocks underground,

FIGURES 1.7  (a) Offshore and (b) onshore seismic surveys. (Courtesy: Shutterstock)

An Introduction to the Oil and Gas Industry

11

sound waves are reflected back to the surface, where detectors known as hydrophones or geophones receive them. As a result of the travel times from the source to various receivers and the velocity of the seismic waves, a geophysicist may construct an image of the subsurface by reconstructing the pathways of the waves.

1.3.3 Exploration Drilling In order to provide information concerning the composition of underground rock layers and their geology and geophysics at a specific location that has been identified as potentially containing oil and/or gas deposits, one or more exploratory wells are drilled (see Figure 1.8). Therefore, if geological and geophysical information identifies and evaluates (technically as well as economically) a drillable prospect, it may be possible to move into the next phase of exploration, drilling the first exploratory well. In contrast to exploratory or appraisal drilling, which is carried out in areas that contain economic quantities of oil and gas, wildcat drilling, a form of high-risk exploratory drilling, involves drilling for oil or natural gas in areas that are either unproven or fully exploited with no concrete historical production records or have been completely exhausted as a source of oil and gas production. There are several methods for exploratory drilling, but they generally include drilling between a half mile and 3 miles from known reserves in order

FIGURE 1.8  Exploratory drilling. (Courtesy: Shutterstock)

12

Equipment and Components in the Oil and Gas Industry

to determine whether there are any additional reserves nearby. Initially, only one exploratory well is drilled in the area in order to gain more information about the reservoir location. Later, multiple wells may be drilled. Drilling an exploratory well or a wildcat requires the selection of the necessary facilities, such as the drilling rig and the drilling facilities and components. Well logging and coring are two of the many measurements and assessments made during the drilling of an exploratory well. The following is a description of these assessments: Well logging: As part of well logging, physical, chemical, electrical, and other properties of the rocks are measured, including their type, porosity, permeability, resistivity, acoustic travel, and density, as well as flow rate and density of the fluid in the well-bore. Essentially, well logging, or borehole logging, consists of making a detailed record (a well log) of the geologic formations penetrated by a borehole. Geophysical logs are based on measurements made with instruments lowered into the hole or visual examinations of samples brought to the surface (geological logs).   In the oil and gas industry, however, well logging means different things to different people. In geology, it is primarily a mapping technique for exploring the rocks located underground in the earth. Petrophysics uses this method to determine whether a reservoir is capable of producing hydrocarbons. Geophysicists use it as a complementary source of data for surface seismic analysis. In the case of a reservoir engineer, it may simply provide simulation values. A wireline geophysical well log, also shortened to well log or log, is the most appropriate name for this continuous depth record. It has often been called an “electrical log” due to the fact that historically the first logs were electrical measurements of electrical properties. It should be noted, however, that the measurements are no longer merely electrical, and modern data transmission methods do not need a wireline in order to transmit data, so the previous name is appropriate.   Geophysical logs are produced by continuously recording geophysical parameters along a borehole. Throughout the well, the value of the measurement is plotted against depth, as illustrated in Figure 1.9. Resistivity logs, for example, provide a continuous representation of the formation’s resistivity over many thousands of meters from the bottom to the top of the well. As a result of well logs, it is possible to answer some key questions, such as: Is there any hydrocarbon in the well, and if so, is it oil or gas? What are the locations of the hydrocarbons? What is the amount of hydrocarbon contained in the formation? What is the production capacity of hydrocarbons? Well coring: The purpose of well coring is to remove a small amount of rock from inside an oil well. The procedure involves drilling and removing a cylindrical sample of rock with the help of a drilling bit.

An Introduction to the Oil and Gas Industry

FIGURE 1.9  A well log. (Courtesy: Shutterstock)

A cross-section of a bore hole is illustrated in Figure 1.10, where the drill bit and string are located inside the well, and mud and cuttings from the drill are flowing into and out of it. A coring drill bit is designed with a central opening (hollow) that allows the sample to be removed from the material being drilled. Drilling is similar to coring, but rather than using a small drill bit, a large, round cutting tool is used. The hole created by coring is larger than the hole created by drilling. The only method that provides high-quality real samples for measuring the properties of rock and reservoirs is coring. Well testing: At various stages of drilling, completion, and production, oil and gas wells are tested. At each stage, test objectives range from identifying produced fluids and determining reservoir deliverability to characterizing complex reservoir characteristics. A well test can be classified as either a productivity test or a descriptive/reservoir test. Well testing has progressed from its modest origins as a rudimentary productivity test to one of the most powerful tools for determining complex reservoir characteristics. It is important to perform productivity well tests to identify the produced fluid as well as its volume, measure the reserve pressure and temperature, obtain fluid samples for behavior analysis, evaluate well deliverability, characterize possible well damage, and evaluate the effectiveness of workovers and well replacements.

13

14

Equipment and Components in the Oil and Gas Industry

FIGURE 1.10  A cross-section of a well that has been drilled with a drilling bit for coring purposes. (Courtesy: Shutterstock)

1.4 DRILLING Upon determining that the reservoir characteristics are sufficient to allow production to commence, the development stage begins. Future production wells will be drilled, along with all the related equipment required for production, as part of this process. The purpose of drilling is to establish a link between the surface and the target formation by drilling into geological strata as deep as 10 kilometers. Nowadays, rotary drilling is used in almost all oil and gas wells. Rotary drilling involves rotating a length of steel pipe (the drill pipe) with a drill bit attached to the end to drill a hole known as the well bore. As the well is drilled deeper, additional sections of drill pipe are added to the rotating drill string. In rotary drilling, the drill pipe is supported by a steel tower. A detailed description of drilling

An Introduction to the Oil and Gas Industry

15

components and facilities can be found in Chapter 2. Figure 1.11 illustrates an oil and gas drilling rig with some of its components and facilities, including drill pipes. Offshore drilling rigs are possible due to the fact that much of the world’s oil and gas reserves lie beneath the sea, and the hydrocarbon industry has developed techniques that are suited to the conditions of the offshore environment both for the discovery and production of hydrocarbons. The techniques and equipment used for drilling offshore wells (offshore drilling) are very similar to those used for onshore drilling, but they must be adapted for marine environment conditions by adding heliports, living quarters, cranes, and risers. An offshore rig is equipped with a heliport, which is also known as a helipad. Since helicopters are often the primary means of transportation, this is an important feature. The purpose of cranes is to move equipment and materials from boats to the rig and to move loads around on the rig. The drilling riser is a steel pipe that connects an offshore well to a drilling unit. There are several different types of offshore drilling platforms, including fixed platforms, jack-up rigs, barge rigs, floaters, submersibles, drill ship, and semisubmersibles. Platforms are supported by jackets (steel tubular frameworks anchored to the ocean bottom) containing surface production equipment, living quarters, and drilling rigs. Jackups are similar to platforms except that the support legs are not permanently attached to the seafloor. Floaters are offshore rigs that are not attached to or resting on the ocean bottom. Barges (long flat-bottomed boats)

FIGURE 1.11  An oil and gas drilling rig. (Courtesy: Shutterstock)

16

Equipment and Components in the Oil and Gas Industry

FIGURE 1.12  Offshore drilling rigs.

or drilling barges are designed to operate in shallow waters, less than 20 feet, to be precise. These are floating platforms that are towed by tugboats from one location to another. A  submersible is essentially a barge that can operate in waters deeper than 20 feet but less than 50–70 feet. Semisubmersibles (also called semis) are usually anchored in place. There are two main types of offshore drilling rigs: bottom supported and floating rigs. Bottom-supported rigs include barges, submersibles, platforms, and jack-ups, whereas floating rigs include semisubmersibles and drilling vessels. A  variety of offshore drilling rigs are shown in Figure 1.12.

1.5 WELL COMPLETION Well completion refers to the process of converting a drilled well into a production or injection well. In this process, casing, cementing, perforating, gravel packing, and the installation of production trees, also known as Christmas trees, are carried out. A well’s completion is an important stage because it contributes to the long-term durability of the well. Casing the wellbore is the first step in the completion process. After an oil well has been drilled, a well casing surrounds the well completely and is installed. A casing consists of a hollow steel pipe that lines the interior of a wellbore. The casings are used to support the well, as the sides of the well would collapse if they were not supported. As well as providing support, the casing isolates the contents of the well from the surrounding rock and soil. In this way, loss of product can be prevented and the soil and groundwater around the plant can be protected from contamination. Casings for wells are constructed in multiple sections. The casing string does not extend to the top of the wellbore but is anchored or suspended from the bottom of the previous casing string. As far as the casing joints themselves are concerned, there is no difference. Liners are casing strings in which the top

An Introduction to the Oil and Gas Industry

17

does not extend to the surface but rather is suspended from within the previous string. Cementing is the second step in the completion of a well after casing. The cementing procedure involves pumping cement slurry into the well to replace the existing drilling fluid and fill the space between the casing and the side of the well. The cement contains additives and hardens over time, sealing the well from non-hydrocarbons as well as permanently positioning the casing in place. The third step in the completion process is perforation. In the context of oil wells, a perforation is a hole punched in the casing of the well in order to connect it to the reservoir. Oil and gas can be easily pumped to the wellbore by creating a channel between the pay zone (reservoir) and the wellbore. During the perforation stage of completion, perforating guns will be run down via a wireline in many cases to the desired depth and fired in order to puncture the casing or liner. Many dozens of explosive charges may be carried by a typical perforating gun. Among the other important completion activities is fracturing. The process of hydraulic fracturing (also known as hydrofracturing or hydrofracking) involves the use of a pressurized liquid to fracture bedrock formations. The process involves the injection of high-pressure “fracking fluid” (primarily water, containing sand or other proppants suspended with the aid of thickening agents) into a wellbore in order to generate cracks in the deep rock formations that will facilitate the flow of natural gas, petroleum, and brine. Fracturing is a method of stimulating a well. Oil and gas well stimulation refers to the process of increasing production by improving the flow of hydrocarbons from the reservoir into the well bore. Well intervention, or well work, refers to any operation performed on an oil or gas well during or after its productive life that alters the well or its geometry, provides well diagnostics, or manages its production. The next stage is to install the tubing. Completion tubing, also called tubing string, is used to transport hydrocarbons safely and economically to the surface or to inject fluids into reservoirs. Tubing string selection, design, and installation are critical aspects of well completion.  The tubing is connected to tubing hanger installed on the surface to support the hanger. Oil and gas wells require a variety of equipment in order to ensure efficient and safe production. The packer is an important piece of equipment. In the completion process of an oil or gas well, production packers play an integral role. The packer seals the tubing to the casing annulus and forces fluid produced from the wellbore into the completion tubing. Packers can be permanent or retrievable. The other important well completion component is sliding sleeve that is assembled to the tubing and forms a part of tubing that is used to provide a flow path between the tubing string and casing annulus. (Refer to Figure 1.13 for a list of some of the key components involved in well completion and production.) In order to control the flow of fluids through the well, a wellhead is attached to the top of the well after it has been completed. An oil well should be closed using a piping, fitting, and valve assembly known as a Christmas tree (see Figure 1.14) so that reservoir fluid can be collected from the wellhead and directed to production facilities.

18

Equipment and Components in the Oil and Gas Industry

FIGURE 1.13  Some of main components for well completion. (Photo by author)

FIGURE 1.14  A wellhead including a Christmas tree. (Courtesy: Shutterstock)

An Introduction to the Oil and Gas Industry

19

1.6 PRODUCTION The process of producing oil and natural gas involves extracting oil and natural gas from wells and converting them into petroleum products for consumer consumption. An oil and gas production process involves a variety of systematic steps, beginning with the exploration of the site, to the actual extraction of the product, and even to the distribution of the product to businesses and the general public. During the primary oil extraction stage, reservoir drive is provided by a variety of natural mechanisms. Among them are the following: natural water displaces oil downward into the well, expansion of associated petroleum gas at the top of the reservoir, and expansion of associated gas originally dissolved in the crude oil. Oil (along with some associated gas) is forced to the surface by underground pressure within the oil reservoir, but it is only necessary to connect the well processing and storage facilities with piping or pipe systems by placing a complex arrangement of valves (the Christmas tree) on the well head. A well’s pressure decreases over the course of its lifetime. There comes a point when the underground pressure is insufficient to force the oil to the surface. In the event that natural reservoir drive diminishes, secondary recovery methods are used. Typically, external energy is supplied to the reservoir by injecting fluids in order to increase reservoir pressure, thus increasing or replacing the natural reservoir drive. Through water injection, gas reinjection, and gas lift, secondary recovery techniques increase the pressure of the reservoir. Both gas reinjection and lift use associated gas, carbon dioxide, or another inert gas to increase the pressure and reduce the density of the oil–gas mixture and thus improve its mobility.

1.7 PROCESSING Pressure is reduced when reservoir fluids (gas, oil, and water) are brought to the surface for separation and treatment. An oil production process involves separating key components from production fluids and preparing them for export. The fluids used in oil well production are typically a mixture of oil, gas, and produced water. Equipment located between oil wells and pipelines or other transportation systems constitutes oil processing facilities. As soon as the oil or gas reaches the wellhead, it is directed into a flowline (a piping or pipeline) for separation. Depending on the number of wellheads, separation may occur at each well or at a central processing facility. It is common for oil wells to produce both natural gas and water in addition to oil. Dehydration and gas sweetening are two main methods for gas treatment. A hydrate may form during the flow of natural gas and water vapor through piping or pipeline systems. There are several ways to prevent this from occurring, including installing heaters on the flowlines or adding chemicals such as glycol or methanol to the produced fluids to prevent the formation of hydrates. When

20

Equipment and Components in the Oil and Gas Industry

natural gas is produced at a well, it is usually required to be processed before being sold. In the field, a variety of processes are available for removing impurities such as carbon dioxide and hydrogen sulfide from gases. Components such as N Q carbon dioxide, hydrogen sulfide N s = , and other sulfur compounds, such 3 H 4 as mercaptans, may need to be removed entirely or partially before gas purchasers will purchase them. The compounds carbon dioxide and hydrogen sulfide are both corrosive, and hydrogen sulfide is also extremely toxic. In addition to having a very unpleasant odor, mercaptans are highly corrosive. The treatment of water is another essential process. In most cases, the water is found beneath the oil and is often referred to as either “connate” or “formation” water. During the formation of a rock, connate water is trapped in it, and its composition may change over the course of its existence. Formation water is water that has been formed in situ and becomes trapped with hydrocarbons beneath the impermeable cap rock. Oil, gas, and water are produced simultaneously as a result of the bringing into production of an oil well. Most often, the first stage in the separation of the oil from the other constituents is a horizontal three-phase separator (see Figure 1.15), which is designed to maximize the residence times of the oil and the water for more effective separation. It is important

FIGURE 1.15  A three-phase separator that separates oil, water, and gas. (Courtesy: Shutterstock)

An Introduction to the Oil and Gas Industry

21

to note that the water leaving the separation train is in no way “clean”. In addition to small droplets of residual oil dispersed in the water, it may also contain some solids. Additionally, the water may contain small amounts of dissolved hydrocarbons and gases, including (corrosive) carbon dioxide and lighter hydrocarbons, as well as any water-soluble chemicals used to enhance the hydrocarbon production process. As a matter of fact, the main question is why the water must be treated when no one purchases water, unlike oil and gas. First, the water is most often discharged into the environment—to the sea when produced offshore or to local river courses when produced onshore. Furthermore, some hydrocarbons are present in the water that can be recovered and returned to the main production system.

1.8 HYDROCARBON STORAGE A storage tank for oil is a container or reservoir that temporarily holds oil during the various stages of processing into other oil products or before it is used or consumed. In accordance with the location of the tank, oil storage tanks may be classified as surface storage tanks, aboveground tanks, or underground tanks. Various types, materials, shapes, and sizes of oil storage tanks are used in the oil and gas industry. There may be special applications that require rectangular, cylindrical, or even spherical tanks. Figure 1.16 shows cylinder-shaped storage tanks used for storing oil and gas in a plant.

FIGURE 1.16  Storage tanks. (Courtesy: Shutterstock)

22

Equipment and Components in the Oil and Gas Industry

1.9 OIL AND GAS METERING Oil and natural gas will be separated before custody is transferred. It is necessary to remove entrained solids, water vapor, and other impurities from crude oil before it can be quantified and sold. In a similar manner, water vapor, sulfur, and other contaminants are extracted from natural gas. Once the oil and gas have been cleaned, they must meet certain specifications regarding the level of impurities such as sediments, corrosive compounds, and the amount of water before they can be sold. In the oil and gas industry, oil and gas metering or measurement is the process of quantifying the mass or volume of hydrocarbons that will be sold to a buyer in the supply chain. Generally, oil and gas metering begins at the wellsite in the United States, in accordance with statutory requirements. Crude oil is an unrefined mixture of hydrocarbon fluids obtained from oil wells. In most cases, this liquid is sold as a consumer product. In this case, the unit of sale is the barrel of crude (BBL), which is the equivalent of 42 US gallons. It is possible to measure the volume or mass of crude oil when it is stored in the storage tank or by using a mass or volume flow meter when it flows through the pipeline. A natural gas unit of sale consists of thousands of cubic feet (MCF) or British Thermal Units (MMBTU). The volume of gas can be measured by a flow meter.

1.10 HYDROCARBON TRANSPORTATION Transporting produced hydrocarbons to refineries can be accomplished in a variety of ways. Barges, tankers, pipelines, trucks, and railroads are used to transport crude oil from the wellhead to the refinery. LNG tankers transport liquefied natural gas (LNG), while pipelines transport natural gas and crude oil. LNGs are types of liquefied gases, which means that they are natural gas components that are separated as liquids. Specifically, LNG is a natural gas condensed into liquid form after it has been treated to remove valuable elements such as helium, as well as impurities such as carbon dioxide and hydrogen sulfide. Since at least a portion of the oil travels through pipelines for much of its journey, pipelines (see Figure 1.17) play a critical role in the transportation process. Pipelines transport crude oil to another carrier or directly to a refinery after it has been separated from natural gas. Planning for the construction of pipelines involves determining the shortest and most economical routes. Oil pipelines are usually composed of steel or plastic materials buried underground. Pump stations along the pipelines transport the oil through the pipelines. Several reasons have made pipelines the preferred mode of transportation for liquids and gases over competing modes such as trucking and rail: they are less environmentally harmful; less susceptible to theft; and more economical, safe, convenient, and reliable than competing modes. Rivers and canals are the primary areas in which barges are used. Compared to pipelines, they require less infrastructure, but they are more expensive, transport much less volume, and take longer to load. Over the course of history, pipelines have been constructed in various parts of the world to convey drinking water and irrigation water.

An Introduction to the Oil and Gas Industry

23

FIGURE 1.17  Oil pipeline. (Courtesy: Shutterstock)

1.11 REFINERIES In an oil refinery or petroleum refinery, crude oil (petrol) is transformed into valuable products such as gasoline (petrol), diesel fuel, asphalt base, fuel oils, heating oil, kerosene, liquefied petroleum gas, and petroleum naphtha. It is common for oil refineries to be large, complex industrial units, as illustrated in Figure  1.18, that are complemented by extensive piping throughout, which carries streams of fluids between large units of chemical processing, such as distillation columns. All refineries have three basic steps of separation, conversion, and treatment. The modern method of separation involves the piping of crude oil through hot furnaces. As a result, liquids and vapors are discharged into distillation units for further processing. According to their boiling points, the liquids and vapors inside the distillation units are separated into petroleum components, known as fractions. The heavy fractions are located at the bottom of the column, and the light fractions are located at the top. As part of the conversion process after distillation, heavy, lower-value distillation fractions may be converted into lighter, higher-value products such as gasoline. During this stage of the process, fractions from the distillation units are converted into streams (intermediate components), which are ultimately transformed into finished products. As the most widely used method of converting heavy hydrocarbon molecules into lighter ones, cracking uses heat, pressure, catalysts, and sometimes hydrogen. Crude oil is converted in a variety of ways other than through cracking. As an alternative to splitting molecules, other

24

Equipment and Components in the Oil and Gas Industry

FIGURE 1.18  An oil and gas refinery. (Courtesy: Shutterstock)

refinery processes rearrange molecules in order to add value. To summarize, conversion process units are used to convert one hydrocarbon stream into another by changing the size and structure of the molecules. As a result, the refinery is making a shift from producing less valuable products (e.g. residual fuel oil, LPG) to producing more valuable ones (e.g. gasoline, diesel). In petroleum refining, treatment involves removing contaminants such as organic compounds containing sulfur, nitrogen, oxygen, dissolved metals and inorganic salts, and soluble salts dissolved in emulsified water from petroleum fractions. The process of treating may take place at an intermediate stage in the refining process or just before the finished product is sent to storage. A  treatment method is selected based on the nature of the petroleum fractions, the amount and type of impurities in the fractions to be treated, the extent to which the process removes impurities, and the specifications of the end product. Among the materials that are treated are acids, solvents, alkalis, oxidizing agents, and adsorption agents. The most commonly used acid treatment process is sulfuric acid. As a result of sulfuric acid treatment, unsaturated hydrocarbons, sulfur, nitrogen, and oxygen compounds as well as resinous and asphaltic compounds are partially or completely removed. On a tank farm near the refinery, both crude oil and final products are temporarily stored in large tanks. In order to transport the final products from the storage tanks to various locations throughout the country, pipelines, trains, and trucks are used.

An Introduction to the Oil and Gas Industry

25

QUESTIONS AND ANSWERS 1. Which oil and gas facility is part of the midstream sector? A. Storage tanks B. Pipelines C. Floating production storage and offloading (FPSO) D. Both options A and B are correct

Answer) Option D is the correct answer.

2. Identify the correct statement regarding the oil and gas industry. A. The product produced from a gas well has a lower GOR than that produced from an oil well. B. As a result of natural gas production, oil is a byproduct. C. The color of crude oil is not necessarily black or brown. D. The oil and gas industry is a small and simple energy sector.

Answer) There is an error in Option A because a gas well produces a product with a higher gas-to-oil ratio. Option B is not correct either, since natural gas is a byproduct of oil. The correct answer is option C. The color of crude oil is usually black or dark brown, but it can also appear yellowish, reddish, tan, or green. In view of the fact that the oil and gas industry is quite large and not a simple energy sector, Option D is incorrect.

3. In Table 1.1, petroleum geology terms are listed on the left and their definitions are listed on the right in the incorrect order. Match the right term with its definition.

Answer) A:5, B:4, C:3, D:1, E:2, F:6

TABLE 1.1 Some Geological Terms and Definitions Geology Terms A. Hydrocarbons B. Source rock C. Reservoir D. Migration E. Porosity F. Trap

Geology Definitions 1. The movement of oil from the source rock to the reservoir rock 2. Volume of voids or open spaces within the rock as a percentage of the total volume 3. Porous and permeable rocks containing commercial hydrocarbon deposits 4. A mature rock that is capable of producing hydrocarbons 5. Among other elements, hydrogen and carbon constitute these substances 6. An underground geological structure that allows hydrocarbons to accumulate in a reservoir

26

Equipment and Components in the Oil and Gas Industry

4. In oil and gas exploration and production, ________ refers to exploratory drilling that seeks to exploit unproven or high-risk areas. A. Well logging B. Wildcat drilling C. Blast hole drilling D. Seismic survey

Answer) Option B is the correct answer.



5. When compared with the other activities, which of the following exploration stages occurs last? A. Exploration and mapping of surface and subsurface geologic features with techniques such as seismic reflection in order to identify areas where oil and gas may have accumulated. B. Conducting well logging and coring to determine the permeability, porosity, and other properties of the geologic formation(s) encountered. C. Identifying geologic formations that may contain commercial quantities of oil and/or gas that can be economically produced. D. For the purpose of determining the presence of hydrocarbons and determining the area and thickness of the oil- and/or gas-bearing reservoir or reservoirs, exploration wells are drilled.

Answer) Option B is the correct answer.

6. Identify the correct statement regarding geophysical surveys to find oil and gas reserves. A. Occasionally, if oil seeps into the surface, it may indicate that petroleum exists beneath the surface. In terms of finding oil, this is considered the simplest geophysical technique. B. Magnetic surveys are less complicated than gravity surveys. C. Seismic surveys can only be performed offshore. D. In electromagnetic surveys, the electromagnetic field measured by the receivers is affected by the subsurface resistivity distribution. EM signals can propagate with little attenuation if a resistive layer exists, such as a hydrocarbon reservoir.



Answer) Option A is incorrect because oil observation at the surface caused by oil seepage cannot be considered a geophysical technique. Option B is also incorrect, since magnetic surveys are more complex than gravity surveys. It is incorrect to choose option C, as seismic surveys can be conducted both onshore and offshore. The correct answer is option D.

7. In regard to the components used in the completion of wells, which statement is correct? A. The first step in the well completion process is the application of cement to secure the casing. B. Well stimulation is a method to fracture the reservoir.

An Introduction to the Oil and Gas Industry



27

C. The packer seals the tubing to the inner wall of the well and forces fluid produced from the wellbore into the casing. D. All three choices are incorrect. Answer) Option A is incorrect because casing is the first step in well completion, and then cement is injected into the well. The correct option is B. Option C is incorrect since the packer seals the tubing to the casing and allows the produced fluid and gas to flow into the tubing. Because option B is the correct option, option D is incorrect.

8. The formation of hydrate is common in which phase? A. Gas B. Water C. Oil D. Gas and water

Answer) Option A is the correct answer.



9. In which of the following processes does the reservoir not become more productive? A. Gas lifting B. Water injection C. Gas injection D. Separation

Answer) Option D is the correct answer. A separation process is used to separate water, gas, and oil during the oil and gas production process, but it does not increase the productivity of the reservoirs.

10. In the production of oil and gas, why is water treatment necessary? A. Preventing pollution of the environment caused by the discharge of water B. Removing any remaining hydrocarbons and chemicals C. Increasing the value of water for the purpose of selling D. Options A and B are both correct.

Answer) Option D is the correct answer.

FURTHER READING 1. Ahmed, T., Makwashi, N., & Hameed, M. (2017). A review of gravity three-phase separators. Journal of Emerging Trends in Engineering and Applied Sciences, 8(3). 2. Chu, Z., Feng, Y., & Seeger, S. (2015). Oil/water separation with selective superantiwetting/superwetting surface materials. Angewandte Chemie International Edition, 54(8), 2328–2338. 3. Emam, E. A. (2015). Gas flaring in industry: An overview. Petroleum & Coal, 57(5), 532–555. 4. Gadirov, V., Kalkan, E., Ozdemir, A., Palabiyik, Y., & Gadirov, K. (2022). Use of gravity and magnetic methods in oil and gas exploration: Case studies from Azerbaijan. International Journal of Earth Sciences Knowledge and Applications, 4(2), 143–156.

28

Equipment and Components in the Oil and Gas Industry

5. Inkpen, A. C. (2011). The global oil & gas industry: Management, strategy & finance. Oklahoma, Tulsa: PennWell. ISBN: 9781593702397 6. Liu, H. (2017). Principles and applications of well logging (pp. 237–269). Berlin, Heidelberg: Springer. ISBN: 978-3-662-53383-3 7. Magoon, L. B. (2004). Petroleum system: Nature’s distribution system for oil and gas. Encyclopedia of Energy, 4, 823–836. 8. Robinson, D. (2010). Oil and gas: Water treatment in oil and gas production—Does it matter? Filtration & Separation, 47(1), 14–18. 9. Speight, J. G. (2014). The chemistry and technology of petroleum. 5th ed. Boca Raton, FL: CRC Press, Taylor & Francis Group. ISBN: 9781439873892 10. Speight, J. G. (2020). The refinery of the future. 2nd ed. Oxford: Gulf Professional Publishing. Paperback ISBN: 9780128169940 11. Sotoodeh, K. (2023). Safety engineering in the oil and gas industry. 1st ed. Boca Raton, FL: CRC Press (Taylor and Francis). ISBN: 9781032479736

2

Drilling and Well Completion Equipment

2.1 INTRODUCTION During drilling, a hole is made into a hard surface, in which the length of the hole is much greater than the diameter of the hole. Almost all oil and gas wells are drilled using rotary drilling today. During rotary drilling, a steel pipe (the drill pipe) with a drill bit is rotated to create the well bore. Additional sections of drill pipe are added to the rotating drill string as the well is drilled deeper. A drilling fluid circulates continuously in the annular space between the drill pipe and the bore hole in order to lift the cuttings from the hole. At the surface, the returning mud passes through a series of devices that separate the cuttings according to their size. Finally, drilling fluid is sucked from the mud tanks by mud pumps and injected into the well again. A well is drilled in this manner by repeating the cycle. Drilling rigs consist of an integrated system that drills wells into the earth’s subsurface, such as oil wells, water wells, or holes for piling and other construction activities. A drilling rig can be a massive structure that houses equipment used to drill water wells, oil wells, or natural gas extraction wells. As discussed in more detail in Chapter 1, drilling rigs can be onshore or offshore. Figure 2.1 shows an offshore oil rig drilling platform. In addition to identifying geologic reservoirs, oil and natural gas drilling rigs are used to drill holes that enable oil and natural gas to be extracted. In onshore oil and gas fields, once a well has been drilled, the drilling rig is removed from the well, and a service rig (a smaller rig), which is designed specifically for completions, is moved on to the well. The process of converting a drilled well into a producing well is known as well completion. The steps involved in the construction of a production tree include casing, cementing, perforating, packing gravel, and installing a production tree. Casing the hole is the first step in the completion of a well.

2.2 ROTARY DRILLING SUBSYSTEMS As part of the rotary drilling operation, six subsystems are involved, the power system, hoisting system, rotating system, circulating system, controlling system, and monitoring system. Following is a description of these subsystems: Power system: A drilling rig’s power system is responsible for powering other main systems on the rig, as well as auxiliary systems, such as electrical systems, pumps, and so on. There are typically two components in a power system: a prime mover (the component which generates DOI: 10.1201/9781003467151-2

29

30

Equipment and Components in the Oil and Gas Industry

FIGURE 2.1  An offshore oil rig drilling platform. (Courtesy: Shutterstock)

the raw power) and a means of transmitting the raw power to the enduse components. A power system consists of fuel storage, engines, and generators. In most rigs, the prime movers are diesel engines that provide power to the rig and are located on the ground at the rear of the machine. Tanks are located near the engines for the storage of diesel fuel. There is a significant amount of power consumed by the hoisting and circulation systems. Additionally, some power is used for the rotating system, rig lights, and other motors. The number of engines depends on the size of the rig and the depth of drilling. Engines are rated according to their horsepower and fuel consumption. In the past, drilling rigs have been powered by coal. Nevertheless, diesel oil is a very common source of fuel for modern drilling rigs. A system of pulleys, belts, shafts, gears, and chains transmits the power from the diesel engines to the rig mechanically. There are some rotary rigs that use electricity directly from power lines. Hoisting system: A hoisting system consists of tools that are used to lift, lower, and suspend equipment in a well. Among the major components of a hoisting system are the crown block, mast or derrick, monkey board, travelling block, hook, swivel, drawworks, weight indicator, and drilling line. Detailed explanations of these items are provided in the next section of this chapter.

Drilling and Well Completion Equipment

31

Rotating or rotary system: On a drilling rig, the rotary system is responsible for rotating the drill bit at the bottom of the wellbore. The rotary system includes a swivel, kelly, kelly bushing, master bushing, rotary table, mouse hole, rat hole, rotary hose, drilling string, bottom hole assembly, and drill bit. In the next section, we will discuss all of these items in more detail. Controlling system: A controlling system may also be referred to as a well control system or a blowout prevention system. Well control systems, or blowout prevention systems, on drilling rigs prevent the uncontrolled and catastrophic release of high-pressure fluids (oil, gas, or salt water) from subsurface formations. The uncontrolled release of formation fluids is referred to as a blowout. In modern wells, blowout preventers are installed in order to prevent such an occurrence. An accidental spark during a blowout can result in a catastrophic oil or gas fire. An accumulator and a blowout preventer are included in the control system. Monitoring system: It is essential to closely control a number of parameters in order to conduct an optimal drilling operation. A modern rig will have devices which display and simultaneously record most of the important parameters related to the drilling operation. The most important parameters include well depth, bit weight, drilling torque and speed, penetration rate, and mud properties. As the driller monitors these important parameters and combines them with reliable historical records of previous similar operations, he or she will be able to predict and detect possible drilling problems. In order to maintain well control, it is important to monitor the mud system.

2.3 MAIN COMPONENTS AND EQUIPMENT FOR ROTARY DRILLING As shown in Figure 2.2, all of the main components and equipment used in rotary drilling are numbered. The crown block is item number 1. Crown blocks are fixed sets of sheaves (pulleys) at the top of a derrick over which drilling lines are run. The crown block is an assembly of sheaves mounted on beams at the top of a derrick or mast. The crown block is a stationary pulley located at the top of the derrick. A crown block is a fixed set of sheaves at the top of a derrick, over which the drilling line is run. It is necessary to erect a drilling mast or derrick (item number 7) over the well. Over an oil well, drilling masts provide support for drilling equipment and allow it to be lifted into and out of the wellbore. The derrick or mast structure supports the crown block and drill string. In item number 2, the hoist line is a structural framework that is installed near the top of a derrick for the purpose of lifting materials. Item number 3 consists of a drilling line, a wire rope hoisting line that is secured on the sheaves of the crown block and traveling block. The primary purpose of this device is to hoist or lower drill pipe or casing from or into a well. The drilling tools are also supported by a wire rope. Item number 4 is a monkeyboard, which is used by the derrickman to stand on when

32

Equipment and Components in the Oil and Gas Industry

FIGURE 2.2  Main component and equipment for rotary drilling.

Drilling and Well Completion Equipment

33

handling the drillpipes. An arrangement of pulleys or sheaves, item 5, the travelling block is used to guide drilling cable so that the cable can travel up and down in the derrick or mast as needed. In order to rotate the drill string and bit, the top drive, item number 6, is installed under the traveling block. It can be controlled from the control room on the rig floor. The traveling block and top drive are shown in Figure 2.3. Item 7, which is the mast or derrick, was explained before. Item 8 refers to a drill pipe, which is a hollow, thin-walled steel or aluminum alloy pipe used in drilling rigs. It is hollow in order to allow drilling fluid to be pumped down the hole and back up the annulus. There are a wide range of sizes, strengths, and wall thicknesses available. Item number 9 consists of an oil well dog house, a steel-sided room adjacent to an oil rig floor with an access door at the driller’s control. The driller and his crew can use this general-purpose shelter as a tool shed, an office, a communications center, a coffee lounge, a lunchroom, and a general meeting place. In general, it is located at the same elevation as the rig floor, and it is usually attached to the main substructure holding the rig up. In order to prevent

FIGURE 2.3  A combination of traveling block and top drive.

34

Equipment and Components in the Oil and Gas Industry

the uncontrolled release of crude oil or natural gas from a well, item number 10 is a blowout preventer, a specialized valve or similar mechanical device. This device is used to seal, control, and monitor oil and gas wells in order to prevent blowouts, the uncontrolled release of oil or natural gas from them. It is common to install them in the company of other valves. Item number 11 is a water tank that stores the water for various purposes, including cleaning the drill rig, mixing the mud, and cementing. Item 12 is an electric cable tray, which supports the heavy electrical cables that deliver power from the control panel to the motors of the rig. In item number 13, a gas or diesel engine generator generates mechanical energy and power for the drilling rig using gas or diesel as fuel. Item number 14 is a fuel tank, which stores the fuel or source of energy for the power generation system (engine generators). In item 15, there is an electrical control house, which is used to monitor and control the drilling rig. Powerful diesel engines drive large electric generators on diesel electric rigs. Electricity is generated by the generators and is transmitted via cables to electrical switches and control equipment enclosed in a control cabinet or panel. Mud pumps, item number 16, are large pumps used on drilling rigs to circulate mud (drilling fluid). Item number 17 includes bulk mud component storage tanks, which are hopper-type tanks used to store drilling fluid components. Item number 18 is a mud pit that consists of a series of open tanks, usually made of steel plates, through which drilling mud is cycled in order to settle out sand and sediments. It is in the pit that additives are mixed with the mud, and the mud is temporarily stored there before being pumped back into the well. Depending on their primary purpose, mud pits may also be referred to as shaker pits, settling pits, or suction pits. There are extra or reserve pits included in item number 19. One of these is an additional mud pit in which drilling mud is stored in order to supply for drilling operations. The mud gas separator, item number 20, separates the gas from the mud coming from the well. A shale shaker, item number 21, consists of trays with sieves or screens that vibrate in order to remove cuttings from the circulation of fluid in rotary drilling operations. Item number 22 is called a choke manifold, which contains pipes and special valves, called chokes, through which drilling mud is circulated when blowout preventers are closed to control well pressures encountered during kicks. In item number 23, you will find a pipe ramp, which is an angled ramp that is used for dragging the drill pipe to the drilling platform and for removing the drill pipe from the drilling platform. A pipe rack (item number 24) is a horizontal support for tubular products to be kept and stored. Item number 25 is an accumulator that is used to store nitrogen-pressurized hydraulic fluid for operation of the blowout preventers. In this chapter, there is more information about blowout preventers and accumulators.

2.4 A DETAILED DESCRIPTION OF SOME OF THE MAIN COMPONENTS OF DRILLING The following are additional drilling items that are not illustrated in the figure: Drawwork: It consists of a steel spool with a large diameter, brakes, a power source, and various auxiliary devices (see Figure  2.4). It is primarily

Drilling and Well Completion Equipment

FIGURE 2.4  A drawwork.

drawing works that are used in order to reel out and reel in drilling lines, large diameter wire ropes, in a controlled manner. Essentially, it is the hoisting mechanism on a drilling rig. It consists of a massive mechanical device that spools out or receives the drilling line so that the drill stem and bit can be raised or lowered. Hook: This high-capacity J-shaped equipment (see Figure 2.5) is used to hang a variety of equipment, including swivels and kellys, elevator bails, and top drives. The hook is attached to the bottom of the traveling block and provides a means of lifting heavy loads. Hooks are either locked (the normal condition) or free to rotate so that they may be mated or decoupled with items positioned around the rig floor, not limited to one direction. Elevator: A set of clamps (see Figure 2.6) that grip a stand, or column, of casing, tubing, or drill pipe so the stand can be raised or lowered into the hole. The elevator is connected to the hook through links. Kelly: A long square or hexagonal steel bar (see Figure 2.7) with a hole drilled through it for the passage of fluids. As the drillstring rotates, the kelly transmits rotary motion from the rotary table to the kelly bushing and allows for the drillstring to be lowered or raised during rotation. The kelly passes through the kelly bushing, which is driven by the rotary table. As the kelly bushing has an inside profile that matches the kelly’s outside profile (either square or hexagonal), it has slightly larger dimensions to allow the kelly to move freely within the bushing.

35

36

Equipment and Components in the Oil and Gas Industry

FIGURE 2.5  Drilling hook.

FIGURE 2.6 Elevators.

Drilling and Well Completion Equipment

FIGURE 2.7 Kelly.

Kelly bushing: A  device attached to the rotary table through which the Kelly passes (see Figure 2.8a and b). It is responsible for transmitting the torque generated by the rotary table to the kelly and drill stem. It is also known as the drive bushing. Rotary table: The rotating or spinning section of the drillfloor (see Figure  2.9) that provides power for rotating the drillstring clockwise. Through the kelly bushing and kelly, rotary motion and power are transmitted to the drillstring. Most drilling rigs today have rotary tables.

37

38

Equipment and Components in the Oil and Gas Industry

FIGURE 2.8  (a) Kelly bushing in a (b) drilling rig.

Drilling and Well Completion Equipment (a)

(b)

FIGURE 2.9  (a) Rotary table in a drilling rig (photo by author). (b) A rotary table.

39

40

Equipment and Components in the Oil and Gas Industry

Swivel: A  mechanical device that suspends the drillstring’s weight, ­permits rotation of the drillstring beneath it while keeping its upper portion stationary, and allows high-pressure drilling mud to flow from the fixed portion to the rotating portion without leaking. Figure 2.10 illustrates the swivel and other components involved in the rotary ­d rilling system.

FIGURE 2.10  A rotary system of drilling, including swivel.

Drilling and Well Completion Equipment

Mousehole: Boreholes under the rig floor, usually lined with pipe, in which drill pipe joints are temporarily suspended for later connection to the drill string (see Figure 2.11). Desander: It consists of a hydrocyclone device that removes large drill solids from the whole mud system (see Figure 2.12). Before the desilters or mud cleaners, the desander should be located downstream of the shale shakers and degassers. Desilter: A  hydrocyclone is similar to a desander, except that its design incorporates a greater number of smaller cones (see Figure 2.13). It serves the same purpose as the desander in removing unwanted solids from the mud system. The smaller cones allow the desilter to efficiently remove drill solids of smaller diameter than a desander. Therefore, the desilter is located downstream of the desander in the surface mud system. Mud gas separator: Equipment that extracts gas from mud coming out of a well (see Figure 2.14). Shale shaker: Probably the most important device on a drilling rig for the removal of drilled solids from mud. In a drilling fluid flow, a wire-cloth screen vibrates while the fluid is flowing over it. A liquid phase of the mud and solids smaller than the wire mesh pass through the screen, whereas larger solids are retained on the screen and eventually fall off

FIGURE 2.11  A mousehole.

41

42

Equipment and Components in the Oil and Gas Industry

FIGURE 2.12 Desander.

FIGURE 2.13 Desilter.

and are discarded. Modern high-efficiency drilling rigs often have four or more shakers, as opposed to the one or two shakers that were common in the past. Shale shakers are illustrated in Figure 2.15. Flowline (mud return line): A large-diameter metal pipe that connects the bell nipple under the rotary table to the mud tanks. The flowline is a

Drilling and Well Completion Equipment

FIGURE 2.14  Mud gas separator.

FIGURE 2.15  Mud gas separator.

gravity-flow conduit that directs mud from the wellbore’s top to the surface treatment equipment. Certain highly reactive clays, called “gumbo,” can cause the flowline to become plugged and require considerable effort on the part of the rig crew to keep it open. Additionally, the flowline

43

44

Equipment and Components in the Oil and Gas Industry

FIGURE 2.16  A standpipe.

is typically equipped with a crude paddle-type flow-measuring device known as a “flow show,” which can give the driller the first indication that the well is flowing. It is important to note that the mud flow path begins at the mud storage tank and ends at the mud pump. Mud is transferred from the mud pump to the drill string via the standpipe manifold and standpipe. Following this, the mud is transferred to the drill bit, pumped up the annulus to the surface, and passed through equipment designed to remove mud contamination. Standpipe: A rigid metal conduit illustrated in Figure 2.16 that provides a high-pressure pathway for drilling mud to travel approximately one-third of the way up the derrick, where it connects to a flexible high-pressure hose. Many large rigs are fitted with dual standpipes so that downtime is kept to a minimum if one standpipe requires repair. Standpipe manifold: This system consists of a series of lines, gauges, and valves for routing mud from the pumps to the standpipe. Rotary hose or kelly hose: Hose that distributes drilling fluid from the mud pump and standpipe to the swivel and kelly on rotary drilling rigs, as illustrated in Figure 2.17; also known as the mud hose or kelly hose. Annulus: The annulus (plural annuli or annuluses) is the region between two concentric circles in mathematics. Informally, it resembles a ring. As the name implies, the annulus of an oil well or water well is the void between the piping, tubing, or casing surrounding it and the piping, tubing, casing, or wellbore immediately adjacent to it. It is named after the corresponding geometric concept, in other words, the area between two concentric objects, such as between a wellbore and casing or between casing and tubing, where fluid can flow. The pipe may be composed

Drilling and Well Completion Equipment

FIGURE 2.17  A rotary hose.

of drill collars, drill pipe, casings, or tubing. For example, the space between the production tubing and casing is called the annulus. Drill bit: Oil and gas well drilling involves the use of cutting or piercing elements. The most common type of bits used in rotary drilling are roller-cone or rolling cutter bits, illustrated in Figure  2.18. In addition to the cutting elements, the bit also consists of a circulating element. The circulating element permits the passage of drilling fluid and uses the hydraulic force of the fluid stream to improve drilling rates.

45

46

Equipment and Components in the Oil and Gas Industry

FIGURE 2.18  Rolling cutter drilling bits.

There are currently two main categories of drilling bits in the drilling industry: rolling cutter bits and fixed cutter bits. A rolling cutter bit, also known as a roller cone bit or tri-cone bit, has three cones. It is possible to rotate each cone independently when the drill string rotates the body of the bit. Cones are fitted with roller bearings during assembly. Two types of rolling cutter bits are available: milled-tooth bits and tungsten carbide insert bits (TCI or insert bits). Steel tooth cutters are fabricated into the bit cones of milled-tooth bits. Insert bits consist of tungsten carbide inserts (teeth) pressed into the bit cones as part of the bit cones.  The fixed cutter bits consist of bit bodies and cutting elements that are integrated with the bit bodies (see Figure 2.19). As opposed to rolling cutter bits, fixed cutter bits are designed to excavate holes by shearing formations rather than chipping or gouging formations. There are two types of cutters available on the market for fixed cutter bits: polycrystalline diamond cutters (PDC) and natural or synthetic diamond cutters. Drill pipe: The drill pipe (see Figure 2.20) is a steel tubing with special threaded ends, commonly referred to as tool joints. Tool joints are explained later in this chapter. In addition to connecting the surface equipment of the rig to the bottom hole assembly and the bit, the drill pipe is used to pump drilling fluid to the bit and to raise, lower, and rotate the bottom hole assembly and bit. Drill collar: Drillstring component that provides weight to the bit during drilling. Due to the large mass of the drill collars, as illustrated in Figure 2.21, gravity provides the downward force that is needed for the bits to break rock efficiently.

Drilling and Well Completion Equipment

FIGURE 2.19  Fixed cutter bits.

Tool joint: Tool joints (see Figure 2.22) are the enlarged and threaded ends of drill pipe joints. In a manufacturing facility, these components are fabricated separately from the pipe body and then welded onto the pipe. The tool joints provide high-strength, high-pressure threaded connections that are sufficiently robust to withstand the stresses of drilling and numerous cycles of tightening and loosening. A tool joint is usually composed of steel that has been heat treated in order to increase its strength over the drill pipe body. Tool joints with large diameters provide lowstress areas where pipe tongs are used to grip the pipe. Bottom hole assembly: The bottom hole assembly (BHA) is a component of a drilling rig. This component extends from the bit to the drill pipe at the lowest point of the drill string. Drill collars, subs such as stabilizers, reamers, shocks, hole-openers, and the bit sub and bit can all be included in the assembly. In order to drill and achieve a sufficient rate of penetration (ROP), the BHA design is based on the need to have sufficient weight transfer to the bit (WOB). Drill collars are components of drillstrings that provide weight to the bit for drilling, as explained earlier in this chapter. A drill collar is a thick-walled tubular piece that is manufactured from solid bars of steel, most often plain carbon steel,

47

48

Equipment and Components in the Oil and Gas Industry

FIGURE 2.20  Drill pipe.

Drilling and Well Completion Equipment

FIGURE 2.21  Drill collars.

FIGURE 2.22  Tool joints at the end of drill pipes.

49

50

Equipment and Components in the Oil and Gas Industry

but sometimes nonmagnetic nickel-copper alloys or other nonmagnetic premium alloys. Stabilizers are used within columns of drill collars. By stabilizing the BHA in the borehole, it reduces the risk of stuck pipes due to unintentional vibrations and side-tracking. Furthermore, stabilizers assist in guiding the bit into the hole. In directional drilling, they are extremely important, as they determine the path and angle of the well bore. In general, reamers work by using a radially symmetrical tool with either a straight, slightly twisted, or spiral fluted cutting surface that is ground to an extremely precise size. The purpose of these tools is to finish holes that have been drilled, end-milled, or punched, leaving them with precise dimensions. In drill collar strings, shock or shock subs are used to absorb vibrations and bit shock loads. Hole openers are used to increase the size of the well bore. Bit subs are used to connect the drill bit to the bottom hole assembly. The connections are usually made on a box-to-box basis (female to female). Blowout preventer: Blowout preventers (BOPs) are large, specialized valves or similar mechanical devices used to control, monitor, and prevent uncontrolled oil and gas well blowouts. Blowouts are caused by extreme erratic pressure and uncontrolled flow of formation into the well, known as kick flow. Kicks differ from blowouts in that kicks can be controlled, while blowouts cannot be controlled. The kick occurs in an oil well when the pressure exerted by the rock surrounding the bore is greater than the pressure within the bore. As a result, fluid rushes into the wellbore in an attempt to stabilize the pressure. It is possible to inject heavier fluids into the well through the kill line located below the BOP stack. In addition, it is possible to evacuate the lighter fluid from the well through the choke line. The blowout preventer is operated hydraulically, which means that the valves are opened and closed by pressurized hydraulic fluid supplied by accumulators. Drillers use a hydraulic control system that consists of accumulator bottles containing pressurized hydraulic fluid, a hydraulic reservoir, pumping system, and hydraulic piping to operate the rams. A control panel is responsible for controlling the flow of hydraulic fluid to the BOP stack. In most cases, valves in blowout preventors are installed redundantly in stacks. There are blowout preventers used on land wells, offshore rigs, and subsea wells. Both land-based and subsea BOPs are attached to the top of the wellbore, which is referred to as the wellhead. On offshore rigs, BOPs are mounted below the deck of the rig. The blowout preventer shuts off the valve leading underneath the machinery in order to prevent any liquid from surfacing in an explosion or kick.  In a typical deep-water blowout prevention system, components include electrical and hydraulic lines, control pods, hydraulic accumulators, test valves, kill and choke lines and valves, riser joints, hydraulic connectors, and a support frame. On top of the well, an individual BOP is installed vertically. It should be noted that the drill pipe passes through the BOP. In normal wellbore operations,

Drilling and Well Completion Equipment

51

the piston of the preventer is kept in its open position by applying hydraulic pressure. As a result of this position, drilling tools, casing, and other items up to the full bore size of the BOP can pass through. An example of a BOP is shown in Figure 2.23, which includes two annulars (annular preventors) and four rams (ram preventors). An annular preventor, also known as an annular seal, is used to create a sealed area around the drill pipe or seal off a hole without a drill pipe to prevent blowouts. By doing so, the blowout preventer is able to confine (isolate) the well fluid inside the well, which is the first important function it serves. When annular BOPs are shut in around the drill pipe, the pipe can move up and down or rotate without breaking the seal. In annular preventors, the sealing device is referred to as the packing element, which is made of elastomeric material and has a donut shape. Different shapes of metallic material are molded into the elastomeric material in order to reinforce it. The purpose of this is to prevent the elastomeric material from extruding when operating system pressure or wellbore pressure is applied to the bottom of the packing

FIGURE 2.23  An illustration of a blowout preventer.

52

Equipment and Components in the Oil and Gas Industry

element. Considering that the packing element is exposed to a variety of drilling environments (such as drilling fluid/mud, corrosive H 2 S gas, and/or drilling fluid temperature), it is essential to ensure that the appropriate packing element is installed in the annular preventer based on the anticipated drilling environment. BOPs with rams include rubber-faced steel rams that are brought together to form a seal or, like annular BOPs, form a seal around a tool within the well. A shear ram is a hydraulically operated ram that is capable of cutting drill pipe with high strength. Among them are blind shear and casing shear rams, both of which can be used to cut drill pipe or other obstructions in the well. The blind shear ram is the thick, heavy steel component of a ram blowout preventer. A blind shear ram is always fitted with hardened tool steel blades that are designed to cut the tubing or drill pipe once the BOP is closed. The wellbore is then completely sealed or isolated. Casing shear rams are designed specifically to shear and/or seal casing and may not seal the well bore. Casing shear rams are specifically designed to cut large-diameter tubulars that cannot be sheared by blind shear rams. When it is necessary to regain pressure control over a flowing well, a shear ram is usually used as a last resort. The drill pipe is usually left hanging in the BOP stack once it has been cut (or sheared) by the shear rams. Variable bore rams are designed to seal around drill pipes of varying diameters. In a BOP stack, a test ram is a ram that is installed in the lowest cavity and is designed to hold pressure from above while sealing around the drill string (used to facilitate BOP testing operations). In general, a ram in a blowout preventer is defined as a device that can be used to seal the top of a well in the event of a well control event (kick). Typically, a ram blowout preventer consists of two halves of a well cover that are split down the middle. In order to seal against high pressure and cut through drill pipe, significant force is required. Using hydraulic power from an accumulator system, blowout preventer rams are forced closed and reopened. A hydraulic accumulator is composed of a cylinder containing hydraulic fluid under high pressure. Subsea BOPs, such as the one illustrated in the figure, are typically equipped with more complex control systems, as well as larger bores and a higher pressure class than surface BOPs. The lower marine riser package (LMRP) is connected to the drilling rig by way of the riser. The riser is defined as the vertical or nearly vertical segment of pipe that connects facilities above water to the subsea. As a matter of fact, choke lines and kill lines located below the BOP are connected to the rig’s LMRP connection, which makes it possible to kill and choke the well to prevent a blowout through this connection. For reasons of safety and environmental protection, the BOP rams must be shut down rapidly, and in the case of subsea BOPs, this can be accomplished at depths of approximately 1200 meters and lower only by transmitting hydraulic fluid through an umbilical. The term “umbilical” refers to a composite hose or cable or to a number of individual hoses or cables that provide hydraulic and electrical power as well as communications in the subsea oil and gas industry. As the hydraulic system does not provide very rapid operation of BOPs installed in water deeper than 1200 meters, an electrohydraulic system is required for the greater depths.

Drilling and Well Completion Equipment

Choke manifold: A choke manifold is an important device for controlling the well kick and executing pressure control technology on oil/gas wells during drilling. As such, the device is utilized to implement a new drilling-well technique for balancing the wellbore pressure, which prevents pollution of the oil layer, increases drilling speed, and reduces blowouts. The device is connected to the side flange of the BOP spool on one end. The choke valve’s opening can be adjusted on the choke manifold in order to control the amount of pressure from the well and casing when the BOP closes so that balanced drilling can be conducted with a minimum difference in pressure between the well and formation when the BOP closes. In Figure 2.24, a choke manifold is shown. According to its name, item number 1 is a lifting base that is used to lift the manifold. Both items 2 and 14 are choke valves responsible for the pressure drop. In the event that one choke valve is removed from the line for maintenance or inspection, the second choke valve can be used as a replacement to control the flow. Items 3 and 10 are tees that are used to get a branch from the main piping header. A tee is considered a type of pipe

FIGURE 2.24  A manifold choke.

53

54

Equipment and Components in the Oil and Gas Industry

fitting. Items 4, 6, 8, and 13 are gate valves, which are used to start and stop fluid flow. Item number 5 is a pressure gauge, which is used to measure the pressure in the system of pipes. Items 9 and 11 are flanges used to connect piping components. The use of flanges facilitates the disassembly and inspection of the piping system. Item number 12 is a piece of pipe. Choke manifolds are primarily composed of at least two adjustable or positive chokes (choke valve), high-pressure gate valves, and fittings mounted on the skid. The choke valve, sometimes also known as the choker valve, is a type of control valve used primarily in oil and gas production wells to control the flow of fluids. It is possible to drop the pressure as high as 500 bars through a choke valve. To control the flow of fluid, a choke valve consists of a plug or stems movable within a slotted cylinder. A choke valve is a very robust device designed to withstand severe extreme conditions, such as high corrosion, erosion, high fluid velocity, wide ranges of flow rates, and marine environmental conditions. This valve is typically designed based on American Petroleum Institute (API) 6A “Wellhead and Tree Equipment,” identical to ISO 10423. In Figure 2.25, the main components of a choke valve that is operated manually are shown. Upon entering the valve from the bottom, the fluid rotates 90° and exits to the right. A valve’s body constitutes the main pressure boundary, including both flange ends that are connected to the inlet and outlet piping. The bonnet or cover is bolted to the body. The force produced by the handwheel and operator is transmitted to the valve stem, which is integrated with the valve plug. Plugs serve as flow control elements and/or closure mechanisms. To fully close the valve, the stem moves downward

FIGURE 2.25  A choke valve.

Drilling and Well Completion Equipment

55

and lowers the plug onto the seats. As the stem moves upward, the plug moves upward as well, which results in the valve becoming more open. Plugs and cages work in conjunction to control the flow rate of valves. The cage is a cylinder installed in the valve outlet port where the plug moves downward. By operating the valve, the cage is designed to produce the required fluid characteristic. Due to the 90° rotation of the fluid inside the valve and the movement of the plug downward, there is a significant pressure drop inside the valve. To conclude, a choke manifold performs the following functions: • Controls the wellbore’s flow and pressure. • Enhances the safety and reliability of the well and the rig. • Controls the well kick and executes pressure control technology during the drilling of oil and gas wells.

2.5 WELL COMPLETION Well completion refers to the process of converting a drilled well into a productive well. There are several steps involved in this process, including casing, cementing, perforating, packing gravel, and installing a production tree. A well completion consists of two parts, the sand-face completion, which serves as an interface between the reservoir rock and the wellbore, and the upper completion, which consists of equipment installed within the last casing string to control and monitor the well flow and ensure the well’s safety. In order to complete a well, the first step is to case the hole.

2.5.1 Well Casing An oil well casing is a series of steel pipes used to stabilize the well, prevent contaminants from entering the oil stream, and prevent oil from leaching into the groundwater. The casing is installed in layers, in sections of decreasing diameter, which are then joined to form casing strings. Conductor casing is the first casing lowered into the well and is generally no longer than 50 to 70 meters in length. Before drilling begins, this casing is inserted into the wellbore to prevent caving of the top of the well caused by soil pressure as well as to facilitate the circulation of drilling fluid. Most conductor casings have a diameter between 20” and 30”. The next type of casing to be installed is the surface casing. It can reach a length of 100 to 400 meters and has a smaller diameter than conductor casings, so it is able to fit inside them. The main purpose of the surface casing is to prevent fresh water from being contaminated by leaking hydrocarbons or salt water from deeper underground. Additionally, it serves as a passage for drilling mud to return to the surface and helps protect the drill hole from damage. In a well, intermediate casing is usually the longest section of casing. Intermediate casing serves the primary purpose of minimizing the hazards associated with the subsurface formation that may affect the well. This may include abnormal underground pressure zones and formations that may contaminate the well. There are times when liner casing is

56

Equipment and Components in the Oil and Gas Industry

installed instead of intermediate casing, which is usually attached to the previous casing with hangers. It is also important to note that the liner is not cemented in place, so it is not permanent. Production casing is the last string of casing installed inside the well. This is the casing that provides the means for producing oil and gas from the formation. It is the smallest casing, and its size depends on various parameters, such as the possibility of lifting equipment to be used in the well or the possibility of deepening the well in the future. The production casing of a well must be large enough to allow passage of the drilling bit, for example, if it is decided later on to deepen the well. All four types of casing are shown in Figure 2.26.

FIGURE 2.26  Strings to be used as casings inside wells.

Drilling and Well Completion Equipment

57

2.5.2 Cementing The cementing of a well involves the introduction of cement into the annular spaces between the well-bore and casing or between successive strings of casing. As a result of cementing, a slurry of cement, cement additives, and water is mixed and pumped down through the casing to critical points within the annulus around the casing or in the open hole below the casing string. As well as holding casing in place, cement acts as a barrier against fluid migration between subsurface formations. A cementing operation can be divided into two broad categories: primary cementing and remedial cementing. Primary cementation occurs shortly after the casing is lowered. Providing zonal isolation is the purpose of primary cementing. The purpose of zonal isolation is to prevent fluid movement between formations and ensure that the casing remains in place. The purpose of remedial cementing is to correct problems associated with the primary cementing. The other functions of cementing are summarized as follows: protecting the casing from corrosion and preventing blowouts by forming a seal immediately, preventing shock loads when drilling deeper, and sealing off areas of lost circulation or thief zones. The loss of circulation is the result of the uncontrolled flow of whole mud into a formation, sometimes referred to as a “thief zone.” The loss of circulation can be total or partial. Partially lost circulation occurs when mud continues to flow to the surface and some formation material is lost. Total loss of circulation occurs when all the mud flows into a formation and does not return to the surface. Figure 2.27 illustrates the process of cementing the casing into the wellbore during well completion. The cement slurry used in the oil industry consists of cement, additives, and water. The cement used in cementing oil wells is essentially Portland cement. It is composed of limestone, clay, alumina, and iron. Portland cement is a finely ground powder that is produced by burning and grinding limestone and clay or limestone and shale. The American Petroleum Institute (API) has classified oilwell cements into nine classes based on their intended use, depth, and pressure. As a result of the development of cement additives, Portland cement has been used in a wide range of applications, such as achieving the necessary performance properties with a relatively low level of effort. There are several categories of additives based on their functions. Accelerators are used for shortening the time required for thickening cement slurries, accelerating cement setting, or reducing the thickening time of cement slurries. They are used at low temperatures to reduce the amount of time spent waiting for cement (WOC). As an accelerator, calcium chloride is commonly used at 3% or less by weight of cement. A retarder or set retardant is another type of additive that is added to cement. The purpose of set retarders is to prevent a premature hardening of the cement slurry before it reaches the area being cemented. It is necessary to use set retarders in order to extend the setting time of the cement in order to allow it to be pumped into place. Natural lignosulfonates and sugars are the most common retarders. Various synthetic compounds are used in the manufacture of new retarders. Cement extenders are chemical additives or inert materials used to reduce the density or increase the yield of cement slurries. The slurry yield is typically expressed as cubic feet of

58

Equipment and Components in the Oil and Gas Industry

FIGURE 2.27  Cementing the casing during well completion.

slurry per sack of cement. A higher yield reduces the cost per volume of cement slurry, while a lower slurry density reduces the hydrostatic pressure of the cement column, enabling weak zones to be successfully cemented and isolated. Slurry yield can be expressed as the volume of slurry obtained when one sack of cement is mixed with the desired amount of water and other additives, usually in the units of m3/kg or ft3/sk. The sack is a unit of measurement for Portland cement. It is commonly understood that a sack refers to the amount of cement that occupies a bulk volume of 1 square foot in the United States. Generally, a sack of Portland cement weighs 94 pounds, including API classes. Slurry design calculations are based on the sack, which is often abbreviated as SK. It is possible for cement slurries to lose water to permeable zones, which can lead to a number of problems, including insufficient mud displacement, high viscosity, unwanted changes in settime, and a lack of final compressive strength. When squeeze cementing, fluid loss additives reduce the loss of water through the cement filter cake.

2.5.3 Perforating It is necessary to perforate the casing in order to allow the produced liquids and gases to flow into the well. Perforated completions are used for this type of work. The term “perforation” refers to holes that extend into the formation through the

Drilling and Well Completion Equipment

59

FIGURE 2.28  Perforating during well completion.

casing and cement. Explosives with shaped charges are the most commonly used method of perforating. From the surface of the well, a perforating gun is lowered on a wire line and fired electronically towards the producing zone. Once the perforations have been made, the tool is retrieved. As can be seen in Figure 2.28, the perforations of casing, cementing, and formation are all illustrated by a perforation gun.

2.5.4 Packer and Tubing Installation There is no production from the well through the casing. To transport oil or gas to the surface, a small-diameter pipe known as tubing is used. Just above the producing zone, a device called a packer is lowered around the tubing. In this manner, the packer expands and seals off the space between the tubing and the

60

Equipment and Components in the Oil and Gas Industry

FIGURE 2.29  A well that has been completed with a packer and tubing.

casing, resulting in the produced fluids being forced to enter the tubing. As shown in Figure 2.29, a packer and tubing are installed in the well to provide a means for oil and gas production.

2.5.5 Wellhead Installation It is also necessary to install an appropriate wellhead and Christmas tree as part of the well completion process. The wellhead is the component at the surface of an oil or gas well that provides a structural and pressure-containing interface between drilling and production equipment. Essentially, the wellhead provides the anchoring point and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment. After the well has been drilled, it is completed to provide an interface with the reservoir rock and a conduit for the well fluids. A Christmas tree is installed on top of the wellhead to control the surface pressure and the flow of fluid into and out of the well. Isolation valves and choke equipment are used to control the flow of well fluids during production. It is common to use the terms Christmas tree and wellhead interchangeably; however, a wellhead and a Christmas tree are two entirely different pieces of equipment. Christmas trees can only be utilized when there is a

Drilling and Well Completion Equipment

61

wellhead present, and drilling operations are conducted with a wellhead but without a Christmas tree. The wellhead and Christmas tree are shown in Figure 2.30. This paragraph explains the parts and function of a Christmas tree. Christmas trees are assemblies of valves, casing spools, and fittings used in petroleum and natural gas extraction for controlling fluid flow coming out from the well or injected into the well. It should be noted that the reservoir pressure is reduced over time in order to allow water or gas to be injected into the well to enhance oil and gas production. It is possible to inject other chemicals into a well in order to clean the well, prevent corrosion, and improve oil recovery. As is evident from the Christmas tree picture, there are five gate valves in all for stopping and starting the flow. There are several types of valves, including the kill wing valve, the swab valve, the production wing valve, the upper master valve, and the lower master valve. As soon as the operator, well, and facilities are ready to produce and receive oil or gas, the valves are opened, allowing formation fluids to pass through the tubing to the tree and into the pipeline. The two lower valves are called the master valves (upper and lower, respectively) because they lie in the flow path well fluids must take to get to surface. As the master valves are double, if one fails, the other may be operated, thus improving the safety and reliability of the Christmas tree. There is one master valve that is operated manually and one that is operated automatically by an actuator. It is possible to refer to the master valve operated by the actuator as a surface safety valve. As the right-hand valve is located in the flow path that hydrocarbons take to production facilities, it is often referred to as the flow wing valve or production wing valve. The left-hand valve is often referred to as the kill wing valve. Generally, it is used to inject fluid into the well for the reasons previously explained. Located at the top of the well, the

FIGURE 2.30  A wellhead and Christmas tree. (Courtesy: Shutterstock)

62

Equipment and Components in the Oil and Gas Industry

swab valve is used for well interventions, such as wireline and coiled tubing. Well interventions refer to operations carried out on an oil or gas well during or at the end of its productive life that alter the well’s state or geometry, provide well diagnostics, or manage the well’s production. The choke valve is typically installed after the Christmas tree (after the production wing valve) in order to reduce the pressure of the production fluid significantly.

2.6 ARTIFICIAL LIFT The majority of modern (or recently drilled) onshore U.S. oil wells do not have sufficient internal pressure to allow oil to flow to the surface. Oil from such wells is brought to the surface using lifting equipment or well treatment. A mechanical surface pump or a downhole pump is typically used for lifting equipment. A well treatment involves injecting acid, water, or gases into the well to open the formation and allow oil to flow more freely through it. Occasionally, compressed gas (often natural gas collected from the well) is injected into oil wells. The gas dissolves into the oil, forming bubbles that lighten the oil and cause it to rise to the surface.

QUESTIONS AND ANSWERS

1. What drilling system is responsible for the movement of the drilling bit inside the well? A. Rotary or rotating system B. Hoisting system C. Power system D. Controlling system Answer) Option A is the correct answer.



2. What is the most important component in a drilling rig to separate solids from mud? A. Mud pit B. Mud and solid separator C. Shale shaker D. Desilter

Answer) Option C is the correct answer.



3. In a drilling rig, which of the following components is not considered for hoisting? A. Drilling line B. Crown block C. Rotary table D. Drawwork

Answer) Option C does not contain a hoisting component. As a matter of fact, rotary tables are components of rotating systems.

Drilling and Well Completion Equipment



4. What is the correct statement regarding blowout preventers? A. The blowout preventer is considered part of the monitoring system. B. In order to control the pressure in the well, rams located at the top of the blowout preventer are used to cut the drill pipe. C. Hydraulic fluid supplied by the accumulators typically operates the valves in the blowout preventer. D. In most cases, a blowout preventer valve is installed as a single valve. Answer) Option A is incorrect since the blowout preventer is part of the control system rather than a monitoring system. Despite the fact that rams are located at the bottom of the blowout preventer, Option B is not entirely correct. The correct answer is option C. The reason option D is incorrect is that in most blowout preventer stacks, valves are redundantly installed.

5. An adapter that serves to connect the rotary table to the kelly is a: A. Hook B. Traveling block C. Kelly bushing D. Elevator

Answer) Option C is the correct answer.

6. What is the incorrect statement regarding choke manifolds? A. There are several components that make up choke manifolds, the main component being a choke valve that regulates flow. B. In order to ensure the safety and reliability of the well during operation, a choke valve is an essential component. C. It is not possible to balance the well pressure using a choke manifold. D. There are several components that make up a choke manifold, such as valves, fittings, flanges, and pipes, as well as a base structure.

Answer) The statement in option C is incorrect.

7. In the accumulator bottle, what is the purpose of storing fluid under pressure? A. To operate the pumps during drilling. B. To operate the blowout preventer. C. To facilitate cementing around the casing. D. All three options are incorrect.

Answer) The correct answer is option D. 8. What are the parameters that affect penetration rate during drilling? A. Amount of weight (load) on the drilling bit B. The type of formation that is drilled C. Rate of mud circulation (flow) D. The three items are all correct Answer) The correct answer is option D.

63

64

Equipment and Components in the Oil and Gas Industry



9. In regard to drilling muds and fluids, which of the following statements is not true? A. Additives and contaminants can be present in drilling fluids. B. It is not the responsibility of all drilling personnel to choose and control drilling fluids. C. In order for an oil or gas well to be successfully drilled and completed, it is imperative that the right drilling fluid be chosen. D. Drilling mud is a complex fluid.

Answer) The wrong statement is option B.

10. Regarding Christmas trees, which of the following statements is correct?



A. Before the Christmas tree is installed, it is not possible to begin drilling a well. B. The valve at the top of the tree is called the kill valve, and it is located in the path used by wireline and coiled tubing interventions. C. Valve assemblies, casing spools, and fittings used to regulate the flow of produced oil and gas from a well or to regulate the flow of chemicals and other compounds injected into the well are referred to as a Christmas tree, or “tree.” D. The Christmas tree and the wellhead are the same. Answer) Option A is incorrect since drilling begins before the installation of the Christmas tree. Option B is incorrect because the valve used for well intervention on the top of the tree is known as a swab valve. The correct statement is option C. Option D is incorrect due to the fact that a Christmas tree is different from a wellhead, as a component installed at the wellhead.

FURTHER READING

1. American Petroleum Institute (API) 6A. (2018). Specification for wellhead and tree equipment. 21st ed. Washington, DC: API. 2. Chupin, E., Frolov, K., Korzhavin, M., & Zhdaneev, O. (2022). Energy storage systems for drilling rigs. Journal of Petroleum Exploration and Production Technology, 12(2), 341–350. 3. Fink, J. (2015). Water-based chemicals and technology for drilling, completion, and workover fluids. London: Gulf Professional Publishing. ISBN: 978-0-12-802505-5 4. Gaurina-Međimurec, N., Pašić, B., Mijić, P., & Medved, I. (2021). Drilling fluid and cement slurry design for naturally fractured reservoirs. Applied Sciences, 11(2), 767. 5. Hewlett, P., & Liska, M. (Eds.). (2003). Lea’s chemistry of cement and concrete. 4th ed. Butterworth-Heinemann. ISBN: 978-0-7506-6256-7 6. International Organization of Standardization (ISO) 10423. (2009). Petroleum and natural gas industries-drilling and production equipment-wellhead and Christmas tree equipment. 4th ed. Geneva: ISO. 7. Liu, G. (Ed.). (2021). Applied well cementing engineering. London: Gulf Professional Publishing. ISBN: 978-0-12-821956-0

Drilling and Well Completion Equipment

65

8. Norman, J. H. (2019). Nontechnical guide to petroleum geology, exploration, drilling & production. 4th ed. Texas, USA: PennWell. ISBN: 9781593704933 9. Sotoodeh, K. (2021). Subsea valves and actuators for the oil and gas industry. 1st ed. Oxford: Elsevier (Gulf Professional Publishing). ISBN: 978-0-323-90605-0 10. Von Flatern, R. (2016). Blowout preventors. Oilfield review. Texas, USA: Schlumberger. 11. Wu, S., Zhang, L., Barros, A., Zheng, W., & Liu, Y. (2018). Performance analysis for subsea blind shear ram preventers subject to testing strategies. Reliability Engineering & System Safety, 169, 281–298.

3

Production and Processing Equipment

3.1 INTRODUCTION There is a great deal of importance placed on oil and gas production in the economy. Additionally, it is a complex process that requires specialized equipment. In order to ensure sustainable, efficient, and safe production, this equipment must be properly maintained. Four types of equipment are described in this chapter that are utilized for the production and processing of fluids: separators, pressure vessels, distillation columns or towers, and filters. Pumps and compressors that are used to increase the pressure of fluids and gases are excluded from this chapter and are discussed in the following one. Additionally, some equipment and facilities, such as coolers and heat exchangers, are used to alter the temperature of liquids and gases. Detailed information about this equipment can be found in Chapter 4.

3.2 SEPARATORS Whether at a refinery, a petrochemical complex, a refinery or a gas plant, separation is an essential process in all chemical processing plants. Well streams (or well fluids) produced from well platforms may contain crude oil, gas, condensates, water, and other contaminants. Separators are designed to separate flow into portions that are desirable for further processing. Separators are pressure vessels used in the oil industry to separate well fluids into gas and liquid components. It is usually necessary to use these separating vessels near the wellhead, manifold, or tank battery on a producing lease or platform in order to separate the fluids produced from oil and gas wells into oil and gas and water. Prior to the separation of the fluids, the individual well streams must be combined and directed to the process separators. In order to accomplish this, a piping system called a gathering system is used. Depending on the application, separators may be installed either onshore or offshore. The separation process can also be accomplished by other types of vessels, such as scrubbers, filters, or coalescers. Generally, scrubbers are more efficient than conventional separators at removing small liquid drops from gas phases. It is common to use scrubbers before compressors, glycol units, and amine units, as well as downstream of field separators in order to remove entertained or condensed liquids. Large slugs of liquid should not be handled by the scrubber. The purpose of filters and coalescers is to remove small amounts of mists, rust, scales, and dust from gases. Typical applications include upstream of compressors, 66

DOI: 10.1201/9781003467151-3

Production and Processing Equipment

67

dehydration units, amine units, and custody transfer stations. As a result of the filter fibers, solids are trapped, and liquid droplets are coalesced into large droplets. In many cases, these filter separators are used for final polishing and are often preceded, or protected, by a conventional scrubber or separator.

3.2.1 Separator Configuration A separator usually has dish ends and is made up of a cylindrical shell. When appropriate, other types of end closures are also employed, such as conical and hemispherical. Separators can be classified according to their orientation (horizontal or vertical) and can be either two phase or three phase. Geometrically, all process vessels can be horizontal, vertical, or spherical. Separators of the horizontal and vertical types are commonly used, while separators of the spherical type are not popular. Oil/gas separators can be classified into gas/liquid twophase separators or oil/gas/water three-phase separators based upon the fluids to be separated. A two-phase separator is the most common type and is used to separate liquids from gases. Separators for two phases may be oriented vertically or horizontally. A level control or dump valve allows the liquid (oil, emulsion) to exit the vessel at the bottom. Upon leaving the vessel, the gas passes through a mist extractor in order to remove small liquid droplets from the gas. In order to determine which design is more economical, it may be necessary to compare both designs. The three-phase separator is used to separate gas from liquid and water from oil. It is often necessary to separate two immiscible liquids, the light and heavy phases, as well as a vapor. Examples of three-phase separation include the separation of water, hydrocarbon liquid, and vapor and the separation of gas, condensate, and glycol in gas dehydration units. It is possible to design three-phase units either horizontally or vertically, just like two-phase designs. As shown in Figure 3.1, a three-phase separator is used to separate gas, oil, and water. Using gravity forces, the upper section of the separator separates gas from liquid, while the lower section collects oil and separates it from water at the bottom. As a result, all three phases can be discharged from the separator separately in a relatively clean condition. It is important to note that a three-phase separator will rarely produce water that is clean of oil and oil that is clean of water. There are usually two or more stages involved in the separation process in an oilfield. It is possible to use the separator shown in the picture as the firststage separator. The retention period in the first-stage separator and gravity forces allow the gas to bubble out, the water to settle at the bottom, and the oil to be withdrawn from the middle. In most cases, the pressure is reduced in several stages, but three stages are the most common, and these stages allow controlled separation of volatile components. The goal of the process is to achieve maximum liquid recovery and stabilized oil and gas, as well as to separate water from the oil and gas. Separation in three stages is shown in Figure 3.2. Separators can be horizontal, vertical, and spherical in the oil and gas industry. When large volumes of total fluids and large amounts of total gas are present with the liquid, horizontal separators are most effective. As a result of the greater

68

Equipment and Components in the Oil and Gas Industry

FIGURE 3.1  A three-phase separator to separate water, oil, and gas.

FIGURE 3.2  A three-stage separator.

liquid surface area in this configuration, the trapped gas is able to be released at an optimum rate. In horizontal vessels, gravity separation is more efficient than in vertical vessels. A horizontal separator is suitable for wellstreams with a high liquid-to-gas ratio. Horizontal separators have a greater surface area at the interface, which contributes to phase equilibrium, and they offer less flow turbulence. This is particularly true if foam or emulsion collects at the gas–oil interface. Therefore, horizontal vessels are preferred from a process perspective.

Production and Processing Equipment

69

Additionally, horizontal separators are more cost effective than vertical separators of the same size and material. It is important to know that horizontal separators are typically preferred in three-phase separations. It should be noted, however, that they have several drawbacks, which may lead to a preference for a vertical vessel in certain circumstances: When it comes to handling solids, horizontal separators are not as effective as vertical separators. In a vertical separator, the liquid dump valve can be positioned at the center of the bottom head so that solids will not build up in the separator but will continue to the next vessel in the process rather than accumulating there. It is necessary to place several drains along the length of a horizontal separator in order to effectively drain the solids. The separation of horizontal vessels requires a greater area of plan than that of vertical vessels. In a land-based setting, this may not be of importance, but offshore, where space is limited, it may be of great importance. It is possible, however, to overcome this disadvantage by stacking horizontal separators on top of each other if several separators are used. Furthermore, the placement of the liquid level control in a horizontal separator is more critical than in a vertical separator. Most commonly, spherical separators are used for separating large volumes of gas from very small volumes of liquid. This equipment is primarily used as a scrubber and is rarely used as an oil and gas separator at well sites. Occasionally, these separators are utilized for high-pressure service where compact size and low liquid volumes are desired.

3.2.2 Separation Mechanisms Separation of oil and gas is accomplished physically in most cases, not chemically. Separation units are designed to accommodate fluids operating under pressures ranging from 5 to 700 pounds per square inch (psi). The following are the main mechanisms of separation. 3.2.2.1 Gravity Separators Separation time is largely determined by gravity or, more specifically, the difference in specific gravity of the components being separated. It has been used for centuries to separate different minerals and metals based on their specific gravity. Natural gas has a specific gravity of approximately 0.55 g/cm3, while oil has a specific gravity of 0.85 g/cm3. Separation by gravity uses these differences in material to separate the different products associated with one single stream into distinct streams based on gravitational forces. A gravity separator separates materials by settling and sedimenting and is driven by gravity. As shown in Figure 3.3, two forces act on a spherical liquid droplet with a diameter of DP in the gas phase. The drag force, FD, is exerted by the flow of gas, while the gravity force, FG, is exerted by the weight of the droplet. As the drag force entrains the liquid droplet, the gravity force pulls it down, separating it from the gas phase. Liquid droplets or solid particles are likely to settle out of a gas phase if the gravitational force acting on them is greater than the drag force generated by the gas flowing around the liquid. Liquid/gas separation is controlled by gravitational forces. The greater

70

Equipment and Components in the Oil and Gas Industry

FIGURE 3.3  An illustration of the forces acting on a liquid droplet in a gaseous state.

the difference in specific gravity between the components, the faster the separation will be. During the three-phase separation of oil, gas, and water, a significant difference in specific gravity exists between gas, oil, and water, so the gas quickly breaks free and rises to the top of the liquids. Since water has a higher specific gravity than oil, it accumulates at the bottom, while oil resides in the middle. In addition, the lower the gas velocity and the larger the vessel, the more efficient the separation. The less difference in specific gravity between the components, the longer the settling or retention time for the components to separate. In the case of a more significant difference in specific gravity, such as in the case of gas and oil, gravity separation will occur relatively quickly. The use of gravity separators as the sole source of removal is not recommended if high separation efficiency is required. 3.2.2.2 Pressure Change The most important principle of oil separation is pressure change. When the vapor pressure in a vessel containing hydrocarbons is decreased, some of the lighter hydrocarbons will flash from the liquid phase into the vapor phase. There may be a separation of lighter and heavier hydrocarbons as a result of this process. Separating a light oil from a heavy oil may require different pressure reductions under different conditions, but whenever two or more components of a mixture are separated, there will always be some pressure change involved. Additionally, if the vapor pressure in a vessel containing hydrocarbons is increased, some of the lighter hydrocarbons will condense back into liquid form. In response to an increase in separator pressure, the liquid flow rate out of the separator increases.

Production and Processing Equipment

71

3.2.2.3 Temperature Change An increase in temperature will increase the molecular movement of the oil and gas, so that oil droplets can be attached and make larger molecules, which improves their separation from the gas phase. It is the same concept that is used in the separation of two liquid phases, and it is possible to separate them more easily by increasing the temperature. Oils with a higher viscosity and lower vapor pressure tend to accumulate near the bottom of an oil/water emulsion when the temperature is increased, resulting in better separation efficiency when compared with operating at low temperatures where both phases are more volatile. 3.2.2.4 Scrubbing Action Oil and gas are separated by scrubbing action. The process of scrubbing is also known as absorption. During scrubbing, components are transferred from the gas phase to the liquid phase. Scrubbers are waste gas treatment systems in which a gas stream is brought into intense contact with a liquid, with the objective of allowing certain gaseous components to pass from the gas to the liquid. In absorption, molecules, atoms, and ions of the substance being absorbed get absorbed into the bulk phase (gas, liquid, or solid) of the material in which they are absorbed. The process of absorption occurs when something is absorbed completely into another substance. 3.2.2.5 Chemical Action Oil-in-water emulsions or water-in-oil emulsions are two types of emulsions. In terms of technical terms, emulsions produced by oil-in-water versus waterin-oil involve mixing one phase (the dispersed phase) with the other phase (the continuous phase). To put it another way, one liquid acts as a sort of base upon which another liquid can be added. An emulsion containing oil is referred to as an “oil-in-water” emulsion in which oil is the dispersed phase that is distributed into the continuous phase, water. The roles are reversed in a water-in-oil emulsion. Emulsion breakers, or demulsifies, are a class of specialty chemicals used to separate emulsions, for example, water and oil. As the chemicals move to the oil–water interface, they weaken the surface tension and enhance the coalescence of the oil and water. Typically, they are employed in the processing of crude oil, which is typically produced in conjunction with large quantities of saline water. Refining crude oil requires the removal of this water (and salt). A significant corrosion problem can occur during the refining process if the majority of the water and salt are not removed. 3.2.2.6 Electrical Separation Water separation from crude oil is positively influenced by the increase in coalescing rates. In order to enhance the coalescence of dispersed water drops from oils, an electric field may be used to enhance their separation. From an energy efficiency perspective, electrostatic demulsification is one of the most effective and widely used methods. The combination of high energy efficiency, which reduces

72

Equipment and Components in the Oil and Gas Industry

the need for heat, and the absence of chemical demulsifiers makes this technique environmentally friendly. Electrical methods have been used for dehydrating crude oil emulsions for many years. In electrocoalescence, water droplets contact and coalesce in oils with low dielectric permittivity to increase their size, which speeds up their settling velocity and cuts down on separation time. It is thought that electrostatic effects are caused by the differences between the properties of oil and water, as water has a much higher dielectric permittivity and conductivity value than oil, leading to polarization effects in water drops. 3.2.2.7 Retention Time Retention time for gas–liquid separation (two phases) refers to the average amount of time that a separator allows flowing fluid to remain in the liquid section at the designed flow rate. In order for liquid to fall out of the gas phase and gas bubbles to escape from the liquid, it is important to allow sufficient retention time (also known as residence time or detention time). It is possible to size the liquid section to ensure dropout by specifying the required retention time in accordance with the mixture’s pressure, temperature, and properties. A two-phase separator that does not experience foaming, wax deposition, or slug flows should retain liquid for between 1 and 4 minutes according to API Specification 12J. A three-phase separator’s retention time is defined as the total amount of time that fluid remains in the separation section at the designed flow rate. There are four primary methods of separating oil and water, chemical, heat, electricity, and time. Time is utilized to aid in the separation process through retention time. In the absence of agitation, an oil and water mixture begins to separate into horizontal sections of oil and free water. This time it takes for the mixture to separate into these horizontal layers is called the retention time. Using special internals, liquid particles can be quickly separated from the bulk of the continuous phase. As a result, the separation is more efficient, and the capacity of the system is increased.

3.2.3 Separator Components It will be briefly discussed in relation to the effects of the components of the gas/liquid separator on the separation performance of gas/liquid. The main components of a separator, shown in Figure 3.4, are the feed pipe, inlet device, gas gravity separation section, mist extractor, and liquid gravity separation section. It is important to determine the sizing and geometry of the inlet feed pipe in order to minimize the formation of small liquid droplets and liquid entrainment into the gas phase. An examination of Figure 3.5 shows how the size of the feed pipe affects the flow and separation processes. The size of the inlet pipe in the separator on the left is larger than the inlet pipe in the separator on the right side. As a result of the lower velocity of the inlet fluid on the left separator, the liquid molecules from one hand and the gas molecules from the other hand are more attracted to one another. This results in larger bubbles and liquid molecules on the left separator and greater separation.

Production and Processing Equipment

73

FIGURE 3.4  A horizontal separator with main components.

FIGURE 3.5  The effect of inlet pipe size on separation.

Inlet devices, also called inlet divertors, are designed to improve separation performance. This is accomplished by maximizing gas–liquid separation in the feed pipe, minimizing gas and liquid droplet shearing, and optimizing the downstream velocity distribution of separated phases into the separator. In fact, the inlet guide element and buffer element are usually placed in this area in order to reduce the oil/gas flow rate, disperse the gas/liquid flow, and create the conditions

74

Equipment and Components in the Oil and Gas Industry

for the separation of the next section. Before the secondary or gravity separation section, the inlet device is considered the primary separation area. There are several types of diverters, but the most common is the baffle plate diverter, which can be shaped as a flat plate, a spherical dish, or a cone. There is a plate diverter on top and a dish-type inlet divertor at the bottom of Figure 3.6. In contrast to plates or angle iron, devices such as a half sphere or cone produce less disturbance, reducing the possibility of re-entrainment or emulsification. In addition to centrifugal diverters, there are centrifugal diverters, which are more efficient but more expensive. By using the diverter, the fluid stream entering the system can be forced to undergo a sudden and rapid change in momentum (velocity and direction). This, in combination with the difference in densities of liquids and gases, results in the separation of fluids. The section of the vessel adjacent to the inlet where the inlet device is located dissipates the energy of the entering well stream. The purpose of this section is to make the initial separation of liquid from gas using an inlet device or divertor. In the liquid accumulation section, the majority of the liquid is diverted. As a result of gravitational force, large quantities of liquid and large liquid drops are immediately separated.

FIGURE 3.6  There is a plate diverter (device) on top and a dish divertor (device) at the bottom.

Production and Processing Equipment

75

Located at the bottom of the vessel, the liquid gravity separation section acts as a receiver for all liquids removed from the gas in the inlet, gas gravity, and mist extraction sections. This section, which is also known as the liquid collection section, provides the retention time necessary to allow any gas entrained in the liquid to escape to the gas gravity separation or settling section. In three-phase separation applications, the liquid gravity separation section provides residence time to facilitate the separation of water droplets from a lighter hydrocarbon liquid phase, and vice versa. Because there is a smaller difference in gravity between crude oil and water, compared to gas and liquid in two-phase separation, liquid–liquid separation requires a longer retention period. A coalescing pack can also be used in a three-phase separator in order to promote the separation of hydrocarbon liquids from water. Gravity is used to separate suspended solids, free oils, and grease from waste water using coalescing packs or plates inside separators. Gas velocity drops as it enters the gas gravity settling section or separation section, and small liquid droplets that are entrained in the gas and have not been separated by the inlet diverter are separated by gravity and fall to the gas–liquid interface, preparing the gas for final polishing by the mist extractor. In the gas stream, a mist extractor collects small droplets of liquid (moisture or hydrocarbons) before the gas leaves the separator. Many industrial processes require the use of mist extractors in order to separate gas from liquid or to prevent liquid droplets from escaping from a process vessel (separator). In general, wire-mesh pads and vanes are the most common types of mist extractors. As soon as the small droplets of liquid have been collected, they are removed from the separator along with the other liquids. Demisters that are called mist extractors or mist eliminators have a material bed that passes the gas stream through, for example, wire mesh, corrugated plates, or vanes. The liquid droplets in the gas stream collide with the surfaces of the material and coalesce into larger droplets, which then fall to the bottom of the demister and are removed. After the liquid droplets have been removed from the gas stream, it can be further processed or released into the atmosphere. A demister is an important component of any natural gas processing plant, as it removes liquid droplets and mist from the gas stream, which could have serious consequences for downstream equipment and processes. It can be extremely costly to maintain and repair equipment if liquid droplets and mist in the gas stream cause corrosion, hydrate formation, slugging, erosion, and other problems with pipes, valves, compressors, and other equipment due to corrosion, hydrate formation, slugging, and erosion. The purity level of some natural gas products, such as liquefied petroleum gas (LPG), must be high. It is possible for liquid droplets and mist to contaminate the gas stream and compromise the quality of the product. By removing these contaminants, demisters ensure that the final product meets specifications. The separators contain additional internal components, as follows: Sand removal (jetting) system: Solids and sand are produced from the reservoir and transported to the production system with the wellstream

76

Equipment and Components in the Oil and Gas Industry

fluids (oil, gas, and water). Due to their high density, they deposit at the bottom of gravity separators such as production separators, and must be removed to prevent the build-up of a large layer over time, which may negatively impact the separation process and cause erosion and corrosion problems. Sand in production vessels reduces capacity and affects separation performance, resulting in deteriorated quality of produced water and an increase in water carryover into the oil phase. Uncontrolled sand contamination in separators can lead to the need for a manual cleanout of a separator, which exposes professional cleaning teams to process hazards and may damage downstream equipment. By removing solids regularly, either manually or automatically, operational problems can be prevented, and the life of equipment can be extended. In a separator, sand jetting is used to remove solids that have accumulated at the bottom. By introducing pressurized water through spray nozzles, they fluidize the solids and remove the slurry through drain nozzles in the separator’s bottom. There is no need to depressurize the separator or even cease production while the separator is being cleaned by the sand jetting system. The sand jet system installed inside the separator consists of headers, fluidization nozzles, transportation nozzles, and sand pans. The water flows through the piping system towards a series of spray nozzles. The water spraying through these nozzles fluidizes the sand, and the transportation nozzles push the now slurry into the sand pan openings to reach the drain. It can be designed to flush the entire vessel at once, or, in the event of limited water supply, it can be divided into sections to flush smaller sections at a time. Additionally, a recommended sand management solution should monitor the rate and volume of sand production. Analyzing this information can lead to improved control of the wells regarding sand production and corrosion/erosion. Vortex breaker: A vortex breaker is used at the liquid outlet to prevent a vortex (whirlpools or vortices that can occur when the liquid control valve is opened) from forming. The formation of a vortex at the liquid outlet may result in the withdrawal and entrainment of gas with the exiting liquid (gas blowby). Wave breaker: It is possible for waves to develop at the gas–liquid interface in long horizontal separators. As a result, there will be unsteady fluctuations in the liquid level, which will negatively affect the performance of the liquid level controller. Wave breakers are used to prevent this from occurring by installing vertical baffles perpendicular to the flow direction. There are a number of functions that wave breakers serve. It is possible to stabilize the oil and water separation process by minimizing the number of waves. As a result, large amounts of wet oil (emulsion) don’t form. The term “emulsion” refers to a system consisting of two liquid phases, oil and water, one of which is dispersed into the other. In Figure 3.7, two wave breakers are shown at the bottom of a horizontal separator.

Production and Processing Equipment

77

FIGURE 3.7  A couple of wave breakers are located at the bottom of the horizontal separator.

Weir plate: In liquid–liquid separation, the lighter of two liquids might have an overflow weir. A weir plate, also called overflow baffle, is an internal part of a separator that holds heavy liquids while allowing light liquids (oil) to skim over it. As a result, there will be only light liquid (oil) in the next chamber. Defoaming plates: Defoaming plates are used to combat foam during separation, which can seriously compromise the performance of a separator. An antifoaming plate consists of parallel inclined plates or tubes that are closely spaced. As a result, the foam is broken up and collapses into the liquid layer. In crude oil, foam is primarily caused by impurities other than water that are difficult to remove before the stream reaches the separator. Carbon dioxide is one of the most common impurities that cause foam. Foam can form at the interface between a liquid and a gas bubble when the gas bubbles are released from the liquid. It is possible for foam to adversely affect separators. The foamy crude will decrease the separation capacity of the oil gas separator due to the fact that it takes up a great deal of space. This will negatively affect the separation performance. Furthermore, foam density is between that of oil and gas, causing the level controller to become confused. When there is a lot of foam in the crude oil, it may go out with the oil phase or gas phase, which will reduce separation efficiency, cause a “carry over” when some droplets escape to the gas phase when the oil level goes up, or cause “gas blowby” with the liquid phase when the level is down. Carry-over is the phenomenon whereby free liquid leaves with the gas phase at the top of a separator. It is possible that carryover is an indication of a high liquid level, damage to the separator, or plugged liquid valves at the bottom of the separator. Blowby occurs when free gas leaves with the liquid phase at the

78

Equipment and Components in the Oil and Gas Industry

bottom of the separator. It may be caused by a low liquid level or an improper level control inside the separator.

3.2.4 Separation Process At least three and often four sections constitute the separation process in all separators: the primary separation section, the secondary separation section, the liquid accumulation section, and the mist extractor section. The primary separation section is the area of the vessel around the inlet where the energy of the entering wellstream is dissipated. The purpose of this section, along with its mechanical components, is to make the initial separation of liquid from gas by using an inlet device in the form of deflectors or impingement baffles. A large portion of the liquid is diverted to the liquid accumulation section. As a result of the gravitational force, larger quantities of liquid and larger liquid drops begin to fall immediately. In a separator, the area immediately beyond the inlet deflector, between the liquid accumulation section and the mist extractor (or the outlet head in the absence of a mist extractor), is referred to as the secondary separation section. Due to the increased cross-sectional area, the velocity of the gas and liquid is reduced in this section. In this manner, the liquid particles are allowed to fall towards the liquid accumulation section due to the gravitational force exerted on their mass. By exerting a drag force on the liquid particles, the upward gas velocity tends to counteract the gravitational force effect. The gravitational force will be the greater force if the particle is large, and it will settle to the bottom as a result. It is likely that very small particles will be carried along with the gas as entrainment and will leave the separator if they are not removed by some other device such as a mist extractor. There must be a liquid accumulation section on all separators in order for the liquid collected from the primary separation section, the secondary separation section, and the mist extractor to be held for a short period of time and then disposed of. In horizontal separators, approximately half of the cross-section is utilized for liquid accumulation. Vertical or horizontal separators are designed with liquid outlet connections located as far away from the inlet as possible in order to ensure maximum liquid retention time for solution gas release. To prevent the development of vortices, these connections are also designed with antivortex baffles or siphon-type drains. The use of mist extractors results in the formation of larger droplets from small entrained particles. By passing the gas stream through the mist extractor, liquid particles entrained in the gas are contacted with the surfaces of the mist extractor. Continual contact with wet surfaces causes the droplets to coalesce into larger ones. In this manner, the small liquid particles are separated from the gas.

3.3 PRESSURE VESSELS A pressure vessel is a closed container designed to hold gases or liquids at a pressure that is substantially higher or lower than the surrounding atmosphere. It is common for the inside pressure to be higher than the outside pressure. Chemical,

Production and Processing Equipment

79

petroleum, petrochemical, and nuclear industries rely heavily on pressure vessels and tanks. An oil and gas pressure vessel is commonly used as a receiver for physical and chemical processes taking place at high temperatures and pressures. The separators discussed earlier in this chapter are examples of pressure vessels. In addition, pressure vessels include tanks, vessels, and pipelines that carry, store, or receive fluids. As shown in Figure 3.8, the pressure vessel is actually a heat exchanger used to change the temperature of fluid. Chapter 5 provides a detailed explanation of heat exchangers. It is possible for the fluid inside the vessel to undergo a change in state, as in the case of a steam boiler, or to combine with other reagents, as in the case of a chemical reactor. There is often an interaction between high pressure and high temperature in a pressure vessel, as well as flammable fluids or highly radioactive material in some cases. As a result of such hazards, it is imperative that the design be such that no leakage can occur. Furthermore, vessels must be designed carefully so that they can withstand the operating temperatures and pressures. Different types of pressure vessels have been produced for a variety of purposes. Geometries such as spherical, conical, and cylindrical are generally preferred. An example of a typical model is the combination of a long cylinder and two heads. Cylindrical vessels are generally preferred over other types of vessels because they are simpler to manufacture and make better use of the available space. It is common for boilers, heat exchangers, chemical reactors, and so forth

FIGURE 3.8  A heat exchanger that is a type of pressure vessel. (Courtesy: Shutterstock)

80

Equipment and Components in the Oil and Gas Industry

to be cylindrical in shape. Spherical vessels require thinner walls for a given pressure and diameter than the equivalent cylinder. Therefore, they are used for large gas or liquid containers.

3.3.1 Design and Safety Safety is the primary consideration in the design of pressure vessels due to the potential impact of an accident. However, in general, the design involves a compromise between considerations of economics and safety. Failures and their consequences are evaluated against the effort required to prevent them; the resulting design should achieve an adequate level of safety at a minimum cost. Design, manufacturing, and material can all contribute to vessel failures, which can be grouped into different categories. It is also possible to categorize failures according to their types, which describe how the failure occurs. It is important to understand the why and how behind each failure. There is a possibility that it failed because of corrosion fatigue due to the wrong material selection! As with stress and loading categories and types, the designer must have an understanding of failure categories and types as well. It has been discovered that there is a significant number of cracked and damaged pressure vessels in workplaces as a result of recent inspections. There is a possibility of leakage or rupture failure in vessels that have been cracked or damaged. There are a number of potential health and safety hazards associated with leaking vessels, including poisoning, suffocation, fires, and explosions. It is important to note that rupture failures can cause much greater damage to property and life. In order to ensure worker safety and health, pressure vessels must be designed, installed, operated, and maintained according to the appropriate codes and standards. The American National Standards Institute (ANSI) includes the ASME Code as a standard. Also included in the ANSI standards are low-pressure storage tank codes developed by the American Petroleum Institute (API). Despite the fact that the ASME Boiler and Pressure Vessel Code has been used throughout the world, many other industrialized countries have also developed boiler and pressure vessel codes. The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) Sec VIII Div. 02 is titled “Rules for Construction of Pressure Vessels” and covers rules for the design, manufacturing, testing, inspection, and certification of pressure vessels and boilers. As a part of the code design criteria, there are several basic rules that specify the design method, the design load, the allowable stress, the acceptable material, and the requirements for fabrication and inspection certification of pressure vessels. In “design by rule,” the minimum required thickness of a part is calculated using design pressure, allowable stress, and a formula compatible with the geometry of the part. As a result of this procedure, a minimal amount of analysis is required to ensure that the vessel will not rupture or undergo excessive distortion. It is also important to note that the code provides many details regarding the construction of vessels, in addition to specifying the vessel thickness. It is required that a more rigorous analysis be performed when vessels are subjected to complex loadings, such as

Production and Processing Equipment

81

cyclic, thermal, or localized loads, and where significant discontinuities occur. This method is known as the “design by analysis” method. Internal/external pressures, dead loads resulting from the weight of the vessel and contents, external loads resulting from piping and attachments, wind and earthquakes, operating-type loads resulting from vibration and sloshing of contents, and start-up and shutdown loads influence the design of pressure vessels. It is important to note that the code considers design pressure, design temperature, and, to some extent, the effects of other loads on circumferential (or hoop) and longitudinal stresses in shells. The designer is responsible for accounting for the effects of the remaining loads on the vessel. In order to handle wind and earthquake loads, various national and local building codes must be consulted.

3.4 DISTILLATION COLUMNS (TOWERS) 3.4.1 Distillation Process The process of distillation is a method of purifying liquids, and it is capable of separating components of a mixture if their boiling points are significantly different. Distillation involves selective boiling and subsequent condensation of a component in a liquid mixture. Basically, it is a method of separating components that may be used to either increase the concentration of one component in a mixture or to obtain (almost) pure components from the mixture. Through the process of distillation, one of the components in the liquid mixture is forced into a gaseous state as a result of the difference in their boiling points. The distillation process can be described as a physical separation rather than a chemical reaction. Distillation can be accomplished in a variety of ways, including simple distillation, fractional distillation, stream distillation, vacuum distillation, air-sensitive vacuum distillation, short path distillation, and zone distillation. During simple distillation, the liquid mixture is heated to a boiling point, and the resulting vapor is immediately condensed. The method can only be used when the boiling points of the liquids are significantly different (at least a difference of 25°C). In order to separate mixtures of liquids with similar boiling points, fractional distillation is often used. It consists of several vaporization-condensation steps (which are carried out in a fractioning column). The process is also referred to as rectification. In most liquid mixtures, the composition of the vapors does not remain the same as the composition of the liquids. In the presence of heat, the liquid with the lower boiling point boils and transforms into vapor. A volatile component remains in a vapor state for a longer period of time than a liquid component. This process involves repeated distillations and condensations, which separate the mixture into its components. As a result of heating, the volatile components are converted from a liquid state to a vapor state, and when this vapor is converted to a liquid state, the volatile components are converted into a liquid state. In distillation, vaporization is followed by condensation (liquefaction). Repeating this distillation process will leave a more volatile component in a pure state in the liquid state. As a result of the fractional distillation method, components of a mixture of liquids

82

Equipment and Components in the Oil and Gas Industry

and gases can be separated as pure substances. This type of distillation relies on the principle that different liquids boil at different temperatures and evaporate at different rates. Therefore, when the mixture is heated, the substance with a lower boiling point begins to boil first and becomes a vapor. Among the most common separation technologies, fractional distillation is used in refineries, petrochemical plants, natural gas processing plants, and cryogenic air separation plants. In chemical engineering, fractional distillation towers are used to separate large quantities of liquids in a single column, such as in the processing of petroleum and natural gas. It is possible to separate two components into two streams using a simple column. In order to separate heat-sensitive components in a mixture, steam distillation is often used. Steam is passed through the mixture (which is slightly heated) to vaporize some of the components. Through this process, a high rate of heat transfer is achieved without the need for high temperatures. In order to obtain the distillate, the resulting vapor is condensed. Vacuum distillation is an important process in the chemical and pharmaceutical industries. It is the preferred method of separation when the compound to be separated has a high boiling point or is explosive. In addition, it allows for the separation of substances that would decompose at higher temperatures. A  vacuum distillation or distillation under reduced pressure is a form of distillation that is performed under reduced pressure. The technique is used when the boiling point of the desired compound is difficult to achieve or will cause the compound to decompose. Compounds with a lower boiling point will decompose when a reduced pressure is applied. A lower pressure allows the component to boil at a lower temperature due to the lowering of the pressure. When the component’s vapor pressure equals the surrounding pressure, it is converted into a vapor. The vapor is then condensed and collected as the distillate. Also, vacuum distillation is used to obtain high-purity samples of compounds that decompose at high temperatures. Vacuum distillation is used for compounds that are sensitive to air and readily react with it, but the vacuum must be replaced with an inert gas once the process has been completed. A process of this type is often referred to as air-sensitive vacuum distillation. Short-path distillation is used to purify a small volume of a compound that is unstable at high temperatures. In this process, the distillate is produced under reduced pressure levels and travels a very short distance before being collected (hence the term “short path”). This method reduces the amount of wastage along the walls of the apparatus due to the reduced distance traveled by the distillate. The process of zone distillation involves the partial melting of a substance and the condensation of the vapors that result to obtain a pure distillate. Zone heaters are used to perform this process in a long container.

3.4.2 Laboratory Distillation Process As well as being used in small-scale laboratory distillations, fractionating columns are also used in large-scale industrial distillations. Figure 3.9 illustrates a fractional distillation apparatus using a Liebig condenser. Liebig condensers are the most basic water-cooled designs. As the inner tube is straight, it is easier to

Production and Processing Equipment

83

FIGURE 3.9  Laboratory fractioning distillation.

manufacture. A Liebig condenser, also known as a straight condenser, is a type of laboratory equipment that consists of a straight glass tube surrounded by water. In the laboratory, a fractionating column is a piece of glassware used to separate liquid compounds of close volatility from vaporized mixtures. Alternatively, it may be referred to as a fractional column. By allowing the mixed vapors to cool, condense, and vaporize again, fractionating columns assist in the separation of the mixture. To continuously vaporize the feed liquid, the liquid is heated and boiled under constant pressure in a distillation kettle or round-bottomed flask. As steam is generated one after another, it is cold-leached and used as a top product where the volatile components are relatively enriched. Throughout the distillation process, the volatile matter concentration in the liquid in the kettle decreases continuously, and the volatile matter concentration in the steam also decreases. By using the difference in boiling points and relative volatility, distillation is a technique used to separate two or more volatile liquid compounds. The distillation process takes advantage of the relative volatility of the components of the feed mixture. In general, there is a difference in the vapor and liquid composition of two or more compounds at a given pressure and temperature as a result

84

Equipment and Components in the Oil and Gas Industry

of the partial pressures of the components. Distillation exploits this by bringing liquid and gas phases into contact at temperatures and pressures that facilitate separation. When these components come into contact, those with lower volatility (typically lower boiling points) will move into the liquid phase, while those with a higher volatility will move into the vapor phase. The name fractional distillation or fractionation is derived from the fact that groups of compounds within a relatively small range of boiling points are also known as fractions. In many cases, it is not worthwhile to separate the components in these fractions further based on the product requirements and the economics. Boiling point is the temperature at which the vapor pressure of a liquid equals the atmospheric pressure surrounding it. When a liquid is in a vacuum environment, its boiling point is lower than when it is at atmospheric pressure. The boiling point of a liquid in a high-pressure environment is higher than that of the same liquid at atmospheric pressure. Thus, the boiling point of liquids is affected by the surrounding pressure in the environment. In most cases, boiling points are expressed in terms of atmospheric pressure (1 atm). Water has a boiling point of 100°C (212°F) at standard pressure.

3.4.3 Distillation Towers 3.4.3.1 Basic Operation and Terminology There are many different types of hydrocarbons in a barrel of crude oil. The process of refining oil separates everything into useful components. Among the unit operations of chemical engineering is fractional distillation. In the chemical process industries, where large quantities of liquids need to be distilled, fractionating columns are widely used. In addition to petroleum refineries, distillation finds its widest application in petrochemical operations, natural gas processing, coal tar processing, brewing, liquified air separation, and hydrocarbon solvent production. A fractional distillation column is the first step in the oil refining process. In refining, fractional distillation is the most important step for separating mixtures with narrow differences in boiling points. The crude oil feedstock in such refineries is extremely complex and multi-component and must be separated in order to achieve pure chemical compounds. As crude oil consists of various components with different sizes, weights, and boiling temperatures, it is first necessary to separate these components. Fractional distillation is a process that allows them to be separated easily because of their different boiling temperatures. Fractional distillation consists of the following steps: 1. The mixture of two or more substances (liquids) with different boiling points is heated to a high temperature. The heating process usually involves the use of high-pressure steam at temperatures of approximately 1112°F/600°C. 2. A mixture boils, resulting in vapor (gases). Most substances enter the vapor phase after boiling.

Production and Processing Equipment

85

3. This vapor enters the bottom of a long column that contains trays or plates (fractional distillation column). The trays have many holes or bubble caps (such as a loosened cap on a soda bottle) that permit the vapor to pass through. In addition to increasing the contact time between vapor and liquid in the column, they assist in collecting liquids that form at various heights in the column. In the column, there is a temperature difference (hot at the bottom, cool at the top). 4. The vapor rises in the column. As the vapor rises through the trays in the column, it cools. 5. As a substance in the vapor reaches a height at which its boiling point is equal to the temperature of the column, it will condense into a liquid. Those substances with the lowest boiling points will condense at the highest point in the column; those with higher boiling points will condense at the lowest point. 6. Trays are used to collect the various liquid fractions. 7. There is a possibility that the collected liquid fractions may be sent to condensers for further cooling and then to storage tanks, or they may be sent to other areas for further chemical processing. A column and two heat exchangers are used in the industrial distillation process. As a general rule, industrial distillation is performed in large, vertical cylindrical columns called “distillation towers” or “distillation columns” that have diameters ranging from about 65 centimeters to 6 meters and heights ranging from about 6 to 60 meters. Between the two heat exchangers, one is called a reboiler, and the other is called a condenser. The reboiler, which is typically placed at the bottom end of the tower and next to it, provides heat and energy to the distillation process. The amount of heat entering the column from the reboiler and with the feed must be equal to the amount of heat removed from the column by the overhead condenser and with the products. A reboiler is a type of heat exchanger that supplies heat to the bottom of an industrial distillation column. Boiling the liquid at the bottom of the distillation column generates vapors that are returned to the column to drive the distillation process. It is the condenser’s role to convert the vapors from the combined heat treatment into liquids. Another distillation facility is the reflux drum, which collects the condensed vapor from the top of the column and enables it to be recycled back into the column. Besides the tower, two heat exchangers, and a reflux drum, some auxiliary equipment such as pumps, control systems, and storage systems is also used for distillation. As a result of the distribution of liquid and gas phases in the column, the vapor phase is enriched with more volatile compounds, while the liquid phase is enriched with less volatile compounds. In order for a distillation to be successful, mass transfer must be ensured. Figures 3.10 and 3.11 illustrate the distillation process in a tower, including the reboiler and condenser. The separation process involves controlling the column temperature and pressure profiles in order to take advantage of differences in the relative volatility of the mixture components and, therefore, the tendency to change phase.

86

Equipment and Components in the Oil and Gas Industry

FIGURE 3.10  A schematic of the distillation process in a tower.

A feed consists of a mixture of inlet material into the tower, which may be liquid, gas, or a mixture of liquid and gas. There is usually a predetermined point in the tower where the feed is placed. Tray towers refer to the feed area as the feed tray. An industrial fractionating column shown in Figure  3.12 separates a feed stream into a distillate fraction and a bottoms fraction. There are, however, many industrial fractionating columns that have outlets at intervals along their length, allowing a single column to distill a multi-component feed stream and separate multiple products with different boiling ranges. The “lightest” products with the lowest boiling points exit from the top of the columns, while the “heaviest” products with the highest boiling points exit from the bottom. The light components are those with the highest relative volatility. In the case of simple hydrocarbons, this is the component with the lowest molecular weight. At the top of the column, it is found in a higher concentration. A heavy component is the component with the lowest relative volatility; for simple hydrocarbons, this is the component with a higher molecular weight. To achieve better separation of products, industrial fractionating columns use external reflux and rectification. Above the feed stage, the trays are referred to as the rectifying section of the distillation column, and

Production and Processing Equipment

87

FIGURE 3.11  A schematic of the distillation process in a tower.

the distillate product is generally withdrawn from the top of the column. Reflux refers to the portion of the condensed overhead liquid product that returns to the upper portion of the fractionating column, as shown in Figure 3.12. Downflowing reflux liquid cools and condenses up flowing vapors inside the distillation tower, thereby increasing its efficiency. There is no doubt that the more reflux and/or trays provided, the more effective the tower is at separating lower-boiling materials from higher-boiling materials. Heat and material are intensively exchanged between the downward-moving liquid phase and the upward-moving vapor phase. In the liquid phase, the less volatile components of the vapor phase condense and increase in concentration. In addition, the condensation heat released from the liquid phase evaporates the more volatile components. In the column, these processes increase the concentration of volatile components in the vapor phase as they move from the bottom to the top. The stripping section refers to the trays

88

Equipment and Components in the Oil and Gas Industry

FIGURE 3.12  The distillation tower schematic shows the separation of fluids.

between the bottom of the column and the feed tray. The purpose of the stripping section is to concentrate the heavier component in a liquid state. In order to design and operate a fractionating column, it is necessary to take into account both the composition of the feed and the composition of the desired products. Another important consideration in the design of the columns is vapor–liquid equilibrium (VLE). An equilibrium between a liquid and its vapor (gas phase) is referred to as vapor–liquid equilibrium, in which the rate of evaporation (change from liquid to vapor) equals the rate of condensation (change from vapor to liquid) on a molecular level such that no net (overall) interconversion occurs between vapor and liquid. The design of distillation columns is dictated by the boiling points of the components in the mixtures to be separated. Accordingly, the sizes and heights of distillation columns are determined by the vapor liquid equilibrium data for the mixtures. 3.4.3.2 Types of Distillation Columns Each distillation column is designed for performing a specific type of separation, and each design differs in terms of complexity. It is possible to classify distillation columns based on how they are operated. Therefore, we have batch and continuous columns. In batch operations, the feed to the column is introduced in batches. As a result, the column is charged with a “batch,” and then the distillation process is carried out. As soon as the desired task has been accomplished, the next batch of feed is introduced. Continuous columns, on the other hand, process a continuous feed stream. There are no interruptions unless there is a problem with the column or surrounding units. Typically, they can handle high throughputs and are the most common type.

Production and Processing Equipment

89

3.4.3.3 Distillation Column Internals During the distillation process, the internals of the distillation column promote contact between vapor and liquid. This allows to achieve equilibrium efficiently, thereby enhancing the separation of each component of the liquid mixture. The extent and type of contact between vapor and liquid streams are influenced by factors such as the geometry of distillation column internals. There are two general types of distillation column internals: • Plates/trays: Usually used interchangeably, plates and trays are the most common components of distillation columns. Plate columns are typically used for large diameters and multiple stages. In a plate column, the plate is used to contain gases and liquids. It is possible to handle a wider range of gas and liquid flow rates with plate columns. Corrosive liquids are handled less economically in plate columns than packed columns. They are not suitable for handling foaming liquids. The installation of maintenance holes on the plates makes it much easier to maintain plate columns. There are different types of trays used in gas–liquid contactors, including sieve trays, valve trays, and bubble cap trays. • Sieve trays: Sieve trays (see Figure 3.13) are simply metal plates with holes drilled through them. The vapor passes straight upward through the liquid on the plate. There are three design parameters: the arrangement, the number, and the size of the holes. • Valve trays: A liftable cap (see Figure 3.14) covers the perforations in the valve trays. The flow of vapor lifts the caps, creating a flow area for the passage of vapor. As a result of the lifting cap, the vapor is directed horizontally into the liquid, thus providing better mixing than is possible in sieve trays. • Bubble cap trays: A bubble cap trays (see Figure 3.15) consists of a riser or chimney fitted over each hole and a cap covering the riser. Caps are mounted so that there is a space between riser and cap to allow vapor to pass through. As the vapor rises through the chimney, it is directed downward by the cap, eventually bubbling through the liquid on the trays.

FIGURE 3.13  Sieve tray.

90

Equipment and Components in the Oil and Gas Industry

FIGURE 3.14  Valve tray.

FIGURE 3.15  Bubble cap tray.

When comparing bubble-cap trays, sieve trays, and valve trays, the following ­factors should be considered: Cost: Compared with sieve or valve trays, bubble cap trays are considerably more expensive, and their relative price will vary depending on the material used in their construction. Sieve trays are normally the cheapest due to their simple design. Operating range: There is a range of vapor and liquid rates within which the tray will operate satisfactorily. Often, the ratio of the highest to the lowest flowrates is referred to as the “turndown ratio.” Due to their positive liquid seal, bubble-cap trays can operate efficiently even at very low vapor rates. As sieve trays depend on the flow of vapors through the holes to hold the liquid, they cannot operate at very low vapor rates. Since valve trays provide greater flexibility than sieve trays at a lower cost than bubble-caps, bubble-cap trays have the widest operating range, followed by valve trays and sieve trays. Pressure drop: Vacuum operations will require consideration of this factor. A tray’s pressure drop will depend on its detailed design, but in general, sieve trays produce the lowest pressure drop, followed by valves, and bubble caps produce the highest. Maintenance: In the case of dirty services, bubble caps are not recommended, as they are the most susceptible to plugging. It is easiest to clean sieve trays.

Production and Processing Equipment

91

In summary, sieve trays are the cheapest and are suitable for most applications. If sieve trays are unable to meet the specified turndown ratio, valve trays should be considered. A bubble cap should only be used when very low vapor rates must be handled and where a positive liquid seal is required regardless of flow rate. Each tray has two conduits, one on each side, known as downcomers. During the descent of liquid from one tray to the next, it falls through the downcomers as a result of gravity. In Figure 3.12 on the right and Figure 3.16, the flow across each plate is illustrated. A weir on the tray ensures that there is always some liquid (holdup) on the tray, and it is designed to keep the holdup at a suitable height. Since vapor is lighter than liquid, it flows up the column and passes through the openings on the trays. In each tray, the area that is available for the passage of vapor is known as the active tray area. During the passage of the hotter vapor through the liquid on the tray above, heat is transferred to the liquid. As a result, some of the vapor condenses, adding to the liquid on the tray. Condensate, on the other hand, is richer in less volatile components than vapor. As a result of the heat input from vapor, the liquid on the tray boils, generating more vapor. It is

FIGURE 3.16  The flow of liquid and vapor in a distillation tower tray.

92

Equipment and Components in the Oil and Gas Industry

this vapor, which moves up to the next tray in the column, that is richer in volatile constituents. As a result of this continuous contact between vapor and liquid on each tray of the column, low boiling point components are separated from high boiling point components. • Packings: They provide a large surface area for vapor–liquid contact, which increases the efficiency of the column. Therefore, packings serve as a means of separating vapor–liquid mixtures (often in solvents). In general, packed columns are used for operations with a small diameter (less than 600 mm) and a low capacity. It is more economical to handle corrosive liquids in packed columns by using cheap ceramic packing materials or chemical-resistant packing elements. It is suitable for the handling of foaming liquids. In the case of packed columns, maintenance work or cleaning cannot be performed easily. The process requires a great deal of time and effort. Packing containing columns is more feasible for vacuum applications, as the pressure drop per stage is smaller. Packing containing columns is not appropriate for sidestream applications. A packed tower is a simple structure to construct. There are a number of packing types used in packed columns, including random packing, structure packing, and grid packing. The choice of packing method depends on the service required, but random packing is the most common in the process industry. Random or dumped packing (see Figure  3.17) refers to packing pieces that are randomly packed or dumped into the shell of the distillation column over its supporting grid. The majority of columns require random packing. Random packing has the major advantage of being much less expensive to implement than structured packing. Random packing also has other advantages, such as increased contact area, mass transfer, and efficiency over older technologies, such as tray technology. Structured or systematically arranged packing is composed of wavy layers of wire mesh or corrugated sheets stacked vertically. It is, however, sometimes necessary to provide more structure than can be achieved through random packing. Structured packing is required in this situation. In structured packing, as illustrated in Figure  3.18, thin corrugated metal plates or gauzes are arranged in a way that forces fluids to take complicated paths through the column, thereby allowing for greater contact between phases. In structured packing, metal or wire gauze sheets are corrugated and embossed with a pattern of perforations. This results in a honeycomb structure with inclined flow channels that provides a relatively high surface area but has very low resistance to gas flow. The surface enhancements have been selected in order to maximize the spreading of liquids. There are significant performance benefits to be gained from these characteristics in applications involving low pressure and low flow rates. A grid packing (see Figure 3.19) is also a systematically arranged packing that uses a lattice structure rather than a mesh

Production and Processing Equipment

93

FIGURE 3.17  Random packing.

FIGURE 3.18  Structured packing.

or corrugated sheet. Grid structured packing combines the high surface area of traditional structured packing with the rugged construction of the common grid configuration. In severe services that are susceptible to plugging, coking, erosion, and containing solids, it can provide high heat transfer efficiency, high mechanical strength, and antifouling properties. This smooth surface provides low liquid holdup and reduces the residence time.

94

Equipment and Components in the Oil and Gas Industry

FIGURE 3.19  Grid packing.

3.5 FILTERS 3.5.1 Introduction and Applications Filtration is the process of removing the impure components from a liquid or gas in order to make it suitable for consumption by humans. No matter what industry you are involved in, filtration is an essential prerequisite. The same is true for the petroleum industry as well. Oil is the primary product of the petroleum industry. Deep within the earth’s crust, oil and gas are hidden in layered structures. As a result, hydrocarbons are crude or raw and remain mixed with impurities. Therefore, oil and gas must be filtered in order to remove impurities and purify them. There are different kinds of impurities that can be removed by these filters, including oil lubrication, solids, fuel gas, gas feeds, and fuel oil inlets. The presence of contaminants in such oil and gas inputs is very common. As well as reducing the quality of the final product, these contaminants have the potential to damage generators, engines, turbines, and pumps over time. It may be necessary to install one or multiple oil and gas filtration units within the process unit or

Production and Processing Equipment

95

plant in order to protect such expensive equipment and maintain the quality of the process. Filters of this type are also capable of separating oil and gas when such a requirement exists. In terms of process requirements for new equipment and plant construction, high-purity gases and oils present new challenges to the industry. It is essential that high-performance oil and gas filter systems be employed in order to achieve and maintain the required purity levels and safety regulations. The oil and gas filtration system is one of the most basic components of any production facility. In addition to compressors and turbines, gas filters may also be used in conjunction with reactors or stationary and mobile large engines. Hydraulic and lubrication systems often use oil filters. Oil and gas filters are found in the upstream, midstream, and downstream sectors of the oil and gas industry. The typical fields of application are exploration, transportation, storage, and processing of oil and gas, the production of chemical and petrochemical products, the processing of industrial raw materials, and the operation of stationary and mobile power generation plants. Upstream facilities are those in which hydrocarbons are first recovered. With the use of effective separation solutions, oil recovery rates can be increased, and produced water can be disposed of effectively. Before being disposed of, produced water must meet certain standards of cleanliness. A filter is essential for removing harmful contaminants from capital equipment, such as a gas dehydration unit, in order to prevent deterioration. Among the midstream activities are the transportation of produced liquids, LNG production, and gas processing. The failure to separate and filter produced fluids during the transportation and processing operations may result in costly downtime. During the gas processing process, filters are used to separate solid contaminants, oil, and water from the gas stream. In downstream oil and gas refining, it is crucial that feed streams be pure in order to ensure adequate chemical reactions. In order to improve the performance of these systems, particulates and fluid contaminants must be removed from them.

3.5.2 Filtration Media One of the most critical components of any oil and gas filtration system is the filter media. The filter media determines how oil and gas are filtered. This is the part that performs the actual filtration process. In most cases, the filter media consists of multiple layers of porous material. Porous components absorb dirt and other contaminants when oil or gas passes through them. In fact, filter media are the components of a filtering system that separate unwanted particles from the substance to be filtered. The type of filter medium should be selected depending on the material to be filtered. A filter can be classified into two types, each utilizing a different type of media. Liquid and gas filters fall into these categories. As far as filter media types are concerned, there are many options available. In some cases, the manufacturer may be able to select the correct media depending on the components that need to be filtered, the type of contaminants that may occur, and the degree of purity required. The following are some of the most commonly used media materials:

96

Equipment and Components in the Oil and Gas Industry

Fiberglass: Fiberglass is a type of fiber-reinforced plastic that is made up of glass fibers. It is possible to arrange the fibers randomly, flatten them into a sheet called a chopped strand mat, or weave them into glass cloth. In most cases, the plastic matrix is a thermoset polymer matrix, such as epoxy, polyester, or vinyl ester resin; however, a thermoplastic matrix can also be used. In spite of the fact that thermosetting plastics and thermoplastics are both polymers, they behave differently when heated. After curing, thermoplastics can melt under heat, while thermoset plastics retain their form and remain solid under heat. Due to their affordability, fiberglass filters have become increasingly popular in recent years. A fiberglass filter can be used for filtering air, gas and liquid separation, and liquid/liquid separation, for example, oil and water separation. Composites: Materials that are composites are those that consist of more than one constituent material. As a result of the merging of these constituent materials, which have notably different chemical or physical properties, a material is created with properties that differ from the properties of the constituent elements. Composite filter media consist of two or more layers of filtration media that are bonded together to create a filter medium with enhanced functionality designed for a specific application. Composites can be made using a variety of different filtration materials and combinations of substrates, with each layer providing a different combination of filtration properties and physical characteristics. Cellulose: The carbohydrate cellulose is a complex polysaccharide that contains 3,000 or more glucose units. A polysaccharide is also known as a glycan, which is the form in which most natural carbohydrates exist. The molecular structure of polysaccharides can be either branched or linear. For enhanced properties, cellulose filter media can be made from pure cellulose fibers or from cellulose fibers mixed with synthetic fibers or glass fibers. By trapping contaminants within a matrix of fibers, it provides a diverse and versatile filtration solution. Because of its superb strength and random fiber size, cellulose is a highly effective material for filtering. It is a great and cost-effective way to filter out most contaminants from oil by using cellulose.

3.5.3 Types of Oil and Gas Filters Oil and gas filtration systems are available in a wide variety of types throughout the world. The following are some of the most popular types you should be familiar with. Simplex filters: Simplex filters are the most basic type of filtration technology. Compact in design, they are extremely easy to clean. When additional shut-off devices can be used to switch off the system or the filter, simplex strainers are recommended for use. In the event of a problem with the filter, the entire process must be stopped while the filter is being repaired, which has significant disadvantages. They prevent soiling and

Production and Processing Equipment

siltation of system components. Gas or oil passes through an inlet into the outer chamber, which contains filter media. Depending on the type of contamination, contaminants are either absorbed or deposited at the bottom of the filter. Then, the remaining liquid or gas flows out through the outlet. An example of a simplex filter can be seen in Figure 3.20. Duplex filters: A duplex filter is composed of two filters that are attached together like twins. These filters operate in a similar manner to simplex filters, with the exception that they have two separate strainer housing units instead of one. In the maritime and production industries, for example, duplex filters are primarily used in situations where shutting down machines and systems is neither practical nor economically feasible. The duplex filter has the advantage that it can be operated without maintenance during normal operation, with the exception of checking

FIGURE 3.20  A simplex filter.

97

98

Equipment and Components in the Oil and Gas Industry

the seals and cleaning the filter element. By connecting two filter chambers together with a changeover valve, one chamber is always in operation, while the other can be in standby. A duplex filter with two ball valves for changing over can be seen in Figure 3.21. Coalescer filters: The coalescing or coalescer filter is a component used in large industries, oil and gas plants, and chemical plants for the separation of diverse substances and mixtures. Basically, a coalescing filter works on the principle of coalescence. In this process, smaller fluid molecules combine to form larger particles. The coalescer filter is designed to remove oil impurities and other contaminants such as dust, dirt, solid waste, and liquid waste. Additionally, oil coalescing filters help remove impurities and contaminants from compressed air and gas used in processing units such as liquid oil and aerosols. This type of filter is also used in the water–oil interphase, which is part of the liquid–liquid

FIGURE 3.21  A duplex filter.

Production and Processing Equipment

filtration process. It may be possible to use these filters as independent units at times, and in other cases, they can form a part of a larger filtration process and serve as an intermediate step in filtering air streams as they proceed through subsequent stages. Generally, oil coalescing filters are used to remove impurities and contaminants from air and gas streams. Coalescence is the process of combining two or more elements into a new substance. In an oil filter, coalescence occurs when liquid aerosols mix together, resulting in larger droplets. Due to coalescence, these droplets become so large that gravity pulls them downward. Oil particles of greater size then accumulate at the bottom of the filter chamber. Through the drainage outlet, these can then be removed. Figure 3.22 illustrates a coalescer filter used to separate oil.

FIGURE 3.22  A coalescer filter.

99

100

Equipment and Components in the Oil and Gas Industry

Single-bag filters: A single-bag filter (see Figure 3.23) is also known as a single-bag basket housing. Typically, these are used for smaller applications requiring the collection of solid contaminants, and the inflow rate is quite slow. It is important to note that these filters are very economical, which is a significant advantage. Only one filter bag can be accommodated in a single-bag housing. Media flow through the piping or pipeline, into the housing, through the bag, and back out of the pipeline. For liquid filtration, single-bag housings are a popular and economical choice. In general, single-bag

FIGURE 3.23  A single-bag filter.

Production and Processing Equipment

101

housings are easy to install in any system, and there is a wide range of options in terms of material, size, maximum pressure, and temperature. Multi-bag filters: Filters with multiple bags are used when there is a high flow rate and multiple contaminants to be removed. Due to their multiple filtration bags, these units require fewer bag changes and fewer maintenance interruptions. Vacuum dehydrator: In different systems, including hydraulics, lubrication, and instrument air, water is considered a contaminant. Vacuum dehydrators are oil and gas filtration systems for removing water contaminants from oil or gas inputs as well as hydraulic and lubrication fluids. Using vacuum technology, such dehydrators are capable of removing up to 90% of dissolved water.

QUESTIONS AND ANSWERS

1. Determine which statement about separators is correct. A. There is only a limited use of separators in the upstream oil and gas industry, near the wellheads. B. Vertical separators are generally preferred because they are less expensive than horizontal separators. C. Scrubbers are generally more efficient at removing small liquid drops from gas phases than conventional separators. D. There is only one stage necessary to perform an effective separation in an oilfield.

Answer) Option A does not represent the correct answer since separators are not only utilized in the upstream oil and gas industry but also in downstream units, such as refineries and petrochemical plants. Furthermore, Option B is not correct because horizontal separators are preferred because they provide a greater surface area, which is more effective in separating liquids from gases. In addition, vertical separators are more expensive than horizontal separators of the same size and material. The correct answer is option C. Option D is incorrect because typically twoor three-phase ­separation is required for effective separation of oil, gas, and water in an oilfield.

2. Which option does not address the advantage of horizontal separators over vertical separators? A. In general, horizontal separators are less expensive than vertical separators. B. For the separation of large volumes of gases and liquids, horizontal separators are more suitable than vertical separators. C. In horizontal separators, liquid level control is less critical than in vertical separators. D. All three choices are incorrect.

Answer) In horizontal separators, liquid level control is more critical than in vertical separators. Therefore, option C is the incorrect answer.

102

Equipment and Components in the Oil and Gas Industry

3. What is considered a pressure vessel among the following items? A. Storage tank B. Separator C. Pipeline D. All three items are correct

Answer) Option D is the correct answer.

4. What is the correct definition of the distillation process and distillation tower? A. The stripping section refers to the trays located between the feed tray and the top of the column. The stripping section concentrates the lighter components in the vapor phase. B. The rectifying section refers to the trays that are located between the bottom of the column and the feed tray. The purpose of the rectifying section is to concentrate the heavier components in ­ ­liquid form. C. The reflux process occurs when vapor from the top of a column is condensed into a liquid and returned to the column as a liquid above the top tray. D. In a reboiler, some of the liquid leaving the column is boiled in a heat exchanger located at the top of the column. At the top of the stripping section, the vapor generated returns to the column.

Answer) Option A is incorrect since the provided definition pertains to rectifying sections. The definition provided in Option B is also incorrect, since it pertains to stripping sections. The correct answer is option C. Option D is incorrect since the reboiler is located at the bottom of the distillation column.

5. Which of the following statements does not refer to the advantage of packed towers? A. There is a minimum pressure drop in the packed column. B. Highly corrosive, foaming fluids can be handled easily by the packed column. C. A packed column is simple to construct. D. Compared to plate columns, packed columns are easier to maintain.

Answer) Option D is the correct answer. 6. What type of trays are simply metal plates with holes? A. Sieve trays B. Valve trays C. Metal cap trays D. None of these Answer) Option A is the correct answer.

Production and Processing Equipment



103

7. Which type of packing is suitable for applications such as fouling, erosion, coking, and high solids content? A. Random packing B. Grid structured packing C. Structured packing D. None of these Answer) Option B is the correct answer. 8. What kind of tray has the highest pressure drop? A. Sieve trays B. Valve trays C. Metal cap trays D. None of these Answer) Option C is the correct answer.

9. What sector of the oil and gas industry requires filters? A. Drilling B. Oil transportation C. Oil refining plants D. All options are correct

Answer) Option D is the correct answer.

10. Determine which statement about filters is correct.

A. Oil and gas multi-bag filters are systems for removing water contaminants from oil or gas inputs as well as hydraulic and lubrication fluids. B. Filters with single filter bags are typically used when there is a high flow rate and multiple contaminants to be removed. C. Coalescing filters work on the principle of coalescence. As a result of this process, smaller fluid molecules combine to form larger particles. D. All three options are incorrect. Answer) Option A is incorrect since it provides a definition of a vacuum dehydrator. Additionally, Option B provides a definition of multi-bag filters, which is incorrect. The correct answer is option C.

FURTHER READING 1. American Petroleum Institute (API) 12J. (2008). Specification for oil and gas ­separators. Washington, DC: API. 2. American Society of Mechanical Engineers (ASME). (2012). Design and fabrication of pressure vessels. Boiler and pressure vessel code. ASME Section VIII Div. 02. New York: ASME.

104

Equipment and Components in the Oil and Gas Industry

3. Aspire Energy Resources. How do filters in oil & gas separation units work? [online] available at: www.aspireenergy.com/how-do-filters-in-oil-gas-separation-units-work/ [access date: 22th May, 2023] 4. ATEX Energy Consulting. (2022). Retention time. [online] available at: www. atex-energy.com/resources/retention-time [access date: 18th May, 2023] 5. BYJUS. (2023). Distillation. [online] available at: https://byjus.com/chemistry/ distillation/ [access date: 19th May, 2023] 6. Campbell, J. M. (2014). Gas conditioning and processing, volume 2: The equipment modules. 9th ed., 2nd printing. Editors Hubbard, R., & Snow–McGregor, K. ­Norman, OK: Campbell Petroleum Series. 7. Eleven Production Equipment. (2022). What are the principals of oil and gas separation? [online] available at: www.12eleven.com/news/what-are-the-principles-of-oiland-gas-separation#a [access date: 18th May, 2023] 8. Hussin, B. (2008). Design, analysis and fabrication of pressure vessel. Bachelor thesis. Faculty of Manufacturing Engineering. 9. Khateeb, Z. M. F., & Tambuskar, D. D. P. (2016). Design of pressure vessel and prediction of failure of limpet coil. IOSR Journal of Mechanical and Civil Engineering, 13(1), 28–34. 10. Livingston, E., Scavuzzo, R. J., & Vessels, P. (2000). Pressure vessels, the engineering handbook. Boca Raton, USA: CRC Press. 11. Mokhatab, S., Poe, W. A., & Mak, J. Y. (2018). Handbook of natural gas transmission and processing: Principles and practices. Texas, FL: Gulf Professional Publishing. ISBN: 978-0-12-801499-8 12. Multitex. (2020). Oil and gas filtration system: The ultimate guide. [online] available at: https://multitex-group.com/2021/12/06/oil-and-gas-filtration/ [access date: 23th May, 2023] 13. OPITO Ltd. (1993). Oil and gas separation, part of the petroleum processing ­technology series. 1st ed. Aberdeen: OPITO Ltd. ISBN: 187204185X 14. Stewart, M., & Arnold, K. (2008). Emulsions and oil treating equipment: Selection, sizing and troubleshooting. Texas, USA: Elsevier. ISBN: 978-0-7506-8970-0 15. Stewart, M., & Arnold, K. (2008). Gas–liquid and liquid–liquid separators. Texas, USA: Gulf Professional Publishing. ISBN: 978-0-7506-8979-3 16. Wallau, W., Schlawitschek, C., & Arellano-Garcia, H. (2016). Electric field driven separation of oil–water mixtures: Model development and experimental verification. Industrial & Engineering Chemistry Research, 55(16), 4585–4598.

4

Equipment for Pressurizing Fluids

4.1 INTRODUCTION Consider the case of moving a solid block of metal. The only option is to pick it up and carry it. Liquids and gases, on the other hand, are much easier to move. It is because they are able to move with only a little assistance from us. Liquids and gases are referred to as fluids because they flow through channels and pipes from one place to another. However, they cannot move without assistance. In most cases, we have to provide our own energy in order to move things. It is true that liquids and gases can sometimes be moved by using the stored potential energy (for example, rivers flow downward from their source to the sea using gravity as their force), but we often need pumps and compressors to transport them to places that they would not ordinarily go. The terms “pump” and “compressor” are sometimes used interchangeably, but there is a significant difference between them: Pumps are capable of moving liquids or gases. Pumping, however, is a process that involves the movement of large quantities of liquids, the precise injection of substances, and the generation and release of energy. Due to the natural ability of gas to be compressed, compressors usually move only gas. Both pumps and compressors have very high pressure rises. It is possible to move air into a chamber using different types of compressors. As a result, pumps can work with liquids as well as gases, but compressors generally work with gases only. The reason for this is that liquids are very difficult to compress. Liquids are composed of atoms and molecules that are so tightly packed that they cannot be squeezed any closer together.

4.2 PUMPS Pumps, fans, blowers, and compressors are used to move fluids through flow systems. The mechanical energy of the fluid is increased by such devices. By using the additional energy, it is possible to increase the velocity (flow rate), pressure, and elevation of the fluid. In engineering, a pump is a device that transfers liquids from one place to another by using mechanical force. There are many energy sources that can be used to power pumps, including electrical, motor, wind energy, and manual strategies. Designed to hold up liquids and move fluids from low-pressure areas to high-pressure areas, this device has the ability to handle liquids of all levels. There are three main components of a pump: a housing, an impeller, and a motor. In a pump, the housing is the mainframe, which supports

DOI: 10.1201/9781003467151-4

105

106

Equipment and Components in the Oil and Gas Industry

the impeller and contains the fluid being pumped. Fluid is moved through the pump by means of an impeller, which is a rotating set of blades.

4.2.1 Types of Pumps Pumps are available in a variety of sizes and for a variety of applications. For a certain application, the choice of the pump class and type will depend on the requirements of the system, the layout of the system, the fluid characteristics, the expected life, the energy cost, the code requirements, and the construction materials. Depending on their basic operating principle, they can be classified as dynamic (kinetic) or positive displacement pumps. A dynamic pump is a type of velocity pump in which kinetic energy is added to the fluid by increasing its flow velocity. When the velocity of the flow exits the pump into the discharge pipe, this increase in energy is converted to a gain in potential energy (pressure). The first law of thermodynamics, or more specifically Bernoulli’s principle, explains this conversion of kinetic energy to pressure. In fluid dynamics, Bernoulli’s principle describes the relationship between pressure, speed, and height. Bernoulli’s principle states that an increase in the speed of a fluid coincides with an increase of dynamic pressure and a decrease in the static pressure or potential energy of the fluid. The static pressure is the pressure exerted by the gas or liquid perpendicular to the gas or liquid stream. Dynamic pressure is the kinetic energy of liquid or gaseous air passing through a pipe. The purpose of a positive displacement (PD) pump is to move a fluid by repeatedly enclosing a fixed volume and mechanically moving it through the system. Pumps operate in a cyclic manner and can be driven by pistons, screws, gears, rollers, diaphragms, or vanes. There are two types of dynamic pumps: centrifugal pumps and special effect pumps. The design of a centrifugal pump is very simple. A centrifugal pump is a rotodynamic pump that uses a rotating impeller to increase the velocity of a fluid. A centrifugal pump is commonly used for moving liquids through a piping system. The impeller and diffuser are the two main components of the centrifugal pump, as shown in Figure 4.1. The main moving part is the impeller, which is attached to a shaft and driven by a motor. The majority of impellers are made of bronze, polycarbonate, cast iron, stainless steel, and other materials. An impeller is housed within a diffuser (also known as an as volute), which captures and directs the fluid. With the help of centrifugal force, fluid enters the center (eye) of the impeller and exits the impeller. During the process of fluid leaving the impeller’s eye, a low-pressure area is created, which causes more fluid to flow into the eye. Due to atmospheric pressure and centrifugal force, the fluid flows at high speed through the impellers and is converted into pressure by the diffuser. In contrast to a positive acting pump, a centrifugal pump does not pump the same volume at all times. Centrifugal pumps are best suited for low- to medium-pressure applications. The most common type of pump in use throughout the world is the centrifugal pump. It is a very simple and straightforward piece of work, which is well described and carefully tested. There are many advantages to this pump, including its strength, efficiency, and affordability.

Equipment for Pressurizing Fluids

107

FIGURE 4.1  An internal view of a centrifugal pump.

There is a category of pumps referred to as “special effect pumps” within the classification of “kinetic pumps.” In the case of a special effect pump, the norms of energy expansion are still kinetic, which is the addition of velocity; however, the impacts are different from those of a refined centrifugal pump. This paragraph describes three types of special effect pumps: gas lift pumps, jet pumps, and electromagnetic pumps. Gas (air) lifts are devices that use compressed air to raise liquids. Formerly, they were widely used for pumping wells, but they have become less common since the development of efficient centrifugal pumps. Compressed air is introduced into the liquid near the bottom of the well in order to operate it. Since air and liquid are lighter than liquid alone, the mixture rises in the well casing. The advantage of this pumping system lies in the fact that there are no moving parts within the well. Pumping equipment consists of an air compressor, which can be installed on the surface. A jet pump is a liquid-handling device that uses the momentum of one liquid to move another. Using electromagnetism, electromagnetic pumps move liquid metal, molten salt, brine, or other electrically conductive liquids. It is necessary to set up a magnetic field at right angles to the direction in which the liquid moves, and to pass a current through it. An electromagnetic force moves the liquid.

108

Equipment and Components in the Oil and Gas Industry

As we have explained previously, a positive displacement pump moves a fluid by repeatedly enclosing a fixed volume and mechanically moving it. There are many ways to drive these pumps, including pistons, screws, gears, rollers, diaphragms, and vanes. Positive displacement pumps are, in principle, self-priming. A self-priming pump is a type of fluid pump that requires a liquid to be placed within the cavity or body of the pump in order to begin pumping. A design feature such as this provides an opportunity for process plants to increase their operating efficiency. A constant supply of fluid in the pump body enables the pump to better cope with “air pockets,” which are accumulations of air bubbles within the pump’s operating mechanism that can interfere with its proper operation. Despite the wide variety of pump designs, the majority can be classified into two general categories: reciprocating and rotary. In a reciprocating positive displacement pump, motion is generated by the repeated back-and-forth movement (strokes) of pistons, plungers, or diaphragms. Reciprocation is the term used to describe these cycles. Piston reciprocating pumps (see Figure  4.2) operate by creating a vacuum, opening the inlet valve, closing the outlet valve, and drawing fluid into the piston chamber (the suction phase). When the piston reverses its movement, the inlet valve, now under pressure, closes, and the outlet valve

FIGURE 4.2  A piston reciprocating pump.

Equipment for Pressurizing Fluids

109

opens, releasing the fluid contained within the piston chamber (the compression phase). A simple example is the bicycle pump. There are also double-acting piston reciprocating pumps with inlet and outlet valves on both sides. On one side of the piston, the piston is in suction; on the other side, the piston is in compression. Depending on the size of the cylinder, a piston reciprocating pump can move a certain amount of fluid. The operation of plunger reciprocating pumps (see Figure 4.3) is similar to piston pumps. In order to maintain the pumping action and to prevent leaks, the seal around the piston or plunger is essential. The seal around a plunger pump is generally easier to maintain since it is stationary at the top of the pump cylinder, as opposed to the seal surrounding a piston, which continuously moves inside the pump. To move fluid, a diaphragm reciprocating pump (see Figure 4.4) uses a flexible membrane instead of a piston or plunger. Pumping chamber volume is increased by expanding the diaphragm and fluid is drawn into the pump. By compressing the diaphragm, some fluid is ejected, and the volume is decreased. Pumps with diaphragms have the advantage of being completely sealed, making them ideal for the pumping of hazardous fluids. A reciprocating pump’s cyclical action creates pulses in the discharge as the fluid accelerates during the compression phase and slows during the suction phase. As a result, damaging vibrations can occur within the installation, so it is often necessary to dampen or smooth out the vibrations. It is also possible to minimize pulses by using two (or more) pistons, plungers, or diaphragms, one in a compression phase and the other in a suction phase. Reciprocating pumps are ideal for applications requiring accurate metering or dosing due to their repeatable and predictable operation. It is possible to measure the volume of the pumped fluid by altering the stroke rate or length of the pump. Rotary pumps are a type of positive displacement pump where, for each revolution, a fixed volume of fluid is moved. A rotary pump is a device that uses rotating vanes or gears to move fluids or gases by trapping pockets of the fluid or gas and moving them from one side of the pump to the other. The rotary pump is used in a variety of applications, including oil and gas production, chemical processing, and water and wastewater treatment. It is a reliable and efficient device for moving fluids and gases in a controlled and consistent manner. The rotary pump is widely used for pumping high-viscosity liquids such as oil, including lube oil

FIGURE 4.3  A plunger reciprocating pump.

110

Equipment and Components in the Oil and Gas Industry

FIGURE 4.4  A diaphragm reciprocating pump. (Courtesy: Shutterstock)

and fuel oil. Different types of rotary pumps exist, including vane pumps, flexible member pumps, screw pumps, gear pumps, and lube pumps. A rotary vane pump is a type of positive displacement pump that consists of vanes mounted on a rotor rotating inside a cavity (see Figure 4.5). In some cases, the vanes may be adjustable in length or tensioned in order to maintain contact with the walls as the pump rotates. In its simplest form, a vane pump has a circular rotor that rotates within a larger circular cavity. There is an offset between the centers of these two circles, which causes them to be eccentric. A slot has been cut into the rotor to accommodate the vane. In these slots, the vanes are permitted to move within a certain range of motion so that they can maintain contact with the cavity wall as the rotor rotates. During a rotation cycle, the volume between adjacent vanes changes due to the eccentric mounting of the rotor. The pumping action is created as a result of this. The vane pump is an excellent choice for pumping low- to medium-viscosity liquids, including those containing entrained gases, and is capable of giving an output that is accurate, smooth, and low in pulsation. The vane pump will continue to provide a constant flow regardless of the feed pressure. It is noteworthy that they have good suction characteristics over the lifetime of the pump, are easy to maintain, and require little maintenance. There is no internal metal-to-metal contact and no internal wear. A vane pump has the

Equipment for Pressurizing Fluids

111

FIGURE 4.5  Schematic of working principle of a vane pump.

primary disadvantage of decreasing efficiency with increasing fluid viscosity, so it is not suitable for liquids with high viscosities. In summary, a vane pump is a type of positive displacement rotary pump. This pump consists of vanes mounted radially on a cylindrical rotor that is eccentrically positioned within the pump casing. A close seal is maintained between the vanes and the casing wall. During a rotation cycle, the volume between adjacent vanes changes due to the eccentric mounting position, creating suction at the inlet of the pump and compressing and releasing the enclosed fluid at the outlet. The flexible member pump (also known as a flexible vane pump or flexible impeller pump) (see Figure 4.6) operates in a similar manner to vane pumps; however, the vanes bend rather than sliding. A flexible impeller pump is composed of a rotating rubber impeller attached to supple vanes that maintain contact with the inner walls of the pump. In light of the fact that the casing is actually smaller than the vanes, the vanes must bend and then straighten as the impeller turns in order to conform to the internal walls of the pump. This vacuum is created by the movement of these vanes, which pushes the fluid from the inlet to the discharge pipe. Each vane is enclosed within a chamber, which is created by the space between it and the pump casing. Thus, the flexible impeller pump head consists of several chambers, each of which operates as a valve. Generally, screw pumps are positive-displacement pumps in which solid or liquid fluids are moved along the axis of the screw(s). High- or low-viscosity fluids are transferred along an axis by screw pumps using one or more screws that rotate axially clockwise or counterclockwise. During each cycle, the thread of each screw carries a specific volume of fluid to the center of the pump, where it is discharged. In order to reduce leakage and wear, the screws are designed to fit the shape of the housing. Screw pumps are used in a wide range of applications, including oil and gas production, industrial processes, and water treatment. They are often preferred to other pumps due to their high efficiency, low maintenance,

112

Equipment and Components in the Oil and Gas Industry

FIGURE 4.6  Schematic of working principles of a flexible member pump.

and reliability. Screw pumps are also capable of pumping viscous liquids, making them well suited for a variety of tasks. The screw pump is the oldest positive displacement pump. It is derived from the Archimedes screw, which was invented in Greece in the 3rd century BC to move water for irrigation by utilizing a single screw that fitted into a cylinder with minimal clearance. At least two screws are used in most screw pumps today. A screw pump is shown in Figure 4.7. Single screw pumps, also known as eccentric screw pumps or progressive cavity pumps, contain a single pumping element (screw), which rotates inside a stationary stator. A set volume of fluid is sealed by direct contact between the screw and the stator with each turn of the screw. Stators are shaped in a manner that corresponds to the outer surface of screws. The stator is the stationary part of a rotary system. Due to the interference fit between the screw or pumping element and the flexible stator, this pump can handle a wide range of fluid characteristics, including high solids and variable viscosities. In spite of this, interference fits require the stator material to be lubricated and cooled. The term “two screw pump” (see Figure 4.8) refers to a screw pump with two shafts. In addition, a twoscrew pump may also be considered a four-screw pump if it has a double suction design (two opposing sets of screws pumping towards the discharge). A  screw pump is composed of two counter-rotating screw rotors that are engineered to rotate towards each other. Liquid is trapped in the space between the screws of the rotors as a result. The trapped volume decreases as the screws rotate, which moves the liquid towards the exhaust.

Equipment for Pressurizing Fluids

113

FIGURE 4.7  A screw pump. (Courtesy: Shutterstock)

FIGURE 4.8  A double screw pump.

The gear pump (see Figure 4.9) is a positive displacement (or fixed displacement) pump that pumps a constant amount of fluid per revolution. These gears are composed of at least two separate and rotating gears with interlocking teeth. A  partial vacuum is created by the separation of these meshed teeth, which is filled by the fluid being pumped. In the process of rotating the gears, the fluid becomes trapped and is carried around the casing of the pump to the discharge side. The fluid is ejected from the gear teeth as the teeth begin to reconnect, resulting in a pumping action. Due to the fact that a gear pump does not have to generate centrifugal force, it can be operated at a much lower speed. As a result, it

114

Equipment and Components in the Oil and Gas Industry

FIGURE 4.9  A gear rotary pump.

FIGURE 4.10  A rotary lobe pump. (Courtesy: Shutterstock)

becomes smoother and easier to control. An important advantage of gear pumps is that they are self-priming. It is possible for their discharge pressure to be very high, depending on a number of factors. Pumps with rotary lobes (see Figure 4.10) are positive displacement pumps in which two or more lobes rotate around parallel shafts inside the pump’s body to

Equipment for Pressurizing Fluids

115

move fluid. As opposed to gear pumps, these pumps do not have physical contact between their lobes, a feature that provides some distinct advantages when pumping certain types of materials. In operation, the shafts with which the lobes are mounted rotate in opposite directions, creating and collapsing cavities within the pump’s body and moving products from the pump’s inlet port around the outside of the pump’s lobes until they reach the outlet port. Lobe pumps can move solids suspended in slurries due to the fact that their lobes do not come into contact with each other. Compared to other types of positive displacement pumps, they are capable of handling larger-sized particles. In general, these pumps are highly efficient at pumping very viscous liquids and are easy to maintain.

4.2.2 Pumping Terms 4.2.2.1 Pumping Head and Characteristics In view of the dynamic nature of the pump, it is more convenient to consider the pressure in terms of head or in terms of meters of liquid column. The pump generates the same head of liquid regardless of the density of the liquid being pumped. The pressure at any point in a liquid can be viewed as being caused by a vertical column of the liquid, which exerts a pressure equal to the pressure at the point in question, due to its weight. Static head refers to the height of this column and is expressed in terms of feet of liquid. In order to calculate the static head associated with any specific pressure, it is necessary to know the weight of the liquid. Centrifugal pumps impart velocity to liquids. As the liquid leaves the pump, much of this velocity energy is converted into pressure energy. Therefore, the head developed is approximately equal to the velocity energy at the impeller’s periphery. Generally, the purpose of a pumping system is either to transfer a liquid from one place to another, such as filling a high-level reservoir, or to circulate liquid throughout a system, such as use in heat exchangers. In order to make the liquid flow at the required rate, a pressure must be applied that overcomes the head losses in the system. There are two types of losses: static losses and friction losses. Gases and liquids are delivered by pumps. Typically, these fluids are pumped from a lower level to a higher level. Between these two levels is the pump. During the suction phase of the pump, a negative pressure is created, which causes the fluid to be sucked in by the pump. As a result, the fluid is placed under high pressure by the pump. The fluid is now pushed through the pipe to the higher level at the outlet. The static head is simply the difference between the heights of the supply and destination reservoirs, as shown in Figure 4.11. Based on the mechanical power transferred to the fluid at a given volume flow rate and density, the static head, static pressure head, or pressure head of a pump would be the maximum height it could deliver. Pump power, fluid density, and volume flow rate are all factors that affect the difference in height that a liquid can overcome. It is important to note that the static head of the pump does not take into account friction losses inside the pipe or pressure losses caused by valves, bends, fittings, and so on. These losses cannot be directly attributed to the pump but rather to

116

Equipment and Components in the Oil and Gas Industry

FIGURE 4.11  An illustration of the static head.

the piping system in which the pump will be installed. Due to the fact that pump manufacturers are not aware of the operating conditions of the pump, they cannot account for such losses anyway. As a result, such pressure losses are taken into account by a process called friction loss. The friction loss or head (sometimes referred to as dynamic head loss) refers to the friction loss caused by the moving of liquid through pipes, valves, and other equipment in a system. There are friction tables available for a wide variety of pipe fittings and valves. According to these tables, friction loss per 100 feet (or meters) of a specific pipe size is shown at varying flow rates. If the liquid is being moved through fittings, friction loss occurs in pipes, valves, and equipment of the same size. There is a direct relationship between friction losses and flow rate squared. Pumps have three additional head definitions: suction head, which refers to the pump’s inlet pressure above atmospheric pressure (see Figure 4.11). Suction head can be negative or positive. A  negative suction head is a condition of negative pressure or vacuum that occurs when the pump outlet is at the same level or above the storage so that the liquid is lifted up by the suction of the pump. The positive suction head in a pump occurs when the pump inlet is below the liquid level, causing the liquid to be drawn into the pump by gravity. In operation, the discharge head (see Figure 4.12) measures the pressure at the pump’s outlet, while the total head measures the pressure difference between the pump’s inlet and outlet. The suction head is the most important head definition, as it determines the pump’s efficiency, power requirement, and flow rate. The other two head definitions are used to determine the pump’s capacity and discharge pressure. It is necessary to know three things in order to calculate the total head requirement: static head, pipe friction loss, and discharge pressure. By adding up these

Equipment for Pressurizing Fluids

117

FIGURE 4.12  An illustration of suction, discharge, and static heads for a pump.

three factors, you will be able to calculate the total system head requirement in meters. 4.2.2.2 Pump Capacity Pump capacity refers to the flow rate through a pump under its intended operating conditions. The amount of liquid that can be pumped through the pump in a given period of time is described by this parameter. Therefore, pump capacity refers to the rate at which the pump can move fluid through its system. In most cases, capacity (Q) is expressed in gallons per minute (gpm). As liquids are essentially incompressible, the capacity of a pipe directly correlates with the velocity of the flow. Equation 4.1 (pump capacity calculation) provides the following relationship:

Q = 449 × A × V (4.1)

where: A = area of pipe or conduit in square feet. V = velocity of flow in feet per second. Q = capacity in gallons per minute. 4.2.2.3 Pump Power and Efficiency During a given period of time, the amount of work that is performed by a pump is determined by the total head and the weight of the liquid pumped. It is more common to use the pump capacity in gpm and the specific gravity of the liquid in formulas rather than the weight of the liquid itself. Pump input or brake

118

Equipment and Components in the Oil and Gas Industry

horsepower (bhp) is the actual force applied to the pump shaft. A  pump’s output, or hydraulic horsepower (whp), is its capacity to deliver liquid horsepower. It can be said that pump efficiency refers to the efficiency with which a pump converts the useful energy from a hydraulic power source into the output of the pump. For example, if an electric motor were to provide X amount of energy to a machine, and the output were half of X, then the machine would be 50% efficient. There are many ways in which a pump can waste energy, including excessive noise or the generation of heat. Noise and heat are not desirable forms of energy for a pump transferring fluid from one point to another, so we consider them “wasted” sources of energy. Simply put, a more efficient pump will save you money. Inefficient pumps waste energy when moving fluid in a system, resulting in increased electricity costs. It is also important to consider maintenance costs; an inefficient pump will wear quicker than an efficient pump, resulting in a loss of revenue income (because the pump is not functioning, stopping production), a greater amount of labor and time required to get the pump up and running, and an increased number of spare parts required annually for pump repairs. Pump efficiency is not a constant value, but rather depends on the volume flow rate! Due to turbulences and the associated flow losses, the efficiency first increases with increasing flow rate, and then decreases again from a maximum point. A pump’s maximum efficiency is typically between 70% and 90%. 4.2.2.4 Pump-Specific Speed A specific speed (Ns) is a non-dimensional design index that is used to categorize pump impellers according to their type and proportion. As a result, pump-specific speed is applicable to centrifugal pumps. It is defined as the revolutions per minute at which a geometrically similar impeller would operate if it were of such a size as to deliver 1 gallon per minute against 1 foot of head. Nevertheless, the understanding of this definition has only design engineering significance, and specific speed should only be considered an index used to predict certain characteristics of a pump. Equation 4.2 (pump-specific speed) is used to calculate the pump-specific speed. Ns =

N Q 3 H 4 

(4.2)

where: N = pump speed in RPM. Q = capacity in gpm at the best efficiency point. H = total head per stage at the best efficiency point. When selecting a pump for a particular application, knowing the shaft speed, flow, and differential head, calculating specific speed will identify the impeller shape that is best suited to the application. The specific speed determines

Equipment for Pressurizing Fluids

119

FIGURE 4.13  Impeller design vs specific speed.

the general shape or class of the impeller, as shown in Figure 4.13. As the specific speed increases, the ratio of the impeller outlet diameter, D2, to the inlet or eye diameter, D1, decreases. In the case of a true axial flow impeller, this ratio becomes 1.0. In the case of a radial flow impeller, head is primarily generated by centrifugal force. A pump with a higher specific speed develops head primarily as a result of centrifugal force and primarily as a result of axial force. High specific speeds indicate a pump design in which head is generated more by axial forces than by centrifugal forces. In axial flow or propeller pumps with a specific speed of 10,000 or greater, the head is generated exclusively by axial forces. An axial flow impeller has a high flow rate but a low head rate, whereas a radial flow impeller has a low flow rate but a high head rate. 4.2.2.5 Pump Performance Curve In general, pump performance curves are used to identify or predict changes in the process parameters (flow, differential head, efficiency, power consumption, etc.). These curves represent a relationship between the different operating parameters of the pump. Pump performance curves can be obtained and designed by the original equipment manufacturer (OEM). Pump performance curves are required when selecting a pump, troubleshooting a pump, and maintaining a pump. These curves allow engineers to calculate the most efficient operation of the pump. They are also useful for designing pump systems, as they allow engineers to determine the necessary parameters for the system to work properly. Pump performance curves can also be used to identify potential problems in a pump system, such as cavitation or suction or discharge piping problems. Cavitation will be explained later in this chapter. Additionally, they can help to identify the proper size pump for a system. Figure 4.14 shows an example of a centrifugal pump performance curve illustrating different characteristics of centrifugal pumps. There is no doubt that the head versus capacity curves are the most important aspects of pump performance. The head versus capacity curves are illustrated with diameter markings (8.88 min. dia.; 9.88 dia.; 10.50 dia.; 10.88 max. dia.). It is possible to fit centrifugal pumps with impellers that have different diameters while using the same size

120

Equipment and Components in the Oil and Gas Industry

FIGURE 4.14  Pump performance curve.

casing. As a result of this practice, the pump is flexible enough to be adapted to a change in service. A larger impeller can be installed on a pump if a change in operating conditions requires that the head be increased. Pumps are normally purchased with an impeller somewhere in the middle of the possible range of impeller sizes. When the impeller diameter is known, the head versus capacity curves illustrate the pump head (total dynamic head) at a known flow rate (US gallons per minute). A mechanical engineer can interpret the curve by referring to the flow rate (for example, 600 gpm) at the curve for the diameter of the installed impeller (for instance, the 10.50 dia. curve) and by reading the value of the head on the left side of the graph (for example, 475 feet). Figure  4.14 illustrates the efficiency versus capacity curves superimposed on top of the head versus capacity curves, corresponding to 73, 75, 77, 78, and 79. The efficiency of a pump can be determined from the curves of its capacity and diameter when these parameters are known. A best efficiency point (BEP) is defined as the point at which efficiency is at its peak. It is recommended that the BEP be near the design operating point for the pump, but the design operating point should never exceed 110% of the pump’s BEP. 4.2.2.6 Net-Positive Suction Head and Cavitation Pump net positive suction head (NPSH) is the amount of pressure, measured in feet or meters, that is available to drive a liquid into a pump. Pump design determines the amount of NPSH required. As the liquid passes from the pump

Equipment for Pressurizing Fluids

121

suction to the impeller eye, the velocity increases and the pressure decreases. As the liquid strikes the impeller, there are also pressure losses due to shock and turbulence. Through the centrifugal force generated by the impeller vanes, the liquid’s velocity is further increased and its pressure is decreased. The NPSH required is the positive head in feet absolute required at the pump suction in order to overcome these pressure drops in the pump and maintain the majority of the liquid above the vapor pressure. It is important to note that the NPSH required varies depending on the pump’s speed and capacity. This information can usually be found in the curves provided by the pump manufacturer. Without enough NPSH, pumps may cavitate, leading to reduced efficiency and potential damage. It is important to calculate NPSH before selecting and installing a pump. It is important to know the system’s NPSH requirements and the NPSH available to ensure a successful pump installation. The available NPSH should be greater than the NPSH required to avoid cavitation. If the two values are close, it is recommended to select a pump with a greater NPSH margin. Additionally, the pump should be installed in a location where the suction line is as short and direct as possible. If necessary, the suction line should be optimized to reduce the friction losses of the fluid. Finally, a suitable suction strainer should be used to ensure the pump is not damaged by debris. It is also important to check the NPSH values regularly to ensure the pump is working optimally. The pump should also be inspected and maintained regularly to ensure it remains in good condition. In centrifugal pumps, cavitation is a common problem. It is possible that your pump is experiencing cavitation if you hear strange noises coming from it. However, what is cavitation? What can you do to prevent it? Cavitation refers to the formation and accumulation of bubbles around the impeller of a pump. When liquids of any viscosity are transported through or around a pump system, bubble vapor can be formed from the liquid due to pressure drops. A high-energy shock wave is created inside the liquid when each of these tiny bubbles collapses or bursts. It is possible for this shock wave to cause damage to the pump as well as the surrounding piping and valves. The pump should be operating at the correct flow rate, pressure, and temperature in order to prevent cavitation. Increasing the pressure upstream of the pump’s impeller is the best way to prevent cavitation from occurring. In technical terms, this pressure is known as the net positive suction head. It is important to maintain the correct NPSH to prevent cavitation from occurring. If cavitation is present, it can cause serious damage to the pump and the surrounding equipment. Regular maintenance should be done to ensure the NPSH is at the correct level.

4.2.3 Pump Parts The construction of a pump’s components may be the most important factor affecting its performance. By understanding these basic principles, you can ensure that your pumps function effectively and efficiently for a long time to come.

122

Equipment and Components in the Oil and Gas Industry

1. Casing: Pump casing refers to the exterior shell of the pump. It must be able to seal off the interior of the unit from the exterior in terms of pressure and fluids. Pump casings are constructed differently depending on the type of pump. The purpose of pump casings is to seal the inside of the pump from the atmosphere in order to prevent leakage and to maintain the pressure inside the pump. Casing type can have an important impact on pump dependability (mean time between repairs) and, to a lesser extent, pump efficiency when pump flow rates are at or below the best efficiency point. Hence, choosing the right types of pump casings is very important in pumping, piping, and plumbing systems. 2. Shaft: Another important component of the pump is the shaft, which transmits power from the motor to the moving parts inside the pump housing. In order to maximize performance, most pumps have either a straight shaft or an offset shaft. A pump’s shaft shape plays a significant role in its efficiency, as it affects the flow of energy from the motor to the pump. The type of shaft used will be determined by the type of pump and the application for which the pump will be used. If the shaft is selected incorrectly, efficiency can be reduced and wear can be increased. In most cases, shafts break as a result of operational or system problems. The most common cause of pump shaft fractures or failures is fatigue failure (also known as reversed bending fatigue with rotation). Shafts of pumps should be inspected regularly for signs of wear, and if any signs of fatigue or damage are observed, they should be replaced as soon as possible. In order for a pump to operate efficiently and last a long time, proper shaft selection is crucial. Maintaining and inspecting pump shafts regularly is essential to preventing failures. 3. Impeller: An explanation of the impeller has already been provided in this chapter. Pump design is centered around the impeller, which is the most important component. The pump plays a crucial role in moving water or other fluids through the system by producing a pumping action. It is the shape, size, and design of the impeller that determine the performance of a pump. The impeller is usually made of metal, although some are made of plastic or other materials. The design of the impeller affects the efficiency of the pump, as well as the speed and volume of the flow. Therefore, it is important to choose the right impeller to ensure that the pump works as expected. The impeller should also be robust enough to withstand the operating conditions, such as pressure and temperature. Last, it should be easy to repair and maintain. The impeller should also be corrosion resistant, as corrosion can significantly reduce its service life. Additionally, the size of the impeller should be suitable for the pump, as an impeller that is too large or too small can result in reduced efficiency. 4. Suction and discharge nozzles: A pump suction nozzle is the cross-­ section (circular cross-section) that defines the boundary between the suction side of the pump system and the pump itself (inlet cross-­section)

Equipment for Pressurizing Fluids

123

at the inlet side of the pump casing. As a result of the suction nozzle, fluid is drawn into the pump housing in order to be pressurized and moved throughout the system. It is common for nozzles to have a specific shape that optimizes flow rate, efficiency, and other performance characteristics; however, they can also be highly customized to suit a variety of applications. The design of the nozzle is important in order to ensure that the pump serves its intended purpose. As a boundary between the discharge-side section of the pump system and the pump, a pump discharge nozzle is a cross-section (circular cross-section) defined at the pump casing’s outlet side (see outlet cross-section). Pump discharge nozzles control the direction and velocity of the pressurized water being pumped out of the system, which directly affects the amount of force applied to whatever needs to be moved. As a result, specific details of the pump design should be taken into account when choosing a discharge nozzle type. In order to maximize the efficiency of the pump, it is important to consider the size, shape, and material of the discharge nozzle. 5. Sealing: In any pump design, the seal protects the internal components from damage or overheating by preventing fluid from entering the shaft housing area. Moreover, it prevents contaminants from entering the pump and maintains a vacuum within the chamber of the pump. The proper sealing of the pump ensures that it operates at maximum efficiency as well. It is essential to use the correct sealing for the pump in order to ensure that it operates properly. In order to ensure proper operation, seals should also be lubricated on a regular basis. It is important to maintain and inspect the seals on a regular basis in order to ensure that they are functioning properly. It is recommended that seals be replaced on a regular basis to ensure proper operation. In this manner, any unexpected failures of the pump will be prevented and unnecessary downtime will be avoided. To ensure a tight seal, the right type of sealant should also be used. It is the purpose of mechanical seals for pumps to separate two environments from one another, so that no fluid communication can occur between them. As part of the sealing process for centrifugal pumps, the challenge is to allow a rotating shaft to enter the “wet” area of the pump without allowing large quantities of pressurized fluid to escape. In order to address this challenge, there needs to be a seal between the shaft and the pump housing that can withstand the friction caused by the shaft rotating as well as the pressure of the process being pumped. The stationary part of the seal is fitted to the pump housing with a static seal, which may be sealed with an o-ring or gasket. Gland packing is one such method that is still widely used. Gland packing consists of braided, rope-like materials that are stuffed around the shaft in order to fill the gap between the shaft and the pump housing. Over time, the friction of the shaft rotating wears away the packing, resulting in increased leakage until it is adjusted or repacked. As a result of the packing being pressed

124

Equipment and Components in the Oil and Gas Industry

against the shaft in order to prevent leakage, the pump requires more drive power to turn the shaft, thereby wasting energy. A thin film of fluid is maintained between the seal faces in most mechanical seals in order to prevent wear on the faces. It is possible for this film to originate either from the process fluid being pumped or from external sources. 6. Bearings: A bearing is a small component of a pump system that plays a critical role. As a result, they bear the load of the pump and allow the shaft to rotate. In addition to allowing rotation of the pump shaft, bearings also prevent side movement and deflection of the shaft under load. Keeping them properly lubricated and monitoring their temperatures is critical to preventing failure. Bearings used in modern pumps are typically either ball bearings or roller bearings, which differ in their durability, efficiency, and other characteristics. 7. Couplings: Pump couplings are used to connect the rotating pump shaft to the motor’s drive shaft. They enable the motor to transmit power efficiently to the pump. In the case of a close coupled pump, a separate coupling is not required since the motor is mounted directly to the pump on a single shaft. As a result, the coupling acts as an intermediary between the motor and pump shaft in order to allow them to rotate together without slipping or causing excessive vibration or noise. It is common for couplings to be made from plastic, rubber, or metal, and their shapes and sizes vary according to their intended use. 8. Check valve: There is no check valve inside the pump, but it is installed after the pump as a one-way valve that prevents water from flowing back into the pump housing after it has been discharged. This is an important safety feature that safeguards the pump from damage and ensures that it continues to function correctly at all times.

4.3 COMPRESSORS Compressors are mechanical devices that increase the pressure of gases by reducing their volume. An air compressor is a type of gas compressor. Compressors are similar to pumps in that they both increase pressure over fluids and can transport those fluids through pipes. There is a major difference between a compressor and a pump in that a compressor is designed primarily to change the density or volume of a fluid, which is generally only possible with gases. As gases are compressible, but liquids are relatively incompressible, compressors are rarely used to compress liquids. It is the primary function of a pump to pressurize and transport liquids. It is possible to stage many compressors, that is, to compress fluid more than once in several steps or stages in order to increase the discharge pressure. To accommodate the already compressed gas without reducing its pressure, the second stage is often physically smaller than the primary stage. Through each stage, the gas is further compressed, and its pressure and temperature are increased (if intercooling is not used between stages). There are many essential aspects of the oil and gas industry that require proper compressor equipment. Compressors are

Equipment for Pressurizing Fluids

125

used to transport gas over long distances, as well as to store and pressurize them. They are also used to maintain pressure in pipelines and other related equipment. Compressors are an essential part of the oil and gas industry. Compressors are also used in natural gas processing, with the aim of reducing the volume of the gas and separating it into different components. In addition, compressors are used to reduce the volume of gas prior to transportation. In order to design a compression system, a fundamental understanding of gas behavior and equations of state is necessary. The behavior of an ideal gas is expressed by Equation 4.3 (ideal gas behavior equation): where: p V n’ T RO

pV = n′ RO T = = = = =

(4.3)

absolute pressure, psia. volume, ft3. number of moles. absolute temperature, °R. Universal gas constant, ftlb/lbmole °R.

In compressor calculations, it is necessary to take into account that all gases deviate from the ideal gas laws. Pressure, volume, temperature (PVT) properties of a real gas can be calculated using equations or states or by introducing compressibility factors into the ideal gas equation. A compressibility factor, Z, is derived by determining the compressibility of a gas or vapor experimentally. A simple equation to account for real gas behavior is given by Equation 4.4 (real gas behavior equation):

pV = n′ ZRO T

(4.4)

Note that the Z factor varies with temperature and pressure.

4.3.1 Types of Compressors The two basic types of compressors are dynamic, which includes radial (centrifugal) and axial flow compressors, and positive displacement, which includes reciprocating and various types of rotary compressors. Dynamic compressors produce nearly constant pressure with variable volumetric flow, whereas positive compressors move constant volumes of gas with variable outlet pressures. There are several types of compressors, but the most common is the dynamic compressor. In a dynamic compressor, air or gas is continuously passed through a rotating element and pressed onto the rotating element and partly on the diffuser or fixed pallets in order to influence the speed of the head part. Dynamic compressors, in contrast to positive displacement compressors, operate at constant pressure and are classified according to their axial or radial design. In addition to variations in the inlet temperature, the surrounding environment can interfere with the performance of this compressor. When air is compressed dynamically, it is drawn

126

Equipment and Components in the Oil and Gas Industry

into the blades of the compression driver, which rotate rapidly as they accelerate. Following the discharge of the gas, the force of the movement is converted into static pressure by the diffuser. Axial or radial compressors are designed to handle large volumes of air flow, depending on the initial direction of the airflow. Due to their ability to generate significant horsepower, dynamic compressors are often referred to as turbochargers. There are two types of dynamic compressors: centrifugal and axial. Centrifugal compressors are characterized by their radial discharge flow. Rotating blades on an impeller draw air into its center. Due to centrifugal forces, it is pushed out towards the perimeter of the impeller. As the air moves radially, it generates kinetic energy as well as a rise in pressure. The term centrifugal describes the movement of a medium, in this case air, from an axial direction to a radial direction by centrifugal force. The direction is changed by 90°. A centrifugal compressor imparts velocity and pressure to a flowing medium by rotating continuous flow impellers. With the aid of a diffuser, the flow direction of the air is changed by 90° a second time after the air exits the tip of the impeller. An intercooler and moisture separator are then used to cool the air. Some machines turn the air 180° and direct it through the inlet section of the next impeller through the center of the next diffuser. This is the process by which kinetic energy is converted into pressure. Figures 4.15 and 4.16 illustrate a centrifugal compressor used in the oil and gas industry. How many stages are required is determined by the design condition requirements. The majority of 100–150 psi machines are usually divided into two to four stages with intercooling. Multistage compressors are designed in such a way that each stage shares the work equally. Therefore, each stage passes the same mass at the same compression rate. Each stage contributes to the overall pressure rise of the compressor unit. In industrial machinery, the maximum pressure ratio of a centrifugal compressor stage is usually not greater than 3. The efficiency of the stage is reduced by higher pressure ratios. There is the possibility of inter-cooling in multi-stage applications in order to reduce the power consumption. On a single, low-speed shaft, multiple stages can be arranged in series. In the oil and gas industry or in the process industry, this concept is often employed. To achieve the desired pressure, a large number of stages and/or multiple compressor sets are required because the pressure ratio per stage is low. A high-speed gearbox is integrated with the compressor stages to rotate the impellers on high-speed pinions in air compression applications. In purchasing a centrifugal pump, we always look for one that is highly efficient, requires minimal maintenance, and is reliable. There are many factors to consider when selecting a centrifugal pump, but one that many people overlook is selecting the appropriate impeller style. There were previously two categories of impellers, open and closed. Nevertheless, there is now a third type available as well. Semi-open impellers are referred to as such. The impeller of a centrifugal pump is a rotating blade with a curved shape. By spinning them at high speeds in a circular motion, the blades increase the pressure and velocity of the fluids they are pumping. Most impellers are either open or closed, depending on the design;

Equipment for Pressurizing Fluids

127

FIGURE 4.15  A centrifugal compressor. (Courtesy: Shutterstock)

FIGURE 4.16  A centrifugal compressor.

however, semi-open impellers are also available. Figure 4.17 illustrates all three types of impellers for centrifugal pumps. An open impeller has no cover plate, while a closed impeller has a cover plate. This cover plate helps to increase the pressure of the fluid as it passes through the impeller. This increased pressure is

128

Equipment and Components in the Oil and Gas Industry

FIGURE 4.17  Different types of centrifugal pump impellers.

then used to move the fluid through the system efficiently. The increased pressure also helps to reduce friction between the impeller and the fluid, allowing the system to operate more effectively. Therefore, an open impeller consists of a hub with vanes attached to it and is mounted on a shaft. Impellers that are open are slightly less efficient than those that are closed or semi-closed. Closed impellers are built with additional wall sections on the back and front sides of the vanes, providing greater strength. In addition, this reduces the thrust load on the shaft, increasing bearing life and reliability, as well as reducing shafting costs. Because of this more complex design, closed impellers are more expensive and more difficult to manufacture. The performance of a closed impeller cannot easily be improved by modifying it. Open impellers can be easily modified by cutting the vanes to increase capacity. In the case of a closed impeller, speed options are limited. However, you can choose an open impeller if you want a wide range of specific speeds. Due to their ability to handle volatile and explosive fluids, closed impellers are the most prevalent impellers in the industry. It is necessary for each centrifugal compressor to be sealed in a suitable manner so as to reduce leakage along the shaft at the point where it passes through the compressor housing. There are many types of seals used in compressors, and the most advanced are found on high-speed compressors intended for high pressures. There are several types of seals, including labyrinth seals, ring seals, controlled gap seals (usually graphite seals), and mechanical seals. An axial flow compressor (see Figure  4.18) or, in a shorter form, an axial compressor, is a type of dynamic compressor. The axial flow compressor is a type of air compressor that moves air in a direction parallel to a particular axis. Generally, axial compressors are high-speed, large-volumetric-flow rate machines. As the gas enters the intake ports, it is propelled axially through the compression space by rotating rotor blades and stationary stators (or diffuser blades). As a matter of fact, axial compressors gradually compress gas flow through a series of rotating rotor blades that resemble fans. Flow is redirected onto the next set of rotor blades by stationary stator vanes located downstream of the rotors. The intake of axial flow air or gas compressors begins with a row of stationary vanes. The purpose of this is to ensure that the air or gas enters the compressor uniformly. The rotor increases the speed of air flow in both axial and circumferential directions. A process called diffusion allows the speed of

Equipment for Pressurizing Fluids

129

FIGURE 4.18  An axial compressor.

air flow or its kinetic energy to be converted to static pressure through the stators (some of the pressure rise also occurs in the rotors). As well as acting as a pressure raising agent, each stator row also redirects the flow to be able to enter the next row of rotor blades in a proper direction. Stages of industrial axial flow compressors consist of stators followed by rotors, and each stage may increase the pressure by 5% to 25%. As a result, multiple stages are required for a compressor to achieve high pressure ratios. Positive displacement air compressors are the most common type of industrial air compressors in use today. They draw air or gas into a compression chamber and then reduce the chamber’s size to achieve the desired air pressure. To achieve the targeted reading for compressed air or gas, different positive displacement compressor types employ different mechanical movements. In fact, positive displacement compressors increase air pressure by reducing air volume within a confined space. There are four types of positive displacement compressors: reciprocating piston compressors, rotary screw compressors, rotary vane compressors, and scroll compressors. There are two main types of reciprocating piston compressors: single acting and double acting. In a single-acting piston, air is drawn into the piston and compressed from one side only. The other side of the compressor is exposed to the crankcase. During the downward stroke of the piston, air is drawn in, and it is compressed during the upward stroke. As a result, a single-acting compressor utilizes only one end of the piston for the purpose of sucking and compressing air. Essentially, the first stroke of the piston draws air into the compressor, while the second stroke compresses the air. On the other hand, the piston’s other end is usually free or open. As a result, we are unable to perform any work by the piston’s other end. Consequently, the piston is used only on one side for sucking and compressing purposes. As a reciprocating air compressor, it uses compressed air to push the piston in one direction and spring force to return the piston to its

130

Equipment and Components in the Oil and Gas Industry

original position. There is only one piston in the cylinder of these reciprocating air compressors which provides and discharges pressurized gas or air. Single-acting air compressors operate on a very simple principle, which is described in detail in the following and illustrated in Figure 4.19. Reciprocal compressors consist of intake valves, exhaust valves, cylinders, valves, crankshafts, and pistons. A downward movement of the piston causes the air pressure in the compressor cylinder to fall below the atmospheric pressure. As the piston moves down, the pressure increases and eventually reaches exhaust pressure, causing the inlet valve to open and draw air into the cylinder. When the piston has finished its downward stroke, the inlet valve will close and air will be drawn into the cylinder. In this instance, the outlet valve is opened in order to discharge the air. A P-V diagram plots the pressure of the gas against the volume of the gas trapped in the compression chamber. Figure 4.20 illustrates the P-V diagram for a single-acting piston compressor. Initially, the air is sucked into the compressor cylinder at constant pressure P1, and its volume increases. This suction process is represented in the figure by lines 1–4. The air compression process begins after the suction stroke has been completed. As a result of this process, the air pressure increases from P1 to P2, and the volume decreases from 1 to a value between 1 and 4. At point 2, the pressure P2 is marginally greater than the delivery pressure. This compression process is represented by lines 1–2. At point 2, the compression stroke is complete, and then the delivery stroke begins. It is important to note that during this process, the air pressure remains constant (P2), while the volume increases. Consequently, the outlet valve opens at this point and discharges the compressed air. According to the diagram, this process is represented by lines 2–3. When the delivery stroke is complete, the piston returns for the suction

FIGURE 4.19  Single-acting piston compressor working schematic.

Equipment for Pressurizing Fluids

131

FIGURE 4.20  A P-V diagram for a single-acting piston compressor.

stroke, sucking air once again, and at this point, the cylinder pressure is P1. As a result of the process being repeated, the work completed during this process can be categorized as 1-2-3-4. By compressing the air on both the upstroke and downstroke of the piston, the double-acting compressor doubles the capacity of a given cylinder size. Air compressors of this type are extremely efficient as a result of this “double” compression cycle. An air compressor of this type uses one end of the piston for sucking air and the other for compressing it. In other words, when the piston moves backward, it suckers air, while when it moves forward, it compresses air. During compression, these types of air compressors reduce the volume of air. One of the main differences between single-stage and two-stage compressors is the number of times that air is compressed between the inlet valve and the tool nozzle. A  single-stage compressor compresses the air once, while a twostage compressor compresses it twice for double the pressure. As a result of the double-acting compression, the two-stage compressor produces higher pressure, which makes it more powerful and capable of handling larger projects. In addition to being more expensive, this type of compressor requires a higher level of maintenance. Single-acting compressors have a work efficiency of 22 to 24 kW per 100 cubic feet of air, while double-acting compressors have a work efficiency of 15 to 16 kW per 100 cubic feet of air. Consequently, these compressors consume less and cheaper electricity than a single-acting compressor for the same amount of compressed air.

132

Equipment and Components in the Oil and Gas Industry

It is very simple to understand the working principle of a double-acting reciprocating compressor, illustrated in Figure 4.21. As a result, the double-acting air compressor has a total of four valves, two outlet valves and two inlet valves. Turbines, engines, and electric motors drive the crankshaft. During the compression process of this type of compressor, air is compressed on both sides of the piston. In response to the crank turning, the piston alternates between two positions. Because of the vacuum created by the downward movement of the piston, air enters from one side into the chamber. As the piston moves downward, the air or gas is compressed downward and is discharged from the cylinder. Air is compressed when the piston moves up. When the piston reaches a specific point in the upward direction, the air stroke and compression process are also completed. As soon as the air has been fully compressed, it is released through the outlet valve. A vacuum is created on the opposite side of the piston

FIGURE 4.21  A double-acting piston compressor.

Equipment for Pressurizing Fluids

133

during the upward movement of the piston, which causes air or gas to be drawn into the piston. It is important to note that rotary compressors are a subset of positive displacement machines. The construction of rotary compressors differs from that of piston compressors; however, they share a number of features. In contrast to reciprocating compressors, rotary compressors do not utilize valves to move gas through the machine. Considering that these compressors do not reciprocate, they do not have pistons or crankshafts. Instead, these compressors use screws, scrolls, and other rotating devices to compress air. There are several types of rotary compressors, such as screw compressors, lobe compressors, scroll compressors, and others. There are more advantages to using a rotary compressor than disadvantages. Rotary compressors can operate continuously, while reciprocating compressors must operate at a minimum duty cycle of 60%. Rotary screw compressors are also quieter than reciprocating compressors. Additionally, they produce cooler air that is easier to dry. In addition, rotating compressors have several advantages over reciprocating compressors, including being lighter in weight, experiencing less vibration, and not requiring heavy foundations. The rotary screw compressor is one of the most widely used technologies in modern industrial machinery. When low air pressure is required, screw compressors are highly efficient. A pair of screws rotate, intermeshing with each other, as illustrated in Figures 4.22 and 4.23, trapping air between them and the compressor casing, forming pockets that get squeezed and delivered at a

FIGURE 4.22  A screw pump.

134

Equipment and Components in the Oil and Gas Industry

FIGURE 4.23  Side and top views of a screw pump.

higher pressure, which opens a delivery valve. In comparison with a reciprocating compressor, compressed air is continuously delivered and operates quietly. Rotary screw compressors compress air by rotating the screw. There are two rotors within the compressor, one male and one female. By designing them differently, they will be able to trap air between them when turned together. As the male rotor has curved blades and the female rotor has curved cavities, they can mesh together without touching to achieve compression. Additionally, the male rotor will have slightly fewer lobes (blades) than the female, meaning it will rotate more quickly, effectively driving the female rotor. In addition to being the technology of choice for a variety of applications, screw compressors offer a number of benefits to customers. 4.3.1.1 Continuous Operation There is no need to switch them on and off, and no duty cycle is required. They are capable of continuous airflow and pressurization. In other words, they are capable of operating continuously with little or no downtime. 4.3.1.2 Easy to Maintain Since there are very few moving and contacting parts, wear and tear are minimized. As a result of long service intervals, maintenance costs are reduced, and routine checks and repairs can be carried out quickly, easily, and without any hassle. 4.3.1.3 Powerful Performance Due to their high airflow rates and ability to operate at extreme temperatures, screw compressors are able to operate in challenging conditions. 4.3.1.4 Energy-Efficient These durable machines have stood the test of time and produce less heat and consume less energy than other models. Their design features ensure that they will not lose capacity over time, which lowers their lifetime costs.

Equipment for Pressurizing Fluids

135

4.3.1.5 Low Noise The small size of the units and the lack of moving parts allow for quiet operation, making them ideal for installation at the point of use. Rotary vane compressors, also known as sliding vane compressors, are positive displacement compressors found in a variety of industries. Since their invention in the late 19th century, they have been around for quite some time, and maybe this explains why they are so prevalent. Rotary vane compressors, as their name implies, have a rotor. Cylindrical rotors are mounted eccentrically in casings with drums in the center. Through the inlet and outlet ports, air enters and exits the casing. Several radial slots in the rotor are fitted with spring-loaded vanes. In order to ensure constant contact between the vanes and the housing, springs are used. There are some vanes that are compressed and some that are extended as the rotor rotates (see Figures 4.24 and 4.25). Additionally, it is usually the case that

FIGURE 4.24  Inlet, outlet and vanes of a rotary vane compressor.

FIGURE 4.25  A rotary vane compressor.

136

Equipment and Components in the Oil and Gas Industry

the inlet port is larger than the outlet port. As discussed previously, the rotor is positioned eccentrically so that the drum is closest to the housing at the outlet port and furthest from it at the inlet port. Each pair of adjacent vanes, along with the corresponding sections of the drum and housing, forms an enclosed space. As the rotor moves about its axis of rotation until it reaches the outlet port, the air trapped between two adjacent vanes undergoes a compression due to the shrinking space. There might be some oil lubrication for the compressor, which also serves as a seal, in order to prevent the air from escaping its space between adjacent vanes. Between the vanes and the housing, a thin layer of oil will seal the space. There are also oil-free designs available. The basic idea is to have some elastic mechanical component, such as springs, connected between the vanes and the drum that will force the vanes against the housing so that no or minimal air leakage occurs between adjacent vanes. In rotary vane compressors, the pressure ratio is dependent on the number of vanes. There is a direct relationship between the number of vanes on a sliding vane compressor and its pressure ratio. For single-stage rotary vane compressors, the pressure ratio is typically 5:1, while the pressure ratio for high-pressure compressors can reach 8:1. As a result, the number of vanes in the design varies from 20 to 30 depending on how much pressure rise is required. Typically, these compressors are used for capacities of up to 150 psig (1,034 kPag). The applications, advantages, and limitations of rotary vane compressors are as follows: Applications • Appliances such as household refrigerators and freezers. • Residential air conditioning and heat pump products below 5 tons. Advantages • Higher efficiency due to lower losses from clearances volume and discharge valve resistance. • Smaller dimensions and lighter weight per unit capacity. • Less vibration. • Fewer components. • Higher reliability because there is no conversion from rotation to reciprocation. Limitation (when compared to other rotary compressors) • Smaller capacity, normally below 5 tons due to the limitation of the structure. • Lower reliability due to more components. • Lower energy efficiency due to losses from clearance volume. In 1860, Philander Higley Roots and Frances Marion Roots patented the design of the rotary-lobe compressor. In a rotary lobe compressor (see Figure 4.26), there

Equipment for Pressurizing Fluids

137

FIGURE 4.26  A lobe compressor.

are two lobes attached to the driving shaft by the prime mover. The lobes are displaced by 90° from one another. As a result, if one of the lobes is in a horizontal direction, the other lobes will be at 90°, that is, vertically oriented. As the lobe rotates, the air is trapped from one end and compressed from the other. The air is then delivered to the delivery line. There are several types of positive displacement compressors, including scroll compressors. Scroll compressors can also be referred to as scroll pumps, scroll vacuum pumps, or spiral compressors. Scroll compressors have been used for many years, but recent advances in manufacturing technology have made them more viable. This section explains the workings, types, and applications of scroll compressors. Compressors that use at least two scrolls or spirals for mixing the working fluid are known as scroll compressors. These compressors function and are designed in a similar manner to screw compressors. They are quiet and smooth in operation. Instead of moving upward and downward as pistons do in a reciprocating compressor, the scrolls move in a circular motion. One scroll is a rotatory scroll, which rotates using a vibratory link, while the other scroll is a fixed scroll, which remains stationary. Upon entering the compressor, the fluid is trapped between the scrolls, and compression occurs when the rotatory scroll rotates. In the compressor, the moving scroll is attached to the crankshaft, while the stationary scroll is attached to the compressor body. The crankshaft is driven by a generator or electric motor. Upon receiving power from the drive motor, the crankshaft begins to rotate. In the process of rotating, the crankshaft transfers its motion to a scroll that moves. As the scroll moves, a pressure difference occurs

138

Equipment and Components in the Oil and Gas Industry

FIGURE 4.27  A scroll compressor.

between the internal pressure and the external pressure of the compressor. In response to the pressure difference, a suction force is generated that introduces air from the external air storage tank into the compressor. During the suction process, air is trapped between the moving and stationary scrolls. The trapped air cannot be moved directly from the suction side to the discharge side. As long as the scroll is moving, it can only move. By moving the scroll, trapped air is gradually moved toward the compressor center, where it is reduced in volume and compressed. The compressed air eventually reaches the center of the assembly, where it is discharged through a port. A scroll compressor is shown in Figure 4.27, which illustrates its structure and working principles. Figure 4.28 shows how various types of compressors can be categorized.

4.3.2 Compressor Selection In some cases, it may not be obvious what type of compressor is required for a particular application. Some of the most commonly used compressor types in the process industry are centrifugal, axial, rotary, and reciprocating compressors. As shown in Figure 4.29, they can be divided into three categories. Axial-flow compressors are best suited for very high flows and low pressure ratios. According to

Equipment for Pressurizing Fluids

139

FIGURE 4.28  Different type of compressors.

FIGURE 4.29  Performance characteristics of various compressors.

Figure 4.30, axial-flow compressors are more efficient but have a smaller operating range than centrifugal compressors. At medium flow rates and high pressure ratios, centrifugal compressors are most efficient. Low flow rates and high pressure ratios are best accommodated by reciprocating and rotary compressors (positive displacement machines). Prior to the 1960s, positive displacement compressors, also known as reciprocating compressors, were the most widely used compressors in the process and pipeline industries.

140

Equipment and Components in the Oil and Gas Industry

FIGURE 4.30  Various pump efficiency charts.

4.3.3 Compressor Terms The following are some of the main compressor terms. 4.3.3.1 Adiabatic Compression Adiabatic compression is obtained when there is no heat transfer to or from the gas during the compression process. It ideally follows the equation pV k = Constant, where:

K=

Cp Cv

=

MC p MC p -1.986

(4.5)

where: K = the adiabatic exponent defined by: Cp= specific heat capacity at constant pressure, Btu/lb °F Cv= specific heat capacity at constant volume, Btu/lb °F M = molecular weight, lb/lbmole The key difference between adiabatic and reversible adiabatic processes is that in adiabatic processes, the adiabatic system is insulated and does not allow any heat transfers, whereas reversible adiabatic processes involve heat transfer that is directly proportional to the change in entropy. There are no reversible adiabatic (isentropic) processes in practice, as heat can be lost from the gas during compression or gained from the compressor, so compression increases entropy. 4.3.3.2 After Cooler After compression, a device is used to dissipate heat that has been generated by the compression process. The compressed air or gas can be effectively rid of moisture in this manner.

Equipment for Pressurizing Fluids

141

4.3.3.3 Break Horsepower A measure of the total power input to compress and deliver a given quantity of air, including losses due to slip and friction and mechanical losses. 4.3.3.4 Casing This is the container where the impeller or rotor is mounted and where the compressed gas is contained. 4.3.3.5 Compressibility Compressibility is the measure of the change in volume of a gas in response to a change in pressure. 4.3.3.6 Compression Reduction of a specific volume of air or gas within a specified compressor cylinder, resulting in an increase in air or gas pressure. 4.3.3.7 Clearance The volume contained in one end of the cylinder that is not swept by the piston in a reciprocating compressor. 4.3.3.8 Compression Efficiency Compression efficiency is the ratio of the work or power required to theoretically compress a gas to the work or power actually performed within the compressor cylinder as indicated on indicator cards. There is a wide range of compressor efficiency depending on the compressor type, size, and throughput. There can only be an accurate estimate provided by the compressor manufacturer after a compressor test has been conducted. 4.3.3.9 Compression Ratio A compressor’s compression ratio is defined as the ratio of the absolute discharge pressure to the absolute suction pressure. As an example, if the absolute exhaust pressure is 20 bar and the absolute suction pressure is 5 bar, the compression ratio is 4. It is important to note that the compression ratio here refers to the ratio between the maximum and minimum volume of the compressor when it is compressing, and this ratio will never change. When it comes to compressors, the compression ratio is an important concept that helps determine the size of the compressor’s compression stroke and a reference value for the point at which the compressor’s efficiency can be optimized. As the discharge pressure increases and the suction pressure decreases, the compression ratio increases. As the compression ratio increases, so does the power consumption of the compressor. Compressor performance decreases, and the performance of the system decreases as well. In contrast, if the discharge pressure decreases and the suction pressure increases, the compression ratio decreases. The system becomes more efficient as a result. Due to the fact that most gases increase in temperature during compression, the final outlet temperature of the compressor is always a concern. High

142

Equipment and Components in the Oil and Gas Industry

discharge temperatures can cause internal components to fail due to material degradation or excessive thermal expansion. As a result of the compression ratio, the required horsepower for a particular stage is also determined by the ratio; the higher the ratio, the greater the horsepower requirement. 4.3.3.10 Design Pressure The design pressure of equipment, including compressors, can be described as the stress placed upon its internal and external pressure that the equipment appears to be able to withstand. It is generally higher than the maximum operating pressure but always lower than the maximum allowable working pressure. 4.3.3.11 Design Speed Compressor speed refers to the number of revolutions per minute made by the compressor shaft. Symbolically, it is represented by the letter n. Compressor speed refers to the number of revolutions per minute made by the shaft of the compressor when the power machine drives it in order to compress the air or gas. There are two types of compressors: variable speed and fixed speed. An air compressor with variable speed maintains a constant air pressure while adjusting the motor speed to meet the production air demand. Variable speed machines reduce the engine speed so that it is aligned with the actual air demand, thus reducing energy consumption. In contrast to variable-speed compressors, fixed-speed compressors either operate at 100% or are switched off. In applications where there is a constant need for compressed air, they are ideal. As long as the engine is not turned off, the machine will run at the same speed at all times. Since fixed-speed compressors always operate at full speed, they produce more air than is necessary, resulting in a waste of energy. 4.3.3.12 Design Temperature Design temperature refers to the temperature used in the design of the equipment such as a compressor. 4.3.3.13 Diffuser This is the stationary passageway following an impeller in which the velocity energy imparted to the gas by the impeller is converted to static pressure. 4.3.3.14 Discharge Pressure The total pressure at the compressor’s discharge flange. 4.3.3.15 Discharge Temperature The temperature at the discharge flange of the compressor. 4.3.3.16 Displacement The amount of air or gas swept by the moving parts of a positive displacement compressor in a given period of time.

Equipment for Pressurizing Fluids

143

4.3.3.17 Duty Cycle In the simplest terms, a compressor duty cycle is the duration of time during which the compressor delivers pressurized air. For percentages, you can simply deduct the number of seconds or minutes represented by the figure from the total cycle time. When expressed as a percentage, duty cycle is equal to the compressor’s run time divided by the total cycle time. Accordingly, this percentage represents the amount of time you may keep the compressor on, plus the time required for the compressor to cool down. A compressor with a 25% duty cycle would require 45 minutes of downtime out of every hour, meaning that it would only be able to operate for 15 minutes. Additionally, a compressor with a 50% duty cycle will require 30 minutes of off time for every 30 minutes of operation. 4.3.3.18 Flow Rate Flow rate is a measure of the actual volume of gas compressed and delivered at a standard discharge point, given the conditions of total temperature, total pressure, and composition at the standard inlet point. 4.3.3.19 Guide Vane In centrifugal compressors, guide vanes (see Figure 4.31) are typically used. Nonrotating elements that may be fixed or adjustable to provide a desired flow direction

FIGURE 4.31  Position of guide vanes in a centrifugal compressor.

144

Equipment and Components in the Oil and Gas Industry

to the impeller inlet. A guide vane ensures that a substance passes through a system evenly, smoothly, and as quickly as possible, as impellers increase the flow of a substance through a system. 4.3.3.20 Inlet Pressure Total pressure at the inlet flange of the compressor 4.3.3.21 Inlet Temperature Temperature at the inlet flange of the compressor 4.3.3.22 Intercooling It is the main function of the air compressor intercooler to cool the air before it enters the next compression stage. The purpose of cooling the gas between compression stages is to reduce discharge temperature, reduce the volume to be compressed in the next stage, and save energy. 4.3.3.23 Isothermal Compression Iso stands for constant, while thermal stands for temperature. In isothermal processes, the temperature remains constant throughout the process. A compression process involves reducing the volume of a system or increasing its pressure. During isothermal compression, the temperature remains constant during the compression process. This is a thermodynamic process that occurs in a closed system. As a result of the process, thermal equilibrium is maintained. The isothermal compression process occurs at a constant temperature, which requires that the heat of compression be continuously removed during the process. According to the isothermal compression formula, pV is a constant in isothermal compression. Thermal equilibrium is the state at which the temperature is constant throughout the system. 4.3.3.24 Normal Operating Points The point at which normal operation is expected and optimum efficiency desired. 4.3.3.25 Oil-Free vs Oil-Less Compressors Positive displacement compressors are usually available in oil-free or oil-less designs, in which no lubricant is injected into the air. Compressors that are oilless typically contain no oil at all, while compressors that are oil-free have a lubricated crank case or gearbox isolated from the compression chamber. The efficiency of oil-free and oil-less machines is typically 10 to 20% lower, and they require more maintenance than their lubricated counterparts. 4.3.3.26 Polytropic Compression A compression process in which changes in the gas characteristics are taken into consideration. A polytropic process is a thermodynamic process that obeys the relation:

pVn = C

Equipment for Pressurizing Fluids

145

where p is the pressure, V is volume, n is the polytropic index, and C is a constant. The polytropic process equation describes expansion and compression processes which include heat transfer. While the adiabatic compression equation is similar to the previous one, the polytropic process is irreversible from a thermodynamic standpoint. An important difference between adiabatic and polytropic processes is that in adiabatic processes, there is no heat transfer, whereas in polytropic processes, there is heat transfer. Due to the fact that the polytropic exponent, n, is determined experimentally for the compressor being used, the relationship is able to predict the gas behavior with pressure and temperature far more accurately. 4.3.3.27 Reversible Compression It is an ideal and unattainable compression process in which there are no losses. Contrary to reversible compression, irreversible compression involves actual compression processes that result in losses, such as leakage, friction, and so on. 4.3.3.28 Rotors It consists of a shaft and impeller (centrifugal types) or a shaft/drum and blading (axial types). 4.3.3.29 Slip Gas that has been partially compressed but is not being delivered to the customer due to internal leakage within the compressor. 4.3.3.30 Stable Operation Rate The range of flow between the maximum capacity and the surge limit. This chapter provides a further explanation of surge and surge limits. 4.3.3.31 Surge There is a technical term for surge, which is an unstable condition of the compressor that results in erratic compressor performance. The flow through any axial or centrifugal compressor will experience the phenomenon called surge when the flow drops below a certain level. What are the effects of surging on the compressor, and what are the consequences? The surge condition results in a momentary reversal of flow, resulting in a very fast pulsating flow back and forth through the compressor interiors, resulting in severe and consequential damage. There are several consequences of surges, including unstable flow and pressure resulting in process upset and damage in sequence resulting in damage to seals, bearings, impellers, and shafts and increased seal clearances and leakage. 4.3.3.32 Surge Control The purpose of surge control is to prevent surges. Anti-surge systems detect and automatically compensate for potential disturbances by maintaining flow through the compressor above surge conditions. Anti-surge systems consist of a surge controller, an anti-surge valve, and a variety of accessories. As part of the surge controller, a temperature (TT), flow (FT), and pressure (PT) sensor is located

146

Equipment and Components in the Oil and Gas Industry

FIGURE 4.32  Surge control in a compressor.

upstream of the compressor, with flow and temperature controllers located downstream of the compressor (see Figure 4.32). Using a surge controller, the valve will be operated as close as possible to the surge line in order to maximize the efficiency of the compressor and gas turbine without compromising the compressor’s performance. Surges can generally be identified by a rapid change in any measurement that is directly related to compressor flow or head. It has already been mentioned that compressor flow, discharge pressure, and inlet temperature can be used to detect surges. 4.3.3.33 Surge Limit There is a maximum capacity at a given head at which unstable flow occurs.

4.3.4 Compressor Parts To help the reader better understand the functions of compressors, this alphabetized list of air and gas compressor parts includes parts from reciprocating piston models as well as rotary models: After cooler: The operation of an aftercooler is similar to that of an intercooler. However, it is located after the final stage (HP) of the air compressor system. Following the release of hot air from the main compressor system, an aftercooler is used to maintain a temperature between 7 and 10°C above the ambient temperature. This section will discuss the intercooler in more detail.

Equipment for Pressurizing Fluids

147

Balance drum: Balance drums are circular devices that are installed on the pump or compressor rotor. Drums are generally installed at the discharge end of the pump or compressor. This device is used to balance the axial thrust generated by the impeller. Also, it is used in conjunction with thrust bearings, which are capable of transferring a very low residual thrust load to them. Bearing: The rotor of a compressor is held in position axially by a thrust bearing, and it rotates on two journal bearings (radial bearings). There are journal bearings at both ends of the rotor, while the thrust bearing is mounted outside of the journal bearing and on the opposite side of the coupling. The following is a brief description of both bearings. The purpose of thrust bearings is to restrict axial movement of the shaft. A  thrust collar is hydraulically attached to a rotor so that it rotates along with it. The compressor shaft is prevented from rotating radially by journal bearings. A journal bearing relies on pressurized oil films that form between the shaft and the bearing in order to support a rotating shaft. Journals are the portions of the shaft that are supported by the bearing. Casing: The casing is the outermost part of the compressor that contains pressure. The compressor casing, as well as the compressor inlet/outlet flanges, must be rated for the maximum discharge pressure of the compressor. It is possible to split the casing horizontally or vertically. The top and bottom halves of a horizontal split casing are bolted together along the centerline as shown in Figure 4.33. By removing the top half, it is possible to perform maintenance on the internal parts.

FIGURE 4.33  A centrifugal compressor casing and internals. (Courtesy: Shutterstock)

148

Equipment and Components in the Oil and Gas Industry

  High-pressure or hydrogen-rich gases should be compressed using vertically split centrifugal compressors (barrel type). Vertical split casings (barrel type) can withstand pressures up to 800 bars (12,000 pounds per square inch). Horizontally split casings are used for low-pressure applications up to 40 bar (600 psi) discharge pressure. Nozzles for the inlet and discharge are welded to the cylindrical casing or are integral with the casing. Pipework is bolted to these nozzles. Connecting rod: A connecting rod, shown on the right side of Figure 4.34, is primarily responsible for converting the linear motion of a piston into the rotary motion of a crankshaft in a reciprocating compressor. Thus, it can be subjected to tension, compression, bending, and buckling. Coupling: Power is transmitted from the driver to the compressor through the coupling. As a matter of fact, couplings transfer load and torque from the driving shaft to the driven shaft. There are two types of couplings: direct coupling and speed-increasing gear coupling. A  toothed coupling is generally used in conjunction with a force-feed or filling lubrication system. Couplings with force-feed lubrication are designed for high rotational speeds and are most commonly used in compressors. Alternatively, there are sealed couplings, which require lubricating grease to be injected every now and then; these couplings are used only on low-speed drive shafts. Crank case: The crankcase, also known as the frame, is an essential component of a reciprocating compressor that houses all its rotating parts. In reciprocating compressors, the crankcase is the core component that supports and encloses almost all internal components. Crank shaft: One of the major shafts in a compressor is the crankshaft, while the other is the motor shaft. As the shaft revolves around the frame axis, the piston, piston rod, and connecting rod are driven by it. Cylinder head: The role of the cylinder head is not limited to absorbing heat in the compressor. A cylinder head is composed of pockets that hold

FIGURE 4.34  The connecting rod and its connection to the piston rod and crankshaft.

Equipment for Pressurizing Fluids

149

the intake/suction and delivery valves. In addition, they have air cooling fins or water jackets in order to facilitate the passage of cooling water. It is common to have a network of pipes for the delivery of cooling water and compressed air to the next stage. The suction filter for the air intake is one of the main components of the cylinder head assembly. Filtered air is usually introduced into the compressor unit through the filter mounted on the cylinder head. Delivery valve: Similar to the suction valve, this valve is also known as a non-return valve. It is used for air or gas discharge from the compressor cylinder to the delivery pipe. Impeller: In a compressor, the impeller is the primary rotating element that adds velocity to the gas. Compressor head and flow characteristics are affected by the shape and size of the impeller. There are three types of impellers: open, semi-open, and closed. This chapter has already discussed all three types of impellers. Intake valve: An air or gas compressor’s intake valve serves as its breathing port. In this valve, air or gas is allowed to enter, which is then directed to the compressor head, where it is compressed to form compressed gas. As well as controlling the size and flow of air and gas pressure, intake valves also control the loading and unloading of the air or gas compressor. Intercooler: In a two-stage compressor, an intercooler is used to cool the air from the first compression stage (LP) before it enters the second compression stage (HP). Piston: As the piston pulls away from the intake valve, the gas is allowed to enter the cylinders. During one stroke of pressure, the crankshaft drives the piston, which compresses the gas. As part of a two-stage compressor, air travels to a second cylinder for another round of compression. Rotor: Rotors are the rotating elements of compressors connected to motor drives. The rotor of a dynamic compressor consists of the impeller(s) and shaft, as well as shaft sleeves and thrust-balancing devices. Shaft: A shaft is a stiff section that is usually constructed from a hard material that has sufficient mechanical strength. In addition to the impellers and spacers mounted on the central part, both ends are mounted with bearings and seals. Shaft seal: The shaft ends are sealed at both ends to minimize leakage of process gas (which is being compressed) from inside to outside the compressor, as well as to prevent outside air or oil vapor from getting into the compressor and interfering with the process. Suction filter: In order to protect the compressor unit from contamination and dirt particles, suction filters are designed to be installed on the suction side of the compressors. Suction valve: Refer to the intake valve. Note: For all compressors to operate, a drive mechanism, such as an electric motor or turbine, is required, and all are rated according to their discharge capacity and flow rate. For most compressors, auxiliary

150

Equipment and Components in the Oil and Gas Industry

components are required for cooling, lubrication, filtering, instrumentation, and control. Compressors with gearboxes between the driver and compressor are capable of increasing the speed of the compressor.

QUESTIONS AND ANSWERS 1. Identify the correct statement about centrifugal pumps. A. A centrifugal pump consists of rotating or stationary components. The impeller and shaft of a pump are stationary components. B. Fluid enters the suction of the pump and then enters the impeller eye, where fluid kinetic energy is increased. C. Centrifugal pumps are rotary pumps due to the rotation of the impeller. D. Non-metallic materials are always used in the manufacture of impellers.

Answer) Option A is incorrect because both the shaft and the impeller are rotating components and not stationary components. The correct answer is option B. Option C is incorrect because centrifugal pumps belong to the kinetic or dynamic pump category and not the rotary pump category. A rotary pump is a type of positive displacement pump. In many cases, impellers are made from metallic materials; therefore, option D is incorrect.



2. According to its intended operating conditions, pump __________ refers to the flow rate through a pump. It describes the amount of liquid that can be pumped through the pump in a given period of time. A. Capacity B. Efficiency C. Performance D. Speed



Answer) Option A is the correct answer.



3. Regarding the pump performance curve, which statement is incorrect? A. The pump manufacturer typically provides a performance curve for the pump. B. The pump performance curve is an important tool for engineers when designing pumps. C. It is also possible to use pump performance curves to identify problems in a pump system, such as cavitation or problems with suction or discharge pipes. D. A pump performance curve is simply a graph illustrating the relationship between the pump head and capacity of the pump.

Answer) A pump performance curve indicates that head, capacity, pump impeller size, efficiency, speed and even more relationships exist between the various curves. Therefore, option D is incorrect.

Equipment for Pressurizing Fluids

151

4. The pump does not contain a _____(a)_____ inside, but instead it is installed after the pump to prevent water from returning to the pump housing after the pump has been discharged. A ___(b)_____serves the purpose of removing solid particles from fluid before they enter the pump and cause damage. _____(c)_____ refers to the outer shell of a pump. The unit must be capable of sealing off the interior from the exterior both in terms of pressure and fluids. A _____(d)_____ is another component of the pump that transmits power from the motor to the moving parts inside the housing.



Answer) (a) check valve, (b) strainer, (c) Casing, (d) shaft 5. What is the correct statement regarding double-acting piston compressors? A. A double-acting compressor is a type of rotary compressor. B. Double-acting compressors have a lower maintenance cost than single-acting compressors. C. Compared to single-acting compressors, double-acting compressors have a lower efficiency. D. The double-acting compressor doubles the capacity of a given cylinder size by compressing air both on the upstroke and downstroke of the piston. Answer) In this case, option A is incorrect, as double-acting piston compressors are a type of positive displacement and reciprocating compressor. In addition, the maintenance cost of a double-acting compressor is higher than that of a single-acting compressor, which makes option B incorrect as well. Due to the higher efficiency of double-acting piston compressors compared to single-acting piston compressors, option C is not correct. Option D is the correct answer.

6. There would be a downtime of 20 minutes per hour for a compressor. What is the value of the compressor’s duly cycle? A. 33% B. 66% C. 50% D. 60%



Answer) In its simplest form, a compressor duty cycle refers to the period of time during which the compressor delivers pressurized air. By dividing the run time of the compressor by its total cycle time, duty cycle is expressed as a percentage. Considering that the compressor has a downtime of 20 minutes in one hour, the working time of the compressor is 40 minutes in 1 hour. In this regard, the duty cycle of the compressor is approximately 66%, which corresponds to a ratio of 40 to 60. Therefore, the correct answer is option B.

7. For applications requiring high pressure and low flow, what type of compressor is appropriate? A. Positive displacement B. Axial

152

Equipment and Components in the Oil and Gas Industry



C. Centrifugal D. All of these options are incorrect



Answer) Option A is the correct answer.



8. What is the correct statement regarding rotary compressors? A. The rotary compressor falls under the category of positive displacement compressors. B. They provide energy to the air or gas being compressed by means of an input shaft moving one or more rotating elements (rotors). C. There is no inlet or discharge valve on these compressors in most cases. D. All options are correct. Answer) Option D is the correct answer.



9. In order for the power to be transmitted from the driver to the compressor, which component of the compressor is involved? A. Casing B. Intake and discharge valve C. Balance drum D. Coupling

Answer) Option D is the correct answer.

10. Find the correct statement about compressor components.

A. In general, a single-stage compressor requires both an intercooler and an aftercooler. B. The crankshaft is the same as the motor shaft. C. In a crankshaft, a connecting rod is responsible for converting the linear motion of a piston into rotary motion. D. Typically, compressors are equipped with filters on the discharge side. Answer) Option A is incorrect because single-stage compressors do not require any intercoolers, as intercoolers are only required for multi-stage compressors. In addition, option B is incorrect because the crankshaft and motor shaft are completely different. It is correct to select option C. It is incorrect to select option D since filters are installed on the suction of the compressors to prevent dirt and particles from entering them.

FURTHER READING

1. Atlas Copco. (2023). Guide to dynamic compressor types: Centrifugal and axial. [online] available at: htps://www.atlascopco.com/en-uk/compressors/wiki/compressed-airarticles/dynamic-compressors [access date: 31st May, 2023] 2. Bloch, H. P., & Godse, A. (2006). Compressors and modern process applications. New Jersey, USA: John Wiley & Sons. ISBN: 978-0-471-72792-7

Equipment for Pressurizing Fluids

153

3. Budris, A. R., & Mayleben, P. A. (1998). Effects of entrained air, NPSH margin, and suction piping on cavitation in centrifugal pumps. In Proceedings of the 15th International Pump Users Symposium. Texas A&M University, Turbomachinery Laboratories. 4. Came, P. M., & Robinson, C. J. (1998). Centrifugal compressor design. Proceedings of the Institution of Mechanical Engineers, Part C: Journal of Mechanical Engineering Science, 213(2), 139–155. 5. Comp Air. (2022). Rotary screw compressor technology explained. [online] available at: www.compair.com/en-is/technologies/screw-compressor [access date: 3th June, 2023] 6. Giampaolo, A. (2020). Compressor handbook: Principles and practice. Boca Raton, FL: CRC Press. ISBN: 9788770229067 7. Inaguma, Y., & Hibi, A. (2005). Vane pump theory for mechanical efficiency. Proceedings of the Institution of Mechanical Engineers, Part C: Journal of Mechanical Engineering Science, 219(11), 1269–1278. 8. JEE Pumps. (2022). Understanding the different pump parts of pump design. [online] available at: www.jeepumps.com/understanding-the-different-parts-of-pumpdesign/#:~:text=Pumps%20typically%20consist%20of%20three,the%20fluid%20 through%20the%20pump [access date: 31st May, 2023] 9. Karassik, I. J., McGuire, T., Karassik, I. J., & McGuire, T. (1998). Special effect pumps. In Centrifugal pumps (pp. 352–366). Boston, MA: Springer. 10. Liquid Technews. (2022). Rotary vane compressors 101: The essential intro. [online] available at: www.linquip.com/blog/rotary-vane-compressors/ [access date: 3rd June, 2023] 11. Lyons, W. C., Stanley, J. H., Sinisterra, F. J., & Weller, T. (2020). Air and gas drilling manual: Applications for oil, gas, geothermal fluid recovery wells, specialized construction boreholes, and the history and advent of the directional DTH. Texas, USA: Gulf Professional Publishing. ISBN: 978-0-12-815792-3 12. McGuire, J. T. (2020). Pumps for chemical processing. 1st ed. Boca Raton, FL: CRC Press. ISBN: 9780367403140 13. Michael Smith Engineers. (2023). Useful information on positive displacement pumps. [online] available at: www.michael-smith-engineers.co.uk/resources/useful-info/positive-displacement-pumps [access date: 26th May, 2023] 14. Michael Smith Engineers. (2023). Useful information on vane pumps. [online] available at: www.michael-smith-engineers.co.uk/resources/useful-info/vane-pumps [access date: 28th May, 2023] 15. Mechanical Boost. (2020). Single acting compressor | working, applications and P-V diagram. [online] available at: https://mechanicalboost.com/single-acting-compressor-working-applications-and-p-v-diagram/ [access date: 1st June, 2023] 16. Mechanical Boost. (2020). Double acting compressor—working principle, ­components, and applications. [online] available at: https://mechanicalboost.com/ double-acting-compressor-working-principle-components-applications-advantag es-and-disadvantages/ [access date: 1st June, 2023] 17. Nelik, L. (1999). Centrifugal & rotary pumps: Fundamentals with applications. Boca Raton, FL: CRC press. ISBN: 9780367399870 18. Saudi Aramco. (2008). Pump and piping system performance as depicted in performance curves. Mechanical Chapter. MEX-211.02. 19. Shum, Y. K. P., Tan, C. S., & Cumpsty, N. A. (2000). Impeller–diffuser interaction in a centrifugal compressor. Journal of Turbomachinery, 122(4), 777–786.

154

Equipment and Components in the Oil and Gas Industry

20. Smirnov, A. V., Chobenko, V. M., Shcherbakov, O. M., Ushakov, S. M., Parafiynyk, V. P., & Sereda, R. M. (2017, August). The results of pre-design studies on the development of a new design of gas turbine compressor package of GPA-C-16 type. In IOP conference series: Materials science and engineering (Vol. 233, No. 1, p. 012022). San Francisco, CA: IOP Publishing. 21. Stewart, M. (2018). Surface production operations, volume IV: Pumps and compressors. Texas, USA: Gulf Professional Publishing. ISBN: 978-0-12-809895-0

5

Equipment for Fluid Temperature Changes

5.1 INTRODUCTION It is very common to change the temperature of oil and gas as well as other media such as water in the oil and gas industry. This includes both cooling and heating. Three main pieces of equipment are used for changing the fluid and gas temperature, heat exchangers, coolers, and boilers, and these are discussed in this chapter. As their name implies, industrial heat exchangers are pieces of industrial equipment that exchange or transfer heat from one medium to another. The primary purpose of the heat exchange may be to heat or cool elements. In the industrial sector, cooling is often the primary function in order to prevent overheating of equipment or volatile substances.

5.2 HEAT EXCHANGERS 5.2.1 Introduction In industrial settings, heat exchangers are easily one of the most important and widely used pieces of process equipment. A heat exchanger is a device that transfers thermal energy (enthalpy) between two or more fluids, between a solid surface and a fluid, or between solid particulates and a fluid at different temperatures and in thermal contact. There are a wide variety of industrial applications for heat exchangers. Typical applications include the heating or cooling of a fluid stream of concern, as well as the evaporation or condensation of single- or multi-component fluid streams. Other applications may involve recovering or rejecting heat, sterilizing, pasteurizing, fractionating, distilling, concentrating, crystallizing, or controlling a process fluid. There are a few heat exchangers in which the fluids exchanging heat are in direct contact with each other. Generally, heat transfer between fluids occurs through a separating wall or into and out of a wall in a transient manner. In many heat exchangers, the fluids are separated by a heat transfer surface, and ideally, the fluids should not mix or leak. Each type of heat exchanger works differently and uses different flow arrangements, equipment, and design features. There is one thing that all heat exchangers have in common: they all function to exchange heat by directly or indirectly exposing a warmer medium to a cooler one. The process is usually carried out by using a set of tubes enclosed within a casing. The use of heat exchangers differs from the use of fuel-fired, electrical-powered, or nuclear-powered heat transfer equipment such as

DOI: 10.1201/9781003467151-5

155

156

Equipment and Components in the Oil and Gas Industry

boilers. Heat must be generated by a fluid source and received by a fluid medium in heat exchangers.

5.2.2 Thermodynamics of Heat Exchangers In a heat exchanger, the rate of heat transfer (Q) is governed by Equation 5.1 (heat transfer in a heat exchanger):

Q = U × A×ΔT(5.1)

where: Q is the amount of heat in watts (w) in SI units. U is the heat transfer coefficient. The heat transfer coefficient is the amount of heat transferred per unit area per Kelvin. Therefore, area is included in the equation since it represents the area over which heat is transferred. In SI units, the heat transfer coefficient is expressed as watts per square w meter Kelvin 2  . m K A is the heat transfer surface area, m 2 . ΔT is the temperature difference between hot and cold fluids in ℃. Using this equation, it can be seen that the U value is directly proportional to Q, the heat transfer rate. The greater the U value, the greater the heat transfer rate, assuming that the heat transfer surface and temperature difference remain unchanged. To put it another way, a higher U value may lead to a shorter batch time and an increase in production/revenue for a particular heat exchanger and product. Thermodynamic principles and mechanisms of heat transfer are the same for all types of heat exchangers. Essentially, these principles describe how thermal energy is transferred. Heat exchanger systems involve the interaction of three bodies: the hot fluid, the cold fluid, and the wall that separates the two fluids. A  flow of energy occurs between a hot fluid and a cold fluid. The first law is known as the law of conservation of energy, which states that energy (in the form of heat and work) cannot be created or destroyed. It can only be transferred from one system to another or converted into a different form. According to the heat balance equation in heat exchangers, this statement can be expressed as follows: (Heat In) + (Generation of Heat) = (Heat Out) + (Accumulation of Heat) If the system operates in a steady-state flow, which means that the thermal properties remain constant over time, and it is adiabatic (perfectly insulated), then the heat balance equation can be simplified to Heat In = Heat Out. Heat exchangers are designed and operated by using this equation, which is one of the most basic equations. Introducing the concept of entropy, the degree of disorderliness and randomness of a system, the second law introduces the concept of entropy. There

Equipment for Fluid Temperature Changes

157

is constant increase in the entropy of the universe, and it can never decrease. It indicates the direction of energy flow between two interacting systems in which the highest entropy is generated. As a natural tendency of all systems, heat is always transferred from a body with a higher temperature to a body with a lower temperature. In heat exchangers, the cold fluid gains heat and increases its temperature, while the hot fluid loses heat and decreases its temperature.

5.2.3

heat transfer mechanisms

It is a combination of conduction and convection that is responsible for the transfer of heat in heat exchangers. 5.2.3.1 Conduction Direct collisions between adjacent molecules transfer heat energy. A  molecule with a higher kinetic energy is capable of transferring thermal energy to a molecule with a lower kinetic energy. There is a greater likelihood of it occurring in solids. The process occurs on the wall that separates the two fluids in a heat exchanger. The process of conduction involves the transfer of heat from the hotter end of an object to its cooler end. The thermal conductivity of an object is determined by its capacity to conduct heat, denoted by k. Based on Fourier’s law of thermal conduction, the rate at which heat is transferred through a material is proportional to the negative gradient in temperature and the area. The proportionality constant obtained in the relation is known as the thermal conductivity, k (or λ), of the material. Generally, a material with a high value of k is a good thermal conductor and readily transfers energy by conduction. Conduction is also affected by the cross-sectional area of the material. The larger the area, the faster the heat transfer will occur due to more collisions between molecules. A material’s thickness can also affect the rate at which heat is transferred. Furthermore, it should be noted that heat flows from hot to cold objects. An exchange of heat energy occurs between a hot and a cold body when they are in thermal contact, resulting in the hot body cooling down and the cold body warming up as they reach thermal equilibrium. A frying pan is shown in Figure 5.1 as an example of conduction heat transfer. Convection in heat exchangers occurs through the bulk motion of the fluid against the surface of the wall, thus transferring thermal energy. Thermal energy is transferred through convection in heat exchangers as a result of bulk motion of the fluid against the wall surface. Molecular diffusion and bulk motion are both involved in this process. Near the surface, fluid velocity is low, and diffusion is predominant. As distance from the surface increases, bulk motion becomes more influential and dominates. This phenomenon is described by Newton’s law of cooling, which states that heat loss is proportional to the temperature difference between a body and its surroundings (in this case, the wall and the fluid). Figure 5.2 illustrates convection in a kettle. The temperature of the water near the heating element increases when the kettle is turned on. Temperature increases

158

Equipment and Components in the Oil and Gas Industry

FIGURE 5.1  Conduction in a frying pan. (Courtesy: Shutterstock)

cause the water to expand and become less dense. Water that has been heated rises to the top of the kettle. Cold water is moved downward in the kettle, and as it contacts the bottom surface, it becomes hot and travels upward. The movement of water creates convection currents. Equation 5.2 calculates the amount of heat transferred by convection:

Q = h×A×ΔT

(5.2)

where: Q is the rate of heat transfer in watts (w) in SI units. h is the convective heat transfer coefficient. In SI units, the convection heat transfer coefficient is expressed as watts per square meter w Kelvin 2  . m K A is the area in square meters normal to the direction of the flow of heat. ΔT is the temperature difference between the wall and bulk fluid in . A heat exchanger transfers heat from a hot fluid to a cold fluid according to the following sequence:

1. By convection, the hot fluid’s thermal heat is transferred to the adjacent wall surface.

Equipment for Fluid Temperature Changes

159

FIGURE 5.2  Convention currents in a kettle. (Courtesy: Shutterstock)



2. By conduction, heat is transferred through the wall surface side. 3. Convection transfers heat from the wall to the cold fluid.

The approach temperature of a heat exchanger is calculated by subtracting the difference between the inlet and outlet temperatures of the fluid stream from the difference between the inlet and outlet temperatures of the process stream. In the case of hot approach temperatures, the difference is between the hot inlet temperature and the cold outlet temperature. As a result of cold approach temperatures, there is a difference between cold inlet temperature and hot outlet temperature. As can be seen in Figure 5.3, there are two fluids being exchanged in the heat exchanger—one is the hot process fluid, while the other is the cooling water (utility). Water, steam, hot water, air, or any other utility can be used as utility fluids in a heat exchanger. The process fluid is available at THin, and it must be cooled to THout. At TCWin, cooling water is available as a utility. Regarding the cold approach temperature, it is obtained as THout – TCWin. When choosing the type of heat exchanger to purchase, it is important to take into account the optimal approach temperature, since miscalculation of the approach temperature can lead to the wrong type of heat exchanger being selected. In Table 5.1, minimum approach temperatures for cooling water, air, and steam are listed. If approach temperatures are below these limits, it would be uneconomical to use that utility, which would result in a very large heat exchanger. If, however, you are faced with a small approach temperature when sizing a new exchanger, you have a few options to choose from. You may be able to use other utilities that have a larger approach temperature value. You may be able to use a

160

Equipment and Components in the Oil and Gas Industry

FIGURE 5.3  Heat exchanger inlet and outlet temperature charts.

TABLE 5.1 The Minimum Acceptable Approach Temperatures for Cooling and Heating Media (Utility) The Medium Used to Cool or Heat (Utility)

Minimum Acceptable Approach Temperature, ℃

Steam Air Cooling water

10 14 8

significantly higher flow rate on the utility side. See if you can use a type of heat exchanger that will maximize the U × A value for overall heat transfer. Example 5–1) When a cold fluid is heated from 80°C to 100°C with a hot fluid at 105°C, what is the hot approach temperature? Does the hot approach temperature meet acceptable standards when steam is used as the heating medium? Answer) Hot approach temperature = Hot fluid inlet temperature – Cold fluid outlet temperature = 105°C – 100°C = 5°C Considering that the minimum acceptable approach temperature for steam is 10°C, the value of the hot approach temperature cannot be considered acceptable. It is likely that the design of the heat exchanger needs to be modified or the steam flow rate needs to be increased.

5.2.4 Classifications of Heat Exchangers Heat exchangers can be classified in a number of ways. The first way is based on the transfer process, which can be direct or indirect. It is imperative to note that

Equipment for Fluid Temperature Changes

161

this method of classifying heat exchangers refers to whether the substances being exchanged are in direct contact with one another. In contrast, they are separated by a physical barrier, such as the walls or tubes themselves. As opposed to relying on radiant heat or convection, direct contact heat exchangers place hot and cold fluids in direct contact within the tubes. Direct contact is an extremely effective method of transferring heat. However, for direct contact to be effective, it must be safe, or even desirable, for the fluids to make contact with each other. When the hot and cold fluids are simply different temperature variations of the same fluid, or if a fluid mixture is desired, direct contact heat exchangers may be a good choice. Heat exchangers with indirect contact maintain a physical separation between hot and cold fluids. In indirect heat exchangers, the hot and cold fluids are separated by different pipes, and heat is exchanged by radiant energy and convection instead. One of the most common reasons for doing this is to prevent contamination or pollution of one fluid by another. It is also possible to categorize heat exchangers according to the number of fluids, which may be two, three, or more than three. It is known that a two-phase heat exchanger is the simplest type of heat exchanger, which involves hot and cold fluids moving in the same or opposite directions through a concentric tube (or double-pipe) arrangement. The hot fluid can be separated from the cold by a wall with high thermal conductivity (usually a steel or aluminum tube), or they can be in direct contact with each other. A flow of energy occurs between a hot fluid and a cold fluid. Heat is always transferred from a body with a higher temperature to a body with a lower temperature as a natural tendency of all systems. Cold fluids gain heat in heat exchangers and increase their temperatures, while hot fluids lose heat and decrease their temperatures. A three-fluid heat exchanger is used to transfer heat between three fluid streams: a cold fluid, an intermediate fluid, and a hot fluid. A heat exchanger with three fluids may have a first tube bundle for circulation of a first fluid, a second tube bundle for circulation of a second fluid, and a shell that accommodates the tube bundles in series. Therefore, when a third fluid is circulated through the shell, it successively contacts the tube bundles, causing a heat exchange between the third fluid and one of the two first-mentioned fluids in the tubes, resulting in a heat transfer between three fluids. Heat exchangers can also be classified based on the flow arrangements, such as counterflow, parallel flow, crossflow, or cross-counterflow. There are several types of counterflow heat exchangers, which are categorized based on their flow arrangement and have opposite fluid flow directions. The best design for shelland-tube exchangers and double-pipe exchangers is a counterflow configuration, which maximizes heat transfer between fluids. In counterflow, the efficiency is higher than in parallel flow, and the temperature at the cooling fluid outlet can exceed the temperature at the warm fluid inlet. In Figure 5.4, a shell-and-tube heat exchanger with a counterflow in which cold fluid flows to the left while hot fluid flows to the right can be seen. Concurrent flow or parallel flow heat exchangers have streams flowing parallel to each other in the same direction as shown in Figure 5.5. They are less efficient than counterflow exchangers but provide more uniform wall temperatures.

162

Equipment and Components in the Oil and Gas Industry

FIGURE 5.4  A  shell-and-tube heat exchanger that operates in a counterflow configuration. (Courtesy: Shutterstock)

FIGURE 5.5  A parallel flow or concurrent flow heat exchanger. (Courtesy: Shutterstock)

The fluids in the hot and cold sections of a crossflow heat exchanger move perpendicularly to one another, as illustrated in Figure 5.6. Heat exchangers of this type are more efficient than those with counterflow. It is not uncommon to find hybrid flow types in industrial heat exchangers. A good example of this is the combination of crossflow and counterflow, as illustrated in Figure 5.6. There is also the possibility of categorizing heat exchangers based on the physical state of the hot and cold fluids, for example, liquids and gases, liquids and

Equipment for Fluid Temperature Changes

163

FIGURE 5.6  A crossflow and a hybrid heat exchanger. (Courtesy: Shutterstock)

solids, and gases and solids. In the case of direct contact heat exchangers, the classification “immiscible liquid–liquid” may also apply to liquids that cannot be blended. Water and oil, for example, are immiscible.

5.2.5 Types of Heat Exchangers Heat exchangers can be divided into four categories based on their construction: tubular heat exchangers, plate heat exchangers, extended surface heat exchangers, and regenerators. 5.2.5.1 Tubular Heat Exchangers In general, these exchangers are constructed of circular tubes, although they can also be constructed using elliptical, rectangular, or round/flat twisted tubes. Considering that the diameter, length, and arrangement of the tubes can be easily changed, there is a considerable amount of flexibility in the design. There is the possibility of designing tubular exchangers for high pressures in relation to the environment, as well as high pressure differences between fluids. Liquid-toliquid and liquid-to-phase change (condensing or evaporating) heat transfer applications are most commonly achieved using tubular exchangers. These exchangers are commonly used for gas-to-liquid and gas-to-gas heat transfer applications in which the operating temperature and/or pressure are very high, fouling is a severe issue on at least one fluid side, and no other type of exchanger would be suitable. An additional barrier to heat transfer can be the fouling of the surface of the wall material. Several factors can contribute to this problem, both on the side of the heating medium and on the side of the product. An excessively high or low temperature on the product side can be one of the causes, as well as particle deposits on the heating side. There are three types of tubular exchangers: shell-and-tube, double-pipe, and spiral tube heat exchangers.

164

Equipment and Components in the Oil and Gas Industry

5.2.5.1.1 Shell-and-Tube Heat Exchangers Shell-and-tube heat exchangers belong to a class of heat exchanger designs. In oil refineries and other large chemical processes, this is the most commonly used type of heat exchanger. In general, heat exchangers of this type consist of a shell (a large pressure vessel) inside of which a bundle of tubes is located. In order to transfer heat between the two fluids, one fluid flows through the tubes and another fluid flows over them (through the shell). There are several types of tubes that can be used in a tube bundle, including plain tubes, longitudinally finned tubes, and so on. This paragraph describes the working principles of a shell-and-tube heat exchanger, illustrated in Figure  5.7. The heat exchanger circulates two fluids with different starting temperatures through it. On the tube side, one flow flows through the tubes, and on the shell side, the other flows outside the tubes but within the shell. Through the tube walls, heat is transferred from one fluid to another, either from the tube side to the shell side or vice versa. Both the shell and tube can be filled with liquids or gases. For efficient heat transfer, a large area of heat transfer must be used, which results in the use of many tubes. The term one-phase or single-phase heat exchanger refers to heat exchangers with only one phase (liquid or gas) on each side. A two-phase heat exchanger can be used to heat a liquid in order to boil it into a gas (vapor), sometimes referred to as a boiler, or

FIGURE 5.7  A shell-and-tube heat exchanger. (Courtesy: Shutterstock)

Equipment for Fluid Temperature Changes

165

to cool the vapors and condense them into a liquid (called a condenser), with the phase change usually occurring on the shell surface. Shell-and-tube heat exchangers are based on the flow and thermal contact of two liquids and are relatively simple to design and operate. In shell-and-tube exchangers, different internal constructions can be utilized depending on the desired heat transfer and pressure drop performance, in addition to the methods employed for reducing thermal stresses, preventing leaks, making cleaning easier, controlling operating pressures and temperatures, controlling corrosion, accommodating highly asymmetrical flows, and so forth. A shell-andtube exchanger is classified and constructed in accordance with the widely used Tubular Exchanger Manufacturers Association (TEMA) standards, Deutsches Institut für Normung (DIN) and other European and international standards, and ASME boiler and pressure vessel codes. Three mechanical standards specify the design, fabrication, and materials for unfired shell-and-tube heat exchangers. There are generally severe requirements associated with petroleum processing and related applications in Class R. There are generally moderate requirements for commercial and general process applications in Class C. Chemical process applications are classified as Class B. ASME Boiler and Pressure Vessel Code, Section VIII, and other pertinent codes and/or standards are followed when building exchangers. TEMA standards are intended to complement and define the ASME code for the application of heat exchangers. Additionally, state and local codes applicable to the plant location must be followed. The terminology and vocabulary used to describe shell-and-tube heat exchangers are essential for understanding their design and operation. The vocabulary is defined in terms of letters and diagrams, shown in Figure 5.8. Specifically, the first letter describes the type of front header, the second letter describes the type of shell, and the third letter describes the type of rear header. An example would be BEM, CFU, or AES. As noted by TEMA, the front head channel and bonnet types are classified as follows: A, B, C, N, and D, while the shell is classified according to the location of the nozzles in the inlet and outlet. There are several types of shell configurations (E, F, G, H, J, K, X). The rear head is similarly classified (L, M, N, P, S, T, U, W). This section describes the components of shell-and-tube heat exchangers. A  shell-and-tube heat exchanger consist of a series of tubes enclosed within a cylindrical container known as a shell. In addition to containing the flowing medium, the housing/shell also houses the internal components. Additionally, it serves as a strong structural component upon which other components can be attached. Shells are constructed from either pipe up to 24” in diameter or rolled and welded plate metal. It is often recommended that carbon steel be used as the material of choice due to its economic advantages, but other materials suitable for extreme temperatures or corrosion resistance may also be specified. In determining fluid flow on the shell side, it is important to keep in mind that the shell is more expensive to fabricate than the tubes, and it is more difficult to clean as well. Tube fluid enters and exits through the front-end and rear-end heads. Many rear-end heads have been designed to accommodate tube thermal expansion.

166

Equipment and Components in the Oil and Gas Industry

FIGURE 5.8  TEMA heat exchanger standards.

Equipment for Fluid Temperature Changes

167

The front-end head is stationary, while the rear-end head can either be stationary (allowing for no thermal expansion of the tubes) or floating, depending on the thermal stresses between the tubes and shell. The tubes within the shell are collectively referred to as a tube bundle or a tube nest. There is a series of baffles and tube sheets (also known as tube stacks) through which each tube passes. The tube sheet is located within the shell and supports the ends of the tubes. The baffles (depending on the design) further support the weight of the tubes. In a heat exchanger, a tube sheet is a plate with holes drilled at optimal locations. These holes are then used to pass tubes through. It is the tube sheet that holds the tubes in place within the heat exchanger so that heat can be transferred effectively. Figures 5.9 and 5.10 illustrate the tube sheets used in heat exchangers. Tube sheets can be circular or rectangular in shape. Fixed tube sheets are perhaps one of the most standard types of tube sheets. They are used in situations where there are no harsh or challenging operating conditions. Basically, they are tubes that are fixed at both ends to the shell. A floating tube sheet, sometimes called a floating head, has one end fixed to the shell while the other floats freely within the shell. It is important to use this type of heat exchanger tube sheet when the product undergoes dynamic temperature changes. This could be a heat exchanger that cycles between hot and cold media. Therefore, when the heat exchanger is heated, one of the tube sheets is fixed and the other is free to move, allowing thermal expansion to occur. It is possible for tubes to expand or shrink as a result of temperature changes. When both ends of the metal are fixed, the pressure could lead to leaks or damage to the metal. By allowing for shrinkage and expansion, a floating design prevents stress on the joints. In applications where it is necessary to avoid mixing of the tube-side fluid with the shell-side fluid, double tube sheets are used (see Figure 5.11). Whenever leaks occur at the ends of tubes, the tube-side fluid will leak between the two tube sheets rather than into the shell. The baffles, also called baffle plates, as illustrated in Figure 5.12, perform two functions. First, they maintain the tubes in the proper position during assembly and operation, preventing vibrations caused by flow-induced eddies, and second, they guide the shell-side flow across the tube field, increasing velocity and heat transfer. As a matter of fact, increasing the flow turbulence in both the shell and tube can improve the efficiency of the heat exchanger as well as the heat transfer. Consequently, baffles are used to create turbulent flow within the shell, while tube inserts (also known as turbulators) are used to create turbulent flow within the tubes. Tube pitch refers to the distance between the centers of each tube hole. It is typically calculated as 1.25 times the outside diameter of the tubes. A minimum value of 1.25 is set because a ligament between two neighboring tube holes may become too weak to allow the tubes to be rolled into the tube sheet properly. For the purpose of securing parts of the heat exchanger, nuts and bolts are used. There should be a suitable tensile strength and corrosion resistance in the bolts chosen. Bolts are the male component of a nut and bolt assembly. The nut is the female part of a bolt and nut assembly.

168

Equipment and Components in the Oil and Gas Industry

FIGURE 5.9  Tube sheets in a shell-and-tube heat exchanger. (Courtesy: Shutterstock)

FIGURE 5.10  Tube sheets in a shell-and-tube heat exchanger. (Courtesy: Shutterstock)

Equipment for Fluid Temperature Changes

169

FIGURE 5.11  A double tube sheet.

The medium flowing within the tubes is known as the tube side medium. In the case of tubes, the flowing medium outside of the tubes is referred to as the shell side medium. There is one entry point and one exit point for each medium. Viscose fluids and fluids with a high flow rate are processed through the shell side, where there is increased turbulence and a greater transfer coefficient, resulting in an improved heat transfer process. Normally, large temperature changes are performed on the shell side. As a result of turbulent flow, heat is transferred more quickly and dissolved solids are less likely to accumulate on the surfaces of the tube and shell walls of the heat exchanger (turbulent flow has a self-cleaning effect). Besides single-pass heat exchangers, multi-pass heat exchangers are also important to understand. In order to increase the efficiency of a heat exchanger, it is economical and efficient to make the flowing media come into contact with each other multiple times. Heat is exchanged each time one medium passes over another. A single-pass heat exchanger is one in which one flowing medium passes over the other only once. A multi-pass heat exchanger is one in which one flowing medium passes over another more than once. In shell-and-tube heat exchangers, there can be one, two, four, six, or eight passes, which are written as 1–1, 1–2, 1–4, and so on. The first number indicates the number of shells. The second number indicates the number of passes. The heat transfer coefficient increases with an increase in the number of passes. One or more sets of U bends are typically used in multi-pass heat exchangers to reverse the flow in the tubes. The U bends in the heat exchanger allow the fluid to flow back and forth across its length. Shell-andtube heat exchangers of this type are referred to as U-tube heat exchangers (see Figure 5.13). In shell-and-tube heat exchangers, it is possible for a tube to rupture and for high-pressure (HP) fluid to enter and overpressurize the low-pressure (LP) side of the exchanger. Most exchangers are configured with the HP fluid in the tubes

170

Equipment and Components in the Oil and Gas Industry

FIGURE 5.12  Baffle plates. (Courtesy: Shutterstock)

Equipment for Fluid Temperature Changes

171

FIGURE 5.13  U-tube heat exchanger. (Courtesy: Shutterstock)

and the LP water, cooling, or heating medium on the shell. In the event of a tube rupture, the integrity of the shell may be compromised and flammable liquids or gases may be released, posing a risk to people and financial losses. It is essential that rupture discs or relief valves protect the shell of an exchanger from overpressure. It has been found that the opening time of protection devices is crucial to the protection of exchangers. This type of device is installed directly on the exchanger shell and discharges into a relief system. There are a variety of applications for shell-and-tube heat exchangers, and they are used in a wide range of industries. The fact that they are available in a variety of configurations makes them suitable for any manufacturing or production operation. This paragraph provides an overview of the advantages of shell-and-tube heat exchangers. It is important to note that the first advantage of this type of heat exchanger is its cost. As compared to plate-type exchangers, they are much less expensive. Furthermore, they are relatively inexpensive to maintain. Second, these heat exchangers have a high temperature working capacity. There is a wide range of temperatures that heat exchangers must be able to handle, which varies according to their application. As a result of their ability to withstand extreme temperatures, they are able to maintain production and keep operations running smoothly. It is important to note that shell-and-tube heat exchangers are capable of working at high temperatures and can be adapted to meet any need. Another advantage of shell-and-tube heat exchangers is their ability to function at high

172

Equipment and Components in the Oil and Gas Industry

pressures. As a result, the shells and tubes of shell-and-tube heat exchangers are tested and designed in accordance with the ASME and pressure equipment directive (PED) codes to withstand the extremes caused by pressure variances. A great deal of care should be taken when designing heat exchangers for high pressure applications in order to prevent very heavy weight for shells and tubes, which can increase the cost and weight of heat exchangers in addition to reducing their production rate. Loss of pressure causes downstream pressure loss, which slows the flow velocity. In shell-and-tube heat exchangers, pressure loss is minimized to meet the design criteria. The loss of pressure is affected by several variables, one of which is fouling of the shell and tubes. There can be an additional barrier to heat transfer if the surface of the wall material is fouled. Multiple factors may contribute to this problem, both on the heating medium side and on the product side. There are a number of possible causes, including particle deposits on the heating side and excessively high or low temperatures on the product side. Another advantage of shell-and-tube heat exchangers is their ease of adjustment. As a result of their design, shell-and-tube heat exchangers can be adapted to meet the needs of any production process. The diameter of the pipe, the number of pipes, the length of the pipes, the pitch of the pipes, and the arrangement of the pipes can be modified in order to meet the requirements of an application. Last, shell-and-tube heat exchangers are designed with multiple tubes, which allows for thermal expansion between the tubes and shell. As a result of this configuration, the heat exchanger is capable of handling flammable and toxic liquids. 5.2.5.1.2 Double-Pipe Heat Exchangers The double-pipe heat exchanger is a type of heat exchanger that utilizes two concentric pipes (one inside the other) for its operation, as illustrated in Figure 5.14. The inner pipe carries one fluid, and the annulus carries the other fluid in a counterflow direction to achieve the highest performance for a given surface area. It is possible, however, for the fluids to flow in a parallel flow direction if the application requires a nearly constant wall temperature. A double-pipe heat exchanger uses a true counter-current flow, which maximizes the temperature difference between the liquids on the shell side and the fluids on the tube side, thus requiring less surface area. In a heat exchanger, two separate flows are allowed to interact at a conductive barrier, allowing thermal energy to be transferred. In order to construct the double-pipe heat exchanger, metals or alloys that are highly heat resistant and corrosive resistant are used. A double-pipe heat exchanger is usually the simplest type of heat exchanger to install. In addition to being available in different sizes and configurations, they can be designed to work seamlessly (without a weld joint) with a variety of surfaces. Their flexible design makes it possible to quickly modify or replace parts. They are also energy efficient. Consider the type of working fluid as well as the amount of space required for the flow of the fluid when selecting a double-pipe heat exchanger. Depending on the project and the environment, the type of heat transfer required will also vary.

Equipment for Fluid Temperature Changes

173

FIGURE 5.14  A double-pipe heat exchanger.

5.2.5.1.3 Spiral Tube Heat Exchangers The spiral heat exchanger consists of two concentric spiral flow channels, one for each fluid, as illustrated in Figure 5.15. It contains two separate flow counters: one that enters at the center and flows toward the periphery and another that enters at the periphery and flows towards the center. Channels have a uniform cross-section and are curved. No risk of intermixing exists. Normally, the product channel is open on one side and closed on the other. Depending on the cleanliness of the heating/cooling medium, the channel for the heating/cooling medium may be closed on both sides. A  connection is located in the center of each channel and another on the periphery of each channel. It is particularly suitable for fluids that tend to cause fouling due to the spiral geometry, which has one channel for each medium and continuous curving. Due to this design, there is high flow turbulence, which significantly reduces the risk of fouling. In the event that fouling occurs in the heat transfer channel, the cross-section of this section of the channel is decreased. Because the entire flow must still pass through the channel, the velocity increases, and the resulting fluid force flushes away any accumulations of deposits. The design of this heat exchanger differs from that of shell-and-tube heat exchangers where the flow enters parallel tubes. Whenever tubes become fouled, there is an increase in pressure drop, which forces the fluid to seek alternative flow paths. As a result, fouling and clogging of the tubes occur very quickly in shell-and-tube heat exchangers. Essentially, this type of heat exchanger consists of two or more spirally wound coils enclosed in a shell. The rate of heat transfer associated with a spiral tube is greater than that associated with a straight

174

Equipment and Components in the Oil and Gas Industry

FIGURE 5.15  A spiral tube heat exchanger.

tube. Additionally, spiraling can accommodate a considerable amount of surface area in a given space. There is no problem with thermal expansion, but cleaning is almost impossible. 5.2.5.2 Plate Heat Exchangers A plate heat exchanger (see Figure 5.16 and 5.17) is a type of heat exchanger that transfers heat between fluids by using metal plates. As the fluids are spread out over the plates, they are exposed to a larger surface area than a conventional heat exchanger. A result of this is that the transfer of heat is facilitated, and the rate of temperature change is greatly accelerated. Plate-type heat exchangers are typically constructed with thin plates. There is either a smooth surface or a corrugated surface on the plates, and the plates are either flat or wound in an exchanger. Plates used in a plate and frame heat exchanger are obtained by pressing metal plates together in one piece. Because of its ability to withstand high temperatures, its strength, and its resistance to corrosion, stainless steel is often used for plates. Rubber sealing gaskets are often placed around the edge of the plates to ensure plate separation. As the liquid flows through the channels in the heat exchanger, the plates are formed into grooves in the carrying bar at right angles to the liquid flow direction. 1.3–1.5-mm gaps are provided between the grooves, which interlink with the other plates to form the channel. A rigid frame compresses the plates to form an arrangement of parallel flow channels with alternate hot and cold fluids. There is an extremely large surface area on the plates, which facilitates the fastest possible transfer of energy. As a result of the thinness of each chamber (distance between two plates), most of

Equipment for Fluid Temperature Changes

175

FIGURE 5.16  Plate type heat exchanger.

FIGURE 5.17  Plate type heat exchanger.

the liquid will contact the plate, aiding in the exchange of gases. Moreover, the grooves maintain a turbulent liquid flow within the exchanger in order to maximize heat transfer. It is possible to achieve a high degree of turbulence at low flow

176

Equipment and Components in the Oil and Gas Industry

rates, which in turn results in a high heat transfer coefficient. Plates are suspended from a carry bar and clamped together with clamping bolts. As the plates are compressed together, they are referred to as a plate stack. During the opening and closing of the plate stack, a guide bar ensures that the plates are aligned properly. Located at the back and front of the heat exchanger, back and front plates are parallel to the exchanger internal plates. The working principles of plate heat exchangers are explained in this paragraph. As the hot medium flows through the heat exchanger, gaskets direct it. There is an alternating pattern of gaskets on each plate. It is important to note that the hot medium flows into the space between a pair of plates but does not flow into the space between the next pair of plates due to the gaskets. In this manner, each subsequent set of plates is filled with the hot flowing medium. Similarly, the cold medium enters the heat exchanger through the cold medium inlet, but this time the gaskets are positioned so that the cold medium flows into the space where there is no hot medium. Both hot and cold fluids are now flowing through the heat exchanger. The two media flow out of their respective outlets, and the process is continuous. It is important to note that the two flowing media are always adjacent to each other during the entire process. Thus, the flowing media have a hot, cold, hot, cold flow pattern as they pass through the heat exchanger. There is no mixing between the two flowing media due to the gaskets and plates that completely separate them. Heat is exchanged between the flowing media as a result of their close proximity. In the engineering world, plate heat exchangers have become widely used due to their efficiency, robustness, and relatively easy maintenance. There is a general limitation to the pressure, temperature, or difference in pressure and temperature that these exchangers can accommodate. In this regard, the plate heat exchanger (PHE) is a specialized design that is well suited for the transfer of heat between medium- and low-pressure fluids. 5.2.5.3 Extended Surface Heat Exchangers An extended surface is one that has fins attached to the primary surface on one side of a two-fluid or multifluid heat exchanger. It is possible for fins to have a variety of shapes: plain, wavy, or interrupted, and to be attached to the inside, outside, or both sides of circular, flat, or oval tubes or parting sheets. During the study of heat transfer, fins are surfaces that extend from an object in order to enhance heat transfer to or from the environment by increasing convection. The amount of heat transferred by an object depends on its conduction, convection, or radiation properties. Increasing the gradient of temperature between the object and the environment, increasing the convection heat transfer coefficient, or increasing the surface area of the object will increase the transfer of heat. A fin is typically attached to a tube by brazing, soldering, welding, adhesive bonding, or mechanical expansion, or it may be extruded or integrally connected to the tube. The fin material generally has a high thermal conductivity, which is exposed to a flowing fluid. Heat exchangers with extended surfaces fall into two main categories: plate-fin heat exchangers and tube-fin heat exchangers.

Equipment for Fluid Temperature Changes

177

5.2.5.3.1 Plate-Fin Heat Exchangers In this type of exchanger, corrugated fins (usually triangular or rectangular in shape) or spacers are sandwiched between parallel plates (known as plates or parting sheets), as illustrated in Figure 5.18. As a result of its high surface area to volume ratio, it is often referred to as a compact heat exchanger. Plate-fin heat exchangers are constructed of corrugated sheets separated by flat metal plates, typically aluminum, in order to create finned chambers. Heat exchangers contain alternating layers of hot and cold fluid streams enclosed by side bars at the edges. Through the fin interface, heat is transferred from one stream to the separator plate and then through the next set of fins to the adjacent stream. Furthermore, fins enhance the structural integrity of the heat exchanger, allowing it to withstand high pressures while providing an increased surface area for heat transfer. A high degree of flexibility is present in the design of plate-fin heat exchangers, as they can operate with any combination of gas, liquid, and two-phase fluids. Different entry and exit points are available for each stream, along with a variety of fin heights and types that accommodate heat transfer between multiple process streams. There is no difficulty in rearranging the fins in a plate-fin heat exchanger. It is possible for the two fluids to flow crossflow, counterflow, cross-counter flow, or parallel. Due to the high level of detail necessary during the manufacturing process, plate-fin heat exchangers are generally more expensive than conventional heat exchangers. Nevertheless, the cost savings that are generated by the addition of heat transfer can often outweigh these costs. 5.2.5.3.2 Tube-Fin Heat Exchangers A tube-fin heat exchanger, also known as a finned coil heat exchanger or a finned tube heat exchanger, consists of tubes that pass through a dense fin stack and are mechanically supported by a mounting frame. During the heat exchange process, fluid passes through the tube coils, conducts heat to the fins, and dissipates heat

FIGURE 5.18  Plate-fin heat exchanger.

178

Equipment and Components in the Oil and Gas Industry

into the air forced through the heat exchanger. Finned tube heat exchangers have tubes with an extended outer surface area or fins to enhance the efficiency of heat transfer. In cases where the outside of the tubes have a low heat transfer coefficient, finned tube heat exchangers are preferred. By creating an extra heat transfer area with fins, we are able to ensure that the required rate of heat transfer is achieved. As a result of increasing the effective heat transfer area between the tubes and the surrounding fluid, finned tubes or tubes with an extended outer surface area enhance the rate of heat transfer. Fluids surrounding finned tubes may be process fluids or air. A tube-fin exchanger typically consists of round or rectangular tubes, although elliptical tubes may also be used. Generally, fins are applied to the outside of the tubes, but some applications may require fins to be applied to the inside. A tight mechanical fit, tension winding, adhesive bonding, soldering, brazing, welding, or extrusion are all methods of attaching the electrodes to the tubes. Finned tube heat exchangers can be divided into longitudinal and transverse types. As shown in Figure 5.19a, tubes have longitudinal fins that run along their length. The longitudinal fins can either have flat or tapered cross-sections. There are many correlations available for evaluating the heat transfer coefficient on the outer surface of tubes with different cross-sectional geometries. The longitudinal fins of a tube are best suited for applications where the flow outside of the tubes is expected to be streamlined along the tube length, for example, in double-pipe heat exchangers. The transverse fins of the finned tubes are hollow metal discs spaced apart along their length (see Figure 5.19b). There are two types of transverse fin discs: flat and tapered. (a)

FIGURE 5.19  (a) Longitudinal finned tube heat exchanger.

Equipment for Fluid Temperature Changes

179

(b)

FIGURE 5.19 (Continued)  (b) Transverse finned tube heat exchanger.

5.2.5.4 Regenerators Regenerative heat exchangers, or regenerators, are heat exchangers that store heat from the hot fluid intermittently in a thermal storage medium (matrix) before transferring it to the cold fluid. Typically, the storage medium consists of a solid material, matrix, or packing with a high thermal capacity, such as ceramic material, metal, or phase change material. In order to accomplish this, the hot fluid is brought into contact with the heat storage medium and then displaced by the cold fluid, which absorbs the heat. Therefore, in a regenerative heat exchanger, heat is transferred by alternating the flow of two fluid streams through the storage medium in a cyclical manner. In the first part of the cycle, one fluid stream passes through the storage medium, where it is heated, while the other fluid stream is diverted. During the second phase of the cycle, the roles of the two fluid streams are reversed, with heated fluid being diverted away and cooled fluid now passing through the storage medium to be heated. In contrast to other types of heat exchangers, which transfer heat directly and immediately from a hot fluid to a cold fluid, both passing through the exchanger simultaneously, the operation of a regenerative heat exchanger involves temporarily storing the heat transferred in a packing with adequate thermal capacity. As a consequence, in regenerative heat exchangers or thermal regenerators, the hot water and cold water pass through the same channels in the packing, alternately washing the same surface area. During the recuperation process, hot and cold fluids pass through different but adjacent channels at the same time. Regenerative heat exchangers can be classified into several types. The first type of regenerator is a fixed matrix or bed regenerator. To transfer heat between two fluid streams, this type of regenerator uses a fixed, stationary matrix. Various ports control the flow of fluid into and out of the matrix, with valves or other mechanisms controlling the direction of flow. In order to maximize heat transfer, the matrix is usually composed of a material with a high thermal conductivity, such as metal, ceramic, or graphite. When a fixed matrix regenerator operates, a

180

Equipment and Components in the Oil and Gas Industry

hot fluid stream passes through the matrix for a specified period of time, known as the “hot period,” during which time it transfers heat to the matrix. The hot fluid is shut off at the end of the hot period, and a cold fluid stream is introduced into the matrix, flowing in the opposite direction. Fluids flowing through a matrix absorb heat stored in the matrix during the hot period, warming up as a result. Second, there are rotary heat exchangers. In these heat exchangers, heat is transferred between two fluid streams by means of a rotating wheel or drum. Most wheels and drums are made of a thermally conductive material, such as metal or ceramic, and are divided into channels or compartments. As the hot fluid stream enters a rotary regenerator, it transfers heat to the material in the channels or compartments on one side of the wheel or drum. The hot fluid is shut off as the wheel or drum rotates, and a cold fluid stream is introduced into the opposite side, flowing in the opposite direction to the hot fluid. During the course of passing through the channels or compartments, the cold fluid absorbs the heat stored in the material and warms up as a result. The third type of regenerator is the fluidized bed. It is important to note that in these heat exchangers, the storage medium is a fluidized bed of particles that is continuously circulated between the two fluid streams. Heat is transferred from the hot fluid to the cool fluid as the particles move between the two streams. There are several advantages to using a regenerator: 1. Simple inlet and outlet header design: Regenerators have simple inlet and outlet headers. In counter-flow regenerators, hot and cold fluids pass through different sections of the matrix, while rotary regenerators can optimize the flow sectors for both hot and cold fluids. Therefore, the matrix can be optimized to minimize pressure drop, thereby reducing the amount of pressure required to move through it. 2. Larger surface area per unit volume: There is a large surface area per unit volume in a regenerator. The reason for this is that the regenerator comprises a matrix that contains numerous channels that are in direct contact with the hot and cold fluids. Its large surface area facilitates efficient heat transfer between the fluids, resulting in a more compact design. 3. Ideal for applications involving gas–gas heat exchange: Because they have a low surface density and a counter-flow arrangement, they are able to transfer heat more efficiently. As a result of the large surface area of a regenerator, the lower heat transfer coefficient of gases is compensated for, resulting in efficient heat transfer. 4. Self-cleaning matrix surfaces: The matrix surfaces of regenerators have self-cleaning properties that reduce fouling and corrosion on the fluid side. The matrix continuously switches between hot and cold fluids, which prevents deposits from building up on the matrix surface. Furthermore, the matrix surface is

Equipment for Fluid Temperature Changes

181

generally rough and porous, resulting in turbulence and preventing stagnant fluid pockets from forming. There are two disadvantages to using a regenerator: 1. Mixing of fluid streams: Due to the transfer of a small fraction of one fluid stream into the other, regenerative heat exchangers always have a small amount of mixing between hot and cold fluid streams. Due to the fact that both streams share the same matrix, it is not possible to completely separate them. When the two fluid streams are mixed, the effectiveness of the heat exchanger may be reduced since the transfer of energy between the two fluids may not be fully achieved. It may also be undesirable in some applications to mix fluid streams, particularly when dealing with liquids or phase-changing fluids where contamination may be a significant issue. 2. Stress on components: As a result of continuous cycles of heating and cooling, regenerative heat exchangers can place significant stress on their components. Heat exchanger materials may crack or break due to the high temperature differential between the hot and cold fluids, as well as the thermal expansion and contraction of the matrix and other components. In extreme circumstances, this can lead to a decrease in efficiency and an increase in maintenance costs, as well as safety concerns. Regenerative heat exchangers can mitigate these problems through proper design and material selection; however, they remain a potential disadvantage.

5.3 BOILERS 5.3.1 Introduction Steam generators produce steam at the desired rate, pressure, and temperature by burning fuel in their furnaces. Boilers are components of steam generators where liquids (water) become vapors (steam), essentially at constant pressure and temperature. However, the term “boiler” is traditionally used to refer to the entire steam generator. Thus, a steam boiler is a closed vessel in which water is heated, vaporized, and converted into steam at a pressure greater than atmospheric pressure. As defined by the American Society of Mechanical Engineers, a boiler consists of “A combination of apparatus for producing, finishing and recovering heat together with apparatus for transferring the heat so that it is available for heating and vaporizing the fluid.” Boilers are also known as tools for the conversion of chemical energy in fuel into heat energy and from heat energy into steam potential energy. A boiler is an important tool in the modern world due to its ability to generate steam from a relatively cheap and readily available source of energy, water. Power generation is a necessity, and power must be produced

182

Equipment and Components in the Oil and Gas Industry

in extraordinary quantities. Power generation facilities require steam for several reasons, including the fact that steam can be produced anywhere in the world provided there is fuel as a heat source in the area. Since steam comes from water, it is non-toxic and can be recycled from steam to water using a condenser. Steam boilers are engineered today to be both economically viable as well as efficient in their use of steam. In addition to developing electrical energy, boilers are used in steam turbines to generate electricity, to run steam engines, to heat buildings during the winter, and to produce hot water. Boilers operate on the principle that any type of fuel can burn in presence of air and produce flue gases that are very hot (hot fluid). The feed water is introduced into the system from the other side (cold fluid) at atmospheric pressure and temperature. During the exchange of heat between hot and cold fluids, the temperature of the cold fluid (water) rises, causing the steam to form. As a result of the decrease in flue gas temperature (hot fluid), the hot fluid is discharged into the atmosphere through the stack or chimney. As part of its function, boilers provide heat transfer surfaces, storage spaces for water and steam, furnaces for burning fuel, and equipment necessary to control safe operation in order to facilitate steam generation. It is common for boilers to have cylindrical drums or shells and tubes, except for one-pass boilers that do not use a drum. Thus, boilers are simply heat exchangers in which water is used as a cold fluid and flue gases are used as a hot fluid. Heat is transferred from hot to cold fluid through convection, which increases the energy of water and converts it into steam. In terms of boiler material selection, the pressure vessel is usually made of steel (or alloy steel) or historically of wrought iron. ASME Boiler Code prohibits stainless steel from being used in wetted parts of modern boilers, but it is commonly used in superheaters that are not exposed to liquid boiler water. When it comes to live steam models, copper or brass is often used because it is easier to fabricate in smaller sizes. Because copper is more formable and has higher thermal conductivity, it has historically been used in fireboxes (especially those used in steam locomotives); however, the high price of copper in recent times has made this an uneconomic choice, which has resulted in the use of cheaper substitutes (such as steel). A boiler and its important components are shown in Figure 5.20. In this section, we will discuss the essential parts and components of the boiler in greater detail. In the oil and gas industry, boilers are an integral part of operations. Various fuels, such as natural gas, oil, and coal, are used to generate steam, electricity, and energy. Industrial and commercial boilers are commonly used in a variety of applications, from small-scale manufacturing plants to large-scale refineries. Boilers have been a major contributor to the economy of the United States for decades thanks to their use in the oil and gas industries. Steam boilers are the most commonly used boilers in the oil and gas industry. In refineries and manufacturing plants, steam boilers are used to generate steam and power for use in various pieces of equipment. As a general rule, steam boilers are typically powered by natural gas, oil, or coal and are used in both small- and large-scale operations. Boilers are used for a wide variety of applications in the oil and gas

Equipment for Fluid Temperature Changes

183

FIGURE 5.20  A boiler and its components.

industry. Steam is one of the most common applications for this technology. In refineries and manufacturing plants, steam is used to power various pieces of machinery. Furthermore, boilers can be used to generate hot water for various purposes, such as cleaning and sanitation. Additionally, boilers are used to generate heat for various processes, including distillation, drying, and refining crude oil and natural gas.

5.3.2 Boiler Terms Accessories: In the boiler industry, accessories are items that are used in order to increase boiler efficiency. It refers to the devices that are integral parts of a boiler but are not mounted on it. A superheater, an economizer, and a feed pump are some of these components. Burner: To maintain ignition and combustion of the fuel within the furnace, the burner introduces fuel and air to the furnace at the necessary velocities, turbulence, and concentration. Blowing off: This process involves removing mud and other water impurities from the boiler’s lowest part. This is accomplished through the use of a blow-off cock or valve. Flue gases: A  boiler furnace produces flue gases as a result of the combination of fuels used. It is common for flue gases to contain ­ water vapor (H2O), carbon dioxide (CO2), carbon monoxide (CO), and

184

Equipment and Components in the Oil and Gas Industry

nitrogen (N2). The flue gas contains both complete and incomplete combustion products. Foaming: Steam contamination by boiler water solids is known as boiler water carry-over. A layer of bubbles, or foam, builds up on the surface of the boiler water and is expelled with the steam. There is a condition known as foaming, which occurs when there is a high concentration of solids in the boiler water. However, it is generally believed that certain substances, including alkalis, oils, fats, greases, certain types of organic matter, and suspended solids, are particularly conducive to foaming. Furnace: In a boiler, the furnace is the part where the fuel is burned to produce heat. In the boiler, this heat is used to generate steam. The furnace is also known as combustion chamber or fire box, which refers to the space beneath the boiler shell, where fuel is burned to produce steam from water within the shell. Grate: A grate is a space (platform) in the furnace on which fuel is burned. A grate is a combination of several cast-iron bars is arranged in such a way that the fuel can be placed on them. It is always necessary to provide some space between consecutive bars so that fuel may flow from beneath the grate and ashes may fall into the ash pit provided beneath the grate. There are two types of grates: circular and rectangular. Grate area: Generally, the area of the grate on which the fuel burns is referred to as the grate area. The area of a grates is always measured in square meters. Heating surface: This refers to the part of the boiler surface that is exposed to the fire (or hot gases emanating from the fire). Mounting: Mountings are items that are used to ensure the safety of a boiler. Scale: Due to conditions in the boiler water, a deposit of a medium is formed on the water heating surfaces due to extreme hardness. Boiler feed water treatment systems may include the technologies necessary to remove problematic dissolved solids, suspended solids, and organic matter. Shell: Boiler shells consist of steel plates riveted or welded together to form a hollow cylindrical body. In order to close the shell ends, end plates are used. Water and steam spaces: Water space refers to the volume of the boiler occupied by water. Steam space refers to the remaining space that is used for storing steam in the boiler until it is removed via the steam line. Water level: Water level refers to the height of the water in the boiler.

5.3.3 Boiler Types or Classifications Many boiler designs are available, and they can be categorized according to the following factors: • Location of boiler shell axis • Boiler pressure

Equipment for Fluid Temperature Changes

• • • • •

185

Flow medium inside the tube Circulation of water Furnace position Type of fuel used Number of tubes

5.3.3.1 Location of Boiler Shell Axis In terms of the shell axis, there are three types of boilers: horizontal, vertical, and inclined. Boilers whose axis is horizontal are known as horizontal boilers. Boilers with vertical axes are called vertical boilers, while those with inclined axes are called inclined boilers. Vertical and horizontal boilers are illustrated in Figure 5.21. 5.3.3.2 Boiler Pressure Boilers are classified according to their pressure into three categories: high, medium, and low pressure. A high-pressure boiler is one that operates at a pressure greater than 80 bar. The medium-pressure boiler has a working pressure of steam of 20 bar to 80 bar. It is used for power generation or process heating. A low-pressure boiler produces steam at a pressure between 15 and 20 bars. The purpose of this is to heat the process. 5.3.3.3 Flow Medium inside the Tube Depending on the flow medium inside the tube, there are two types of boilers: fire tube and water tube (see Figure 5.22). In a fire tube boiler, hot flue gases are contained within the tubes, and water surrounds the tubes. A water tube boiler consists of tubes that contain water and hot gases on the outside. This paragraph provides more detailed information about fire tube and water tube boilers. When a fire tube boiler is operated, hot gases produced by the combination of fuels in the boiler furnace are forced through a series of tubes (called

FIGURE 5.21  Vertical shell (left) and horizontal shell (right) boilers.

186

Equipment and Components in the Oil and Gas Industry

FIGURE 5.22  Water tube vs fire tube boilers.

fuel tubes or smoke tubes) that are submerged in water in order to reach the chimney. The walls of tubes transfer heat from the hot gases to the water. Water-tube boilers are the type of boiler in which water flows through a number of tubes (called water tubes), and the hot gases that are produced during the combustion of fuel in the boiler furnace pass around the tubes. Through the walls of the water tubes, the hot gases transfer their heat to the water. 5.3.3.4 Circulation of Water Water circulates in two ways: (1) free (natural) circulation (2) forced circulation. Natural circulation boilers circulate water due to the difference in density caused by the temperature of water. Suppose the bottom of a vessel containing water is heated. The density of the water in the bottom decreases in comparison to the density of the water in the upper part of the vessel when the bottom portion is heated. As a result, the less dense water on the bottom of the vessel rises, and the more dense and cold water on the upper part of the vessel descends to take its place, creating a convection current in the water until all water is the same temperature. A boiler that circulates water with the assistance of a pump is referred to as a forced circulation boiler. Pumps are used in forced circulation boilers to maintain a continuous flow of water. The pump creates pressure that causes the water to circulate in such a case. There are a number of high-pressure, high-­capacity boilers that utilize the forced circulation system, all of which are water tube boilers. As a result of free circulation of water, it is possible to maintain a uniform temperature throughout the boiler, thus preventing unequal expansion in various parts of the boiler. Additionally, free circulation of water facilitates the escape of steam from the heating surface as soon as it is formed. In the event that steam does not escape quickly after it has been formed, the boilerplates will not remain continually in contact with water, leading to an overheating of these plates.

Equipment for Fluid Temperature Changes

187

The following are some of the advantages of forced circulation: There is a higher rate of heat transfer from the flue gases to the water. It is possible to use tubes with relatively small diameters. As a result, the boiler’s overall weight is reduced. It may be possible to reduce the number of boiler drums required. There is a reduction in the amount of scale that must be formed in the boilers. It is possible to generate steam quickly. It is unlikely that the boilerplates will overheat. 5.3.3.5 Furnace Position Depending on the position of the furnace, there are two types of boilers: internally fired and externally fired (see Figure 5.23). In the case of internally fired boilers, the furnace is located inside the drum or shell of the boiler. A boiler that has the furnace located outside of the drum is referred to as an externally fired boiler. 5.3.3.6 Type of Fuel Used There are several types of fuels used in boilers, including solids, liquids, gases, and electricity. Solid fuel boilers are those that obtain energy by burning solid fuels such as coal or lignite to produce heat. Boilers that burn liquid or gaseous fuel are known as liquid or gaseous fuel boilers. Boilers that generate heat by using electrical or nuclear energy are referred to as boilers powered by electrical energy or boilers powered by nuclear energy. 5.3.3.7 Number of Tubes Boilers can be classified into the following categories based on the number of tubes they contain: 1. single tube boiler 2. multi-tube boiler. Due to its single flue tube, the Cornish boiler may be referred to as a single-tube boiler. As Cochran boilers have a number of flue tubes, they may be considered multi-tube boilers.

FIGURE 5.23  Internal and external furnace boilers.

188

Equipment and Components in the Oil and Gas Industry

5.3.4 Boiler Selection In order to select an ideal boiler, a number of factors must be considered. The following requirements are listed:

1. It should produce the maximum quantity of steam while using the least amount of fuel. 2. It should be economical to install and require little maintenance during operation. 3. It should be able to handle fluctuations in load quickly. 4. It should be capable of starting quickly. 5. It should be light in weight. 6. It should occupy a small space. 7. It is important to have a few joints that can be inspected easily.

Following are some factors that should be considered when selecting a steam boiler type and size:

1. The amount of power and pressure required. 2. The rate at which steam will be generated. 3. A description of the power house’s geographical location. 4. There is a supply of fuel and water. 5. A description of the type of fuel to be used. 6. The probable load factor.

5.3.5 Boiler Mountings Blow-off-cock: This is a controllable valve that is positioned at the bottom of the boiler’s water space, and it is used to remove mud or sediments that have settled at the bottom of the boiler during normal operation. It is also used to completely empty the boiler’s water when it has been shut off for cleaning purposes or for inspection and maintenance purposes. Feed check valve: The feed check valve is located after the feed pump in the feed water line of the boiler. In a boiler, it allows water to flow in when the discharge pressure of the feed pump is greater than the inside steam pressure and prevents backflow when the feed pump pressure is less than the boiler pressure. A feed check valve is located slightly below the normal water level in the boiler. Fusible plug: A fusible plug serves to protect the boiler from damage caused by overheating of the boiler tubes due to low water levels. Fusible plugs are safety devices used in steam boilers to prevent overheating and explosions. It consists of a threaded cylindrical object, usually made of brass, bronze, or gunmetal, with a tapered hole drilled completely through its length. A metal with a low melting point, such as tin or lead, is used to seal the hole. Fusible plugs serve as safety valves when dangerous temperatures, rather than dangerous pressures, are reached in a closed vessel.

Equipment for Fluid Temperature Changes

189

Pressure gauge: The pressure of steam in the boiler is indicated by a pressure gauge. In general, it is located on the front top of the boiler. There are two types of pressure gauges: (1) Bourdon tube pressure gauge and (2) diaphragm pressure gauge. Both of these gauges have a dial on which a needle moves over a circular scale in accordance with the pressure. A reading of zero is obtained at atmospheric pressure. In certain gauges, only positive pressure is indicated, but in some gauges, both positive and negative pressures are indicated. By looking at the gauge, the boiler operator can determine whether the boiler is operating at a safe working pressure and take appropriate action to ensure that it is. In the event that the pressure within the boiler exceeds the safe limit, the material of the boiler shell may fail and burst, causing serious damage to people and property. With the help of a pressure gauge, it is very important to continuously monitor the pressure in a boiler. Safety valve: In a boiler, a spring-loaded safety valve is mounted safely on the boiler shell and serves as a safeguard against high pressure. In order to prevent a boiler from bursting under high pressure and thus to save lives and property, it is crucial that it be kept in good working condition at all times. Steam stop valve: In the boiler, it is installed between the steam space and the steam supply line. Its primary function is to regulate the flow of steam from the boiler to the steam line. A valve such as this is used to regulate the flow of steam from the boiler to the steam pipe. During the steaming process, it opens when there is a need for steam and shuts off when there is sufficient steam in the steam pipe. Water level indicator: By means of a glass tube, a water level indicator is mounted outside the boiler shell to indicate the water level in the boiler. No matter what type of boiler you have, the water level should remain at the specified level. When the water level drops below the level due to the change in phase from water to steam, and fresh water does not fill in simultaneously, the hot surface may be exposed to steam alone and overheat. This is due to the fact that steam has a very low heat transfer coefficient compared to water. Overheating may result in damage to the tube surface. It is imperative that the level of water in the boiler be continuously monitored and maintained by the operator by keeping an eye on the water level indicator in order to prevent this situation.

5.3.6 Boiler Accessories Boiler accessories are those components that are attached to the boiler (not mounted on it) and are important for the proper operation and efficiency of the boiler. The following is a list of various boiler accessories: Feed pump: Water is fed into the boiler using a feed pump placed near the boiler. The pump works at a high pressure and is used to feed water to the boiler. In addition to supplying water to the boiler, the

190

Equipment and Components in the Oil and Gas Industry

FIGURE 5.24  A boiler high-pressure feed pump. (Courtesy: Shutterstock)

feed pump must have a discharge pressure sufficient to push the water into the boiler since boilers operate at high pressures. In Figure 5.24, we can see an illustration of a high pressure boiler feed pump. There are two types of pumps commonly used as feed pumps: reciprocating pumps and rotary pumps. Chapter 4 provides more information about pumps. Economizer: A boiler economizer is used to preheat water before it enters the boiler drum. In order to preheat the water, the economizer utilizes the heat from the flue gases. After leaving the boiler, flue gases pass through an economizer and then are released into the atmosphere. As a result, boiler efficiency is increased. Hence, an economizer is a heat exchanger designed to recover the heat energy of outgoing flue gases and use it for preheating boiler feed water. By increasing the boiler’s thermal efficiency, it conserves heat energy and hence fuel and lowers its operating costs. As a matter of fact, once steam is produced, flue gas exits the system. Some heat energy remains in the flue gas when it is emitted. This heat energy is lost if it cannot be utilized. A boiler economizer uses

Equipment for Fluid Temperature Changes

191

a portion of the remaining energy from the flue gas to heat the boiler’s inlet water (feed water). A boiler economizer has simple construction and operating principles (see Figure 5.25). In the bottom part, there is a horizontal inlet pipe that supplies water with a normal temperature to the economizer. In addition to the horizontal pipe at the top of the economizer, there is also a vertical pipe. These two horizontal pipes, which are the bottom and top pipes, are connected by a group of vertical pipes. In order to supply hot water to the boiler, an outlet valve is mounted on the top horizontal pipe. The flue gases from the boiler furnace pass through the vertical pipes of the economizer. During the passage of the water through the vertical pipes to the top horizontal pipe, the flue gases transfer remaining heat to the water through the surface of the vertical pipes. By using the economizer, the heat from the flue gases can be utilized to heat the water and produce steam before flue gases exit the boiler. Air preheater: A pre-heater is designed to further utilize the heat of flue gases after they have exited the economizer by pre-heating the air used in a furnace or oil burner. The purpose of the air pre-heater is to raise the temperature of air before it enters the furnace. It is located after the economizer. The flue gases are passed through the economizer to the

FIGURE 5.25  A boiler economizer.

192

Equipment and Components in the Oil and Gas Industry

air preheater. The degree of preheating depends on the type of fuel, the type of fuel burning equipment, and the operating rate of the boiler and furnace. Steam separator: Steam separators are used to remove entrained water particles from the steam conveyed to a steam engine or turbine. On the main steam pipe from the boiler, it is installed as close as possible to the steam engine. Superheater: Steam superheaters are coil-type heat exchangers used to produce superheated steam or to convert wet steam into dry steam generated by boilers. In most boilers, the superheater is located in the flue gas path, where it is heated by the hot flue gases. Superheaters are available in a variety of materials, including steel, copper, and stainless steel. Superheaters in boilers provide the following benefits: increased efficiency of the steam power plant, minimized erosion of turbine blades, reduced steam consumption, reduced condensation loss in boiler steam pipes, and increased saturation of steam by removing entrained water particles from turbine steam. In Figure 5.26, a superheater is depicted.

FIGURE 5.26  A superheater in the boiler. (Courtesy: Shutterstock)

Equipment for Fluid Temperature Changes

193

5.4 AIR COOLERS (AIR-COOLED HEAT EXCHANGERS) 5.4.1 Introduction In order to cool fluids, two sources are readily available, both of which are relatively inexpensive, to transfer heat (air and water). Water shortages and rising costs, as well as concerns about water pollution and cooling tower plumes, have greatly reduced the use of water-cooled heat exchangers in industry. The result is that a significant proportion of the process cooling in refineries, chemical plants, and power plants is provided by air-cooled heat exchangers (ACHEs). In the refinery sector, these are known as air fin coolers (AFC) or fin fan coolers (FFC) and in the power sector as air-cooled condensers. The air-cooled heat exchanger discharges heat directly from fluids into the ambient air. Air-cooled heat exchangers are one of the most commonly used types of heat exchangers in process, power, steel, and several other industries where process systems generate heat that must be removed. Various process media are directly cooled by atmospheric air using the air-cooled heat exchanger. You can find air-cooled heat exchangers that are as small as a radiator in your car or as large as several acres of land, such as those used in large power plants without access to water. The obvious advantage of an air cooler is that it does not require water, so equipment requiring cooling does not need to be near a water supply. Additionally, government regulations and environmental concerns have increased the costs associated with treating and disposing of water. It is possible to transfer heat from fluid or gas into ambient air using an air-cooled heat exchanger without causing environmental concerns or requiring a significant associated cost. Generally, aircooled heat exchangers are used to cool gases and liquids in situations where the outlet temperature must be greater than the surrounding ambient air temperature, covering a wide range of industries and products. Gas compressor packages, gas transmission facilities, engine cooling, condensation of gasses, and steam are among the applications. There is only one disadvantage that these users have in common: the need to eject heat into the atmosphere. In some of these applications, the discharge air from the air cooler is also used to assist in heating buildings or other equipment in order to prevent the heat from entering the air.

5.4.2 Air Cooler Advantages and Disadvantages The following are some of the advantages of air-cooled heat exchangers:

1. An air-cooled heat exchanger generally has a lower operating cost than a water-cooled heat exchanger (WCHE). WCHE operating costs include the cost of make-up water for the cooling water, the power required for the cooling tower fans and for the circulating pump, and cooling tower maintenance. ACHE operating costs include the cost of power consumed by fans. As water costs increase day by day, the difference between WCHE and ACHE in operating costs increases as well.

194

Equipment and Components in the Oil and Gas Industry



2. Fouling or scale formation does not take place with air cooling. 3. Thermal or chemical pollution of water resources is avoided. 4. As a result of the elimination of the coolant water piping, installation is simplified. 5. Eliminates high water costs, including water treatment expenses. 6. The location of the air-cooled heat exchangers is independent of the location of the water supply. 7. By means of shutters, adjustable fan blades, variable speed drives, or, in the case of multiple fan installations, shutting off fans as necessary, the temperature of the process fluid can be easily controlled. 8. It is generally claimed that water coolers require 1/3 or less maintenance than air conditioners. The following are some of the disadvantages of air-cooled heat exchangers: 1. ACHEs have a higher fixed cost than WCHEs. Air has a lower heat transfer coefficient than cooling water; therefore the area required for heat transfer by ACHE is greater. Furthermore, the design inlet temperature of cooling water from cooling towers is always lower than the design ambient temperature. As a result, the mean temperature difference (MTD) for ACHEs is lower than that for WCHEs, causing an increase in the amount of heat transfer area required for ACHEs. 2. In cold winter environments, it may be necessary to take special precautions to avoid freezing of the tube side fluid and the formation of ice on the outside surface of the tube. 3. Large-diameter fan blades rotating at high speeds are responsible for moving large volumes of cooling air. Consequently, noise is generated as a result of air turbulence and high fan tip speeds.

5.4.3 Air Cooler Design Considerations In the design of an air-cooled heat exchanger, the same heat transfer relationships apply as they do for shell-and-tube exchangers. When designing an air-cooled exchanger, there are a number of factors that need to be taken into account. Aircooled heat exchangers are exposed to a variety of climatic conditions, which makes controlling the air cooler a critical issue. It is necessary to determine the actual ambient air temperature that will be used for the design. A number of factors determine the design of the air cooler, including tube diameter, tube length, fin height, number of tube rows, number of passes, face area, horsepower availability, and plot area. Given that there are many variables, there are normally many possible solutions, but the designer attempts to determine the most economical design based on these factors. It is important to note that the term “air-cooled exchanger” is a very broad term and that the product can vary significantly in terms of its design, applications, and cost. In addition to the design pressure and temperature, as well as the

Equipment for Fluid Temperature Changes

195

fluid to be cooled, other factors such as hazardous fluids, fouling considerations, noise tolerability, and environmental factors must also be considered. In order to design an air-cooled heat exchanger, the following considerations must be taken into account. For air-cooled heat exchangers, the basic design procedure is similar to that for shell-and-tube exchangers. In order to determine the initial configuration of the unit, a rough estimate of the overall heat transfer coefficient has been calculated in conjunction with the design guidelines. The selection of the outlet air temperature is an important preliminary step in the design process. This parameter has a significant impact on the economics of exchangers. By increasing the outlet air temperature, less air is required, which reduces fan power and, consequently, operating costs. However, it also decreases the air-side heat transfer coefficient and the mean temperature difference in the exchanger, increasing the size of the unit and resulting in a higher capital expenditure. 5.4.3.1 Vertical or Horizontal Airflow It is usually driven by safety practices or obstructions. The most common orientation is vertical. It is important to consider obstructions that may limit either the air supply or discharge of the system. It is possible to significantly reduce the ground area of the unit if bundles are mounted vertically, but the performance of the unit is heavily dependent upon the prevailing wind speed. Due to the fact that air-cooled heat exchanger fans push air only in one direction, prevailing winds in opposing directions greatly reduce the performance of vertically mounted bundles, which is why vertically mounted bundles are typically found in small, packaged units. 5.4.3.2 Available Space At the thermal sizing stage of design, length, width, or height restrictions can be considered. As a result of fluid flow and pressure drop, the dimensions of length and width may be limited in their flexibility. The minimum height of the unit is determined by the total airflow. You should take into account obstructions that could restrict either the supply of air or the discharge of air. Bundle, header, and fan arrangements should be optimized for maximum heat transfer to minimize size and weight, thereby reducing capital and operating costs. 5.4.3.3 Induced or Forced Airflow It is most common to use forced airflow (fans that blow air into the tube bundle). A fan that induces air flow (draws air through the tube bundle) is commonly used when fans are cycled and ice may build up on the fan blades, causing the fan to be out of balance. The presence of obstructions that could restrict air supply or discharge should be considered. A  forced draft air-cooled exchanger uses fans below the tube bundles to move air across the surface of the tubes. As a result of this design, it is easier to maintain the fan blades and adjust them. Due to this, it requires less structural support, has a longer mechanical life, and is more cost effective. Induced draft implies an inlet fan placed on top of the cooling tower and the creation of low pressure.

196

Equipment and Components in the Oil and Gas Industry

5.4.3.4 Air Recirculation When air temperatures are at their hottest in the summer, air coolers are in high demand and therefore are sized much larger than normal to adequately cool the process fluid during the colder months. In winter, however, the air temperatures can be quite cold, and air coolers become too effective, so the risk of overcooling becomes increased. It is particularly problematic when water is present in the fluid but is also a problem when heavy oils or other fluids become too viscous (slow to flow). It is possible for saturated gases to form hydrate crystals. Recirculating the warmer air that is normally released into the atmosphere during summer conditions is the solution to over-cooling (during winter). Recirculation occurs when heated air exiting the air-cooled heat exchanger is drawn back into the inlet, resulting in an elevated temperature of the cooling air. However, recirculation during the summer could lead to overheating the air cooler. In order to avoid recirculation, the following design considerations should be taken into account: • Induced air flow—Direct high-velocity air upward from the exit of the tube bundle. • Cooler elevation—Ensure that sufficient free air area exists to provide adequate cooling air supply at low velocity. • Fan coverage—To ensure proper air distribution over the tube bundle, the number of fans, fan diameter, and distance from the tube bundle must be designed. In dead spots or pockets of low airflow, recirculated air can be drawn in. • Multiple banks—Where there is more than one air-cooled exchanger installed side by side, provisions must be made to ensure a consistent supply of fresh air. 5.4.3.5 Tubing Selection An important consideration when selecting tubing is the temperature of the fluid at the tube side as well as the possibility of corrosion at the external surface of the tube. Thermal effectiveness and cleaning considerations are considered when selecting tube diameters, unless otherwise specified. It is important to consider corrosion resistance, fouling considerations, tube joint type, thermal effectiveness, and economics when selecting tube-side materials for a heat exchanger. 5.4.3.6 Fin Side Design In accordance with the environment and design conditions, a variety of fin types can be considered. The following factors should be considered when selecting a fin type; • Design temperature • Corrosion properties of the air (coastal environment, industrial pollutants) • Temperature cycling frequency

Equipment for Fluid Temperature Changes

197

• Cleaning method and frequency • Type of fouling debris in air • Isolation of cooler (is it subject to frequent work in the vicinity) 5.4.3.7 Header Design The type and design of headers are generally determined by the design pressure and temperature, cleaning requirements, access to tubes for repair or plugging, leak concerns, code requirements, and economic considerations. A  few of the most commonly used header designs are as follows: • Pipe header: economical, no access to the tubes for cleaning. • Removable cover plate: gasketed joint that allows access to tubes and inside of header for cleaning or tube plugging. • Welded box: typically used for high-pressure applications in which it is not necessary to have access to the tubes. • Plug type: similar to a welded box, except that individual plugs allow access to each tube for cleaning or plugging. 5.4.3.8 Area Flow Distribution It is recommended that the fan area of the tube bundle be at least 40% of the bundle face area in order to obtain an even distribution of air flow across the bundle. In addition, for two-fan bays, the ratio of tube length to bundle width should be in the range of 3–3.5. It is also desirable to have a minimum of four tube rows. 5.4.3.9 Sound Level Limitations Often, it is necessary to control the sound level emitted by the fan and drive of an air-cooled heat exchanger in order to meet industrial safety standards. Noise is affected by the number of fans, the diameter of the fans, the speed of the fans, and the profile of the blades and pitch of the drives. When air-cooled heat exchangers are required to meet strict sound level requirements, their costs can be significantly increased. The designer must balance adding surface area to the tube bundle, reducing the speed of the fan, and selecting fans with low noise profiles in order to minimize the cost impact. In the design and operation of air-cooled heat exchangers, environmental noise is becoming an increasingly significant factor. Consequently, the design of a noise-efficient air-cooled heat exchanger is becoming increasingly important. There are several sources of noise generated by air coolers. The largest contributor to the overall noise levels in an air cooler is the fan. It is important to consider a number of factors in the design and selection of the proper fan for low noise applications that affect the noise level; however, the fan speed has the greatest effect on the overall sound level. Electric motors generally contribute less to overall noise than fans or drives; however, there are steps that can be taken to minimize their influence. It is possible for structural vibration and the effects of rotating equipment to have an effect on the structure of the air

198

Equipment and Components in the Oil and Gas Industry

cooler, including vibration in the panels. It is possible to produce a low-frequency noise from this.

5.4.4 Air Cooler Components Air-cooled heat exchangers consist of the following components, illustrated in Figure 5.27: • • • • •

One or more coils (tube bundles) with heat transfer surfaces Air moving device, normally a fan A driver and speed reduction device Plenum between the coil and the fan to direct air across the surface area Supporting structure

FIGURE 5.27  Air-cooled heat exchangers and their components.

Equipment for Fluid Temperature Changes

199

• Optional header and fan maintenance walkways with ladders to grade. • Guards for rotating equipment and protection of the coil area • Optional louvers to control outlet temperatures 5.4.4.1 Tube Bundles An assembly of tubes, headers, side frames, and tube supports is referred to as a tube bundle. The tubes are normally round and can be produced in almost any metal suitable for the process. As a general rule, the longer the tubes and the more rows, the lower the cost per square foot of the surface area. To allow for thermal expansion of the tubes, the bundles must have at least one floating header. Thermal expansion could cause problems with the tube-to-tube sheet joint, since the thermal expansion would attempt to push the tube into the header box, loosening the expanded tube-to-tube sheet joint. There are generally holes in the tube sheet of the header box that are used to expand the tubes. An inside tube sheet hole that is grooved or an inside tube sheet hole that is smooth can be used to expand the tube sheet. Because grooved tube sheet holes provide additional strength in high-pressure and high-temperature applications, they are preferred in these situations. As soon as the tubes have been installed in the bundle, they must be supported so that the fins do not rub against one another. They must also be “tidied,” allowing channels of airflow to be created in the tubes. Depending on the manufacturer, a variety of tube support methods are employed. At atmospheric pressure, air passes over the tube surface, which has extended surfaces in the form of fins in order to compensate for a low rate of heat transfer and a low enough velocity to maintain a reasonable fan power consumption. There are two types of fins: helical or plate type, and aluminum is commonly used due to its good thermal conductivity and ease of fabrication. The use of steel fins is common in applications involving very high temperatures. A typical tube bundle configuration is illustrated in Figure 5.28. Tube bundles are rectangular in shape and are usually 6 to 12 feet wide. Due to the fact that tube bundles are manufactured in factories and shipped to the plant site, the maximum bundle width is determined by the requirements for transportation. The tubes are either welded together or rolled into long rectangular tube sheets that are welded to box-type headers. There are screwed plugs located in both front and rear headers that align with the tube holes. During maintenance or cleaning, the plugs can be removed to allow access to the tubes. 5.4.4.2 Fins The tube, through which the process fluid flows, is a common feature of all aircooled heat exchangers. It is necessary to add external fins to the outside of the tube to compensate for the poor heat transfer properties of air, which flows across the outside of the tube, and to reduce the overall dimensions of the heat exchanger. There are many types of finned tubes available for use in air-cooled exchangers. There is a wide range of geometry, materials, and construction methods with regard to finned tubes, which has an impact on both their thermal performance and their pressure drop on the air side. A fin’s shape and material choice may be

200

Equipment and Components in the Oil and Gas Industry

FIGURE 5.28  Typical tube bundle configuration.

influenced by the operating environment. It is very common to use aluminum as a fin material, although copper, steel, and stainless-steel fins are also available. The shape of the fin can be edge-type, L-foot type, or double L-foot type. Figure 5.29 illustrates the various shapes of fins. L-footed tension-wound aluminum fins are the most commonly used fin type in air-cooled heat exchangers. The L-foot fin (see Figure 5.29a) is produced by wrapping an aluminum strip, which is footed at the base, around the tube. At all times, tension must be maintained on the fin. It is important to note that the fins’ ends are stapled to prevent the aluminum fin from unraveling and losing contact with the tube. As the heat is transferred from the tube wall through the fin to the surrounding ambient air through this contact, it is crucial to the operation of the air cooler. L-footed tension wound fins are usually used in applications where the tube wall temperature does not exceed 350° and air-side corrosion is not severe. During higher tube wall temperatures, due to the difference in material between the tube and the fin, the fin will lose contact with the tube, resulting in a loss of cooling efficiency of the air cooler. The fin is also susceptible to air-side corrosion, which creates a film between the tube and fin. This process can be slowed by applying a coating to the fins or by using a special material. For high-temperature applications, the fin is attached to the tube wall using an embedded process, as illustrated in Figure 5.29b. This process involves cutting a groove

Equipment for Fluid Temperature Changes

201

FIGURE 5.29  Different types of fin arrangements in air-cooled heat exchangers. (a) L-foot, (b) Embedded (c) L-footed with slit cuts into the fin, (d) Extruded fin tubes.

into the tube material, inserting the fin strip, and then “plowing” back against the fin to seal it in place. Embedded processes do not have a foot on the fin, leaving the tube completely exposed to airside corrosion. To avoid overpressurizing the tube, a thicker wall is required due to the groove cut into the tube. For temperatures greater than 350°F and less than 750°F, embedded fins are generally used. Extruded fin tubes (see Figure 5.29d) provide the best protection from atmospheric corrosion in applications where atmospheric corrosion is critical. Extruded fins are produced by inserting the tube into an aluminum sleeve and then extruding the fins from the aluminum sleeve. Due to the total covering of the tube by the aluminum sleeve, the tube wall is protected from outside corrosion, and the bond between the fin and the tube remains intact. Extruded fin tubes are suitable for temperatures up to 650°F. The production of this fin tube is the most expensive. The double L-foot fin is similar to the L-tension fin in that it is produced in a similar manner. In this process, a foot is formed on both sides of the upright portion of the fin, resulting in an overlap of the fins. In this way, the tube is protected from atmospheric corrosion to a greater extent. Fins of this type are also known as overlapped fins. In Figure 5.29c, L-footed fins with slits cut into the fin are presented. By cutting a slit into the fin, more turbulence can be created, as the air boundary layer is interrupted. In turn, this increases the airside heat transfer coefficient along with a modest increase in the airside pressure drop and the fan horsepower.

202

Equipment and Components in the Oil and Gas Industry

5.4.4.3 Headers In an air cooler, the headers are the boxes at the end of the tubes that are responsible for distributing fluid from the piping to the tubes. 5.4.4.4 Bays A bay in an air-cooled heat exchanger consists of one or more tube bundles, serviced by two or more fans, along with the structure, plenum, and other related equipment. Generally, the longer the tubes and the greater the number of rows, the lower the cost per square foot of the heat transfer surface. There may be a combination of one or more bundles of the same or different services in one bay with one set of fans. The fan bays may be preassembled and shipped to the plant site if they are small enough to meet transportation requirements. Otherwise, they must be assembled on site, which increases the cost of the heat exchanger. Air-cooled heat exchangers comprise one or more fan bays, with multiple bays operating simultaneously. Figure 5.30 illustrates different combinations of tube bundles and fans in bays. 5.4.4.5 Fans For uniform heat transfer, it is essential that air be distributed evenly throughout the tube bundle. By ensuring adequate fan coverage across the bundle and minimizing static pressure loss, this can be accomplished. Axial flow propeller-type fans are commonly employed in air-cooled heat exchangers; these fans either force the air across the bundles, as in forced draft configurations, or pull it across, as in induced draft configurations. The tube bundles are usually equipped with one or two fans to provide redundancy in the event of mechanical failure. The average efficiency of a fan is approximately 65%. Depending on the size of the fan, it can range from 3 to 60 feet in diameter and have 2 to 20 blades. A blade can be made from wood, steel, aluminum, or fiberglass-reinforced plastic and can be solid or hollow. The most popular blades are hollow plastic blades. There are two types of blades: those with straight sides and those with contoured sides.

FIGURE 5.30  Combinations of tube bundles and fans in bays.

Equipment for Fluid Temperature Changes

203

Heat exchangers are equipped with fans that are sized according to the dimensions of the tube bundle and the performance requirements. In general, the diameter of the fan should be approximately equal to the width of the bundle, although smaller diameters are also possible. A single fan is used for bundles that are square or nearly square. There may be a need to use several fans operating in parallel for long rectangular bundles. There are fans that use axial flow design, which can move relatively large volumes of air at low pressure. Fan blades are set within orifice rings that provide close radial clearance between the blade tips and the ring in order to minimize air recirculation and improve fan efficiency. In an air-cooled heat exchanger, the fans are arranged in bays, which are self-contained sections. There are several basic components that make up a bay, including one or more tube bundles and the fans and drive assemblies that supply air to the bundles, as well as the framework and support structures that surround the bundles. The tube bundles in the bay are usually placed side by side, except in unusual circumstances. Most bays are designed to accommodate two to three fans. 5.4.4.6 Plenums It is possible for the air passing through the fan to have a velocity that is three to four times greater than that passing across the tube bundle. It is also essential that the air, coming from the circular shape of the fan, be distributed over the square or rectangular shape of the bundle. The air plenum chamber is intended to achieve this change in velocity and shape, so that the distribution of air is uniform across the bundle. The enclosure is designed to facilitate the smooth flow of air between the fan and the bundle. A heat exchanger that uses air-cooled technology is controlled by two factors: the size and configuration of the tube bundles and the ability to move air across the surface area that each bundle provides. Therefore, manufacturers of air coolers should consider not only the selection of the appropriate fan but also the design of plenums in order to force the air across the surface area of the cooler. There are two types of plenums: box plenums and slope plenums. Air-cooled heat exchangers are classified as forced draft when the tube section is located on the discharge side of the fan or induced draft when the tube section is located on the suction side of the fan. Forced draft units are more common. Slope-sided plenums are most commonly used with induced draft because they present structural problems when a machinery mount is suspended from a slope-sided forced draft plenum. 5.4.4.7 Motors It is possible for fans to be driven by electric motors, steam turbines, gas engines, or hydraulic motors. Electric motors are the most popular choice. It is sometimes necessary to use hydraulic motors in the absence of electric power from an electric utility. There are also hydraulic motors that provide variable speed control, but they are not very efficient.

204

Equipment and Components in the Oil and Gas Industry

5.4.4.8 Structural Assemblies Depending on the particular plant site requirements of the user, the structural assembly of the air-cooled heat exchanger will vary. Mechanical loads should be considered for the heat exchanger structure, due to its own weight, of course, but other loadings must also be taken into account, such as wind loads, impact loads, nozzle loading, and seismic forces. It may be necessary to design the heat exchanger differently if there is equipment underneath. There may be a need for fencing or fan guards due to safety concerns. It is possible that environmental factors may indicate the need for vents, hail screens, or other protective devices. Furthermore, the location of the heat exchangers may require ladders, platforms, railings, safety cages, and other miscellaneous items, which will be required by the user.

5.4.5 Air Cooler Types There are several configurations available for air-cooled heat exchangers, which are typically determined by the power available, the installation, and the preferences of the customer. Horizontal coils with horizontal fans and vertical airflow are the most common types of air coolers (see Figure 5.31). Typically, this type of fan is driven by an electric motor connected to the fan. An engine with a right-angle gear drive arrangement is also capable of driving this model, as well as hydraulic motors, air motors, and air compressors. These models are usually used in plants or refineries where electric power is available and where the air cooler is located away from other equipment in order to allow adequate airflow around it. The model is available in both forced draft and induced draft configurations. Both models have advantages and disadvantages depending on the application and the installation site. Air is forced across the tube surface by fans set below the tube bundles in a forced draft air-cooled exchanger. As a result of this design, maintenance and blade adjustment can be performed more easily. Consequently, it requires less structural support, has a longer mechanical life, and can be more cost effective. Induced draft implies an inlet fan placed on top of the cooler. Among the advantages of forced draft air coolers are lower horsepower requirements caused by lower inlet temperatures, greater ease of access to fans and bearings, and more convenient replacement of bundles. Forced draft air coolers have the disadvantages of less uniform air distribution over the bundle, increased air recirculation probability, and exposure of coils to the sun and rain. Air coolers with induced drafts have the advantages of better air distribution across the bundle, reduced recirculation of air, and increased capacity when the fans are not operating. Furthermore, there are some disadvantages associated with induced draft air coolers, such as a higher horsepower requirement, since the fan is located in the outlet air stream. The internal components of the air cooler are subject to higher temperatures, and the fans are less accessible for maintenance.

Equipment for Fluid Temperature Changes

205

FIGURE 5.31  Air coolers with horizontal coils and fans and a vertical flow by Amercool manufacturing.

The vertical air cooler is another common configuration of an air cooler (see Figure 5.32). Bundles are typically stacked vertically, with a vertical fan, and the intake air is drawn from a horizontal direction. The air flow may be turned vertically or horizontally or angled towards the fan on different models. A model such as this was designed for applications in which the fan was driven by an engine and the cooler was mounted on a skid with other equipment. It is a typical application for skid-mounted gas compressors and generators powered by engines. In addition to serving as a radiator for the engine, the cooler is often used to cool the compressor’s gas or air as well. As with air-cooled heat exchangers, this type is available in both forced and induced draft configurations. There are some applications where natural draft coolers can be used in the absence of power. Based on this design, air cooler bundles generate their own air

206

Equipment and Components in the Oil and Gas Industry

FIGURE 5.32  Air coolers with vertical coils and fans and a horizontal flow by Amercool manufacturing.

flow, either as a result of natural crosswinds or as a result of the air flow created when hot air rises from the bundle and is replaced by cooler air. In natural draft coolers, coils may be arranged horizontally or vertically or stacked, providing additional means of generating air flow across the coils.

QUESTIONS AND ANSWERS

1. Identify the correct statement regarding heat transfer in heat exchangers. A. In heat exchangers, radiation is the principal method of heat transfer. B. Thermal energy is transferred from the hot fluid surface to the adjacent wall surface by conduction. C. It is through conduction that heat is transferred through the wall surface. D. Heat is transferred from the wall to the cold fluid by conduction.

Answer) It is incorrect to choose option A since convection and conduction are the primary methods of transferring heat in heat exchangers. Likewise, option B is incorrect since thermal energy is transferred by convection between the fluid and the wall surface. For the same reason, option D is also incorrect. The correct answer is option C.

Equipment for Fluid Temperature Changes

207

2. What standard applies to shell-and-tube heat exchangers? A. DIN B. ASME C. TEMA D. It is correct to choose any of the three options

Answer) Option D is the correct answer. 3. Which type of heat exchanger is almost impossible to clean? A. Shell-and-tube heat exchanger B. Spiral tube heat exchanger C. Plate heat exchanger D. Double-pipe heat exchanger Answer) Option B is the correct answer. 4. What is the correct statement regarding plate heat exchangers? A. A plate heat exchanger is a type of heat exchanger that transfers heat between fluids by using spiral plates. B. In a plate heat exchanger, hot and cold fluids are mixed together. C. In the design and manufacture of plate heat exchangers, gaskets are essential components. D. A plate type heat exchanger has a low heat transfer rate. Answer) In a plate type heat exchanger, the plates are not spiral. Therefore, option A is incorrect. As well as option A, option B is incorrect since plate heat exchangers do not mix hot and cold fluids. The correct answer is option C. Option D is incorrect due to the large contact area between the cold and hot media, which leads to a high heat transfer rate in this type of heat exchanger.



5. Which statements are correct regarding shell-and-tube heat exchangers? A. Shell-and-tube heat exchangers have the advantage of not requiring any overpressure protection system on their shells. B. Shell-and-tube heat exchangers with a single pass provide a better heat transfer than those with multiple passes. C. Heat exchangers with shells and tubes can handle flammable and toxic fluids at high operating temperatures. D. U-tube heat exchangers are not shell-and-tube heat exchangers. E. Tube pitch refers to the distance between the centers of each tube hole. It is typically calculated as 1.25 times the outside diameter of the tubes. F. Heat exchangers use baffles only to support the tubes.

Answer). Option A is incorrect since a pressure relief disk or rupture disk can be installed on the shell side to prevent an overpressure scenario in the shell in the event of a tube rupture. Also, option B is incorrect since multipass heat exchangers provide greater heat transfer than single-pass exchangers. The statement in option C is correct. Due to the fact that U-tube heat exchangers are shell-and-tube heat exchangers, option D is incorrect. Option

208

Equipment and Components in the Oil and Gas Industry

E is correct. Option F is not entirely correct, as baffles are used to provide high fluid turbulence on the shell side, which facilitates heat transfer. 6. In a boiler, the — of the flue gases transfers to the water through —. The fuel is burnt in the —, which produces —. These flue gases pass over the water contained in the shell or tube according to the type of boiler. The heat of the flue gases transfers to the water and converts it into steam. This is the basic principle of a boiler. A. kinetic energy, convection, furnace, steam B. heat energy, convection, furnace, flue gases C. kinetic energy, conduction, tube, steam D. heat energy, conduction, tube, flue gases

Answer). Option B is the correct answer.

7. What is the correct statement regarding the mounting of a boiler? A. A safety valve is located between the steam space and the steam supply line in the boiler. It is primarily responsible for regulating the flow of steam from the boiler to the steam line. B. Boiler economizers are mounting devices that heat water prior to entering a boiler drum. The flue gases provide heat for the economizer, which is used to preheat the water. C. A pressure gauge indicates the pressure of steam in the boiler. Generally, it is located on the front top of the boiler. There are two types of pressure gauges: (i) bourdon tube pressure gauges and (ii) diaphragm pressure gauges. D. By regulating the water level in the boiler, the safety valve protects it from damage resulting from overheating of the boiler tubes.

Answer). Due to the fact that the provided definition pertains to a steam stop valve rather than a safety valve, option A is incorrect. Due to the fact that the economizer is not a mounting device, Option B is incorrect. Option C is the correct answer. The given definition refers to a fusible plug, so option D is incorrect.

8. In order to combat the poor heat transfer properties of the air flowing across the outside of the tube and to reduce the overall dimensions of the heat exchanger, a _______ must be added to the outside of the tube. A. Bundle B. Motor C. Fan D. Fin

Answer) Option D is the correct answer. 9. Among the following choices, which does not address the advantage of forced draft air-cooled heat exchangers? A. Better maintenance B. Lower temperature of air entering the cooler

Equipment for Fluid Temperature Changes

209



C. Reduction in the probability of air recirculation D. Due to the lower air temperature, there is a reduction in horsepower requirements



Answer) Recirculation occurs when heated air exiting a heat exchanger is drawn back into the inlet, resulting in an increase in cooling air temperature. Since forced draft air-cooled heat exchangers suffer from this problem, option C is the correct answer.

10. In an air cooler, what type of fin arrangement is the most expensive? A. Extruded B. Embedded C. L-type D. Double L-type

Answer) Option B is the correct answer.

FURTHER READING

1. Alfa Laval. (2023). How do spiral heat exchangers work. [online] available at: www. alfalaval.com/products/heat-transfer/plate-heat-exchangers/welded-spiral-heatexchangers/how-it-works/ [access date: 9th June, 2023] 2. Amercool Manufacturing Inc. (2011). Basics of air-cooled heat exchangers. Tulsa, OK: Amercool Manufacturing Inc. 3. EnggCyclopedia. (2023). Regenerative heat exchangers. [online] available at: https:// enggcyclopedia.com/2023/04/regenerative-heat-exchangers/ [access date: 17th June, 2023] 4. EPCM. (2023). Design of shell and tube heat exchanger. [online] available at: https:// epcmholdings.com/design-of-shell-and-tube-heat-exchanger/ [access date: 9th June, 2023] 5. Ghorbani, N., Taherian, H., Gorji, M., & Mirgolbabaei, H. (2010). Experimental study of mixed convection heat transfer in vertical helically coiled tube heat exchangers. Experimental Thermal and Fluid Science, 34(7), 900–905. 6. Kashani, A. H. A., Maddahi, A., & Hajabdollahi, H. (2013). Thermal-economic optimization of an air-cooled heat exchanger unit. Applied Thermal Engineering, 54(1), 43–55. 7. Khayal, O. M. E. S. (2018). Fundamentals of heat exchangers. International Journal of Research in Computer Applications and Robotics, 6, 1–11. 8. Industrial Quick Search (IQS). (2023). Heat exchangers. [online] available at: www. iqsdirectory.com/articles/heat-exchanger.html [access date: 7th June, 2023] 9. Industrial Quick Search (IQS). (2023). Shell and tube heat exchangers. [online] available at: www.iqsdirectory.com/articles/heat-exchanger/shell-and-tube-hea texchangers.html#:~:text=The%20shell%20of%20a%20shell,outer%20edge%20 and%20the%20shell [access date: 9th June, 2023] 10. Kraus, A. D., Aziz, A., Welty, J., & Sekulic, D. P. (2001). Extended surface heat transfer. Applied Mechanics Reviews, 54(5), B92. 11. Kundakcı, N. (2019). An integrated method using MACBETH and EDAS methods for evaluating steam boiler alternatives. Journal of Multi-Criteria Decision Analysis, 26(1–2), 27–34. 12. Manassaldi, J. I., Scenna, N. J., & Mussati, S. F. (2014). Optimization mathematical model for the detailed design of air cooled heat exchangers. Energy, 64, 734–746.

210

Equipment and Components in the Oil and Gas Industry

13. Meyer, C. J., & Kröger, D. G. (2001). Air-cooled heat exchanger inlet flow losses. Applied Thermal Engineering, 21(7), 771–786. 14. Pachaiyappan, R., & Dasa Prakash, J. (2015). Improving the boiler efficiency by optimizing the combustion air. In Applied mechanics and materials (Vol. 787, pp. 238–242). Trans Tech Publications Ltd. 15. Picon-Nunez, M., Polley, G. T., Torres-Reyes, E., & Gallegos-Munoz, A. (1999). Surface selection and design of plate–fin heat exchangers. Applied Thermal Engineering, 19(9), 917–931. 16. Razelos, P. (2003). A critical review of extended surface heat transfer. Heat Transfer Engineering, 24(6), 11–28. 17. Rohsenow, W. M., Hartnett, J. P., & Cho, Y. I. (1998). Handbook of heat transfer. New York: McGraw-Hill Book Company. ISBN: 9780070535558. DOI: 10.1016/0017– 9310(75)90148–9 18. SAVREE. (2023). Shell and tube heat exchanger. [online] available at: https://savree. com/en/encyclopedia/shell-and-tube-type-heat-exchanger [access date: 9th June, 2023] 19. Shah, R. K., & Sekulic, D. P. (2003). Fundamentals of heat exchanger design. John Wiley & Sons. ISBN: 9780471321712 20. Shrivastava, D., & Ameel, T. A. (2004). Three-fluid heat exchangers with three thermal communications. Part A: General mathematical model. International Journal of Heat and Mass Transfer, 47(17–18), 3855–3865. 21. Shrivastava, D., & Ameel, T. A. (2004). Three-fluid heat exchangers with three thermal communications. Part B: Effectiveness evaluation. International Journal of Heat and Mass Transfer, 47(17–18), 3867–3875. 22. STI Group. (2023). Industrial heat exchangers: What they are, how they work, and why they are needed. [online] available at: https://setxind.com/industrial-heat-exchangers-what-they-are-how-they-work-and-why-they-are-needed/ [access date: 7th June, 2023] 23. Teir, S. (2002). Modern boiler types and applications. In Steam boiler technology book (pp. 1–14). Helsinki: Helsinki University of Technology, Department of Mechanical Engineering, Energy, Engineering and Environmental Protection. 24. Yilmaz, T., & Büyükalaca, O. (2003). Design of regenerative heat exchangers. Heat Transfer Engineering, 24(4), 32–38. 25. Zohuri, B., & Zohuri, B. (2017). Heat exchanger types and classifications. In Compact heat exchangers: Selection, application, design and evaluation (pp. 19–56). Berlin, Heidelberg: Springer.

6

Prime Movers

6.1 INTRODUCTION Prime movers are used to drive pumping units, compressors, chillers, and other types of equipment related to the energy industry. Natural gas turbines and reciprocating engines are the most common prime movers in the oil and gas industry. It is also possible to use steam turbines. Motors powered by electricity are not considered prime movers and will be discussed in the second volume of the book. The characteristics of each type of prime mover determine its suitability for a particular application, taking into account the site conditions and the availability of fuel energy. When it comes to prime movers, gas engines are most commonly used to generate power.

6.2 GAS TURBINES 6.2.1 Introduction Since 1939, gas turbines have been used to generate electricity. One of the most widely used technologies for generating power today is the gas turbine. The gas turbine is a type of internal combustion (IC) engine that generates power by burning an air–fuel mixture to produce hot gases that spin a turbine. Gas turbines are named after the hot gas produced during the combustion of fuel rather than the fuel itself. The combustion process occurs continuously in gas turbines, as opposed to intermittently in reciprocating engines. Gas turbines combine the simplicity of steam turbines with the advantages associated with internal combustion as achieved by diesel engines. The gas turbine is still classified as an external combustion engine, since no fuel is actually burned in the turbine itself.

6.2.2 Working Principles Most commercial jets are powered by turbofan engines, and turbofans are one example of a general class of engines called gas turbine engines. The following example will illustrate the basic operation of a gas turbine: Consider a rocket that burns fuel, producing high-pressure exhaust gases. As a result of the law of energy conservation, in high-pressure exhaust gases, the chemical energy of the fuel is converted into mechanical energy. When a rocket is fired, the thrust from the exhaust gas attempts to propel the rocket forward. In a gas turbine, the chemical energy of the fuel is converted into mechanical energy or kinetic energy by means of shaft power. In other words, it is a machine that delivers power or thrust by mechanical means. In order to accomplish this task, a gaseous working fluid

DOI: 10.1201/9781003467151-6

211

212

Equipment and Components in the Oil and Gas Industry

is used. Industrial devices can utilize the mechanical power generated by the gas turbine. Generally, gas turbines consist of three main components: a compressor, a combustion chamber (or combustor), and a turbine (see Figures  6.1 and 6.2). There are two types of compressors: axial flow and centrifugal flow. The use of axial flow compressors in power generation is more prevalent due to their higher flow rates and efficiency. During the operation of an axial flow compressor, air is drawn parallel to the axis of rotation through multiple stages of rotating and stationary blades (or stators), which are incrementally compressed as they pass through each stage of the compressor. Air is accelerated by the rotating blades and diffused by the stators, which increases pressure and reduces volume. Despite the fact that no heat is added, the compression of the air also results in a rise in temperature. Gas turbines are internal combustion engines. From all points of view, it can be considered a self-sufficient system: in fact, it takes and compresses atmospheric air in its own compressor, increases the energy power of the air in its combustion chamber, and converts this into useful mechanical energy during the expansion process that takes place in the turbine section. Through a coupling, the mechanical energy is transmitted to a driven machine, which produces power for the industrial process to which the gas turbine is applied. Through nozzles, compressed air is mixed with fuel. It is possible to pre-mix the fuel with compressed air or to introduce the compressed air directly into the combustion chamber. As a result of the combustion of the fuel–air mixture under constant pressure, the hot combustion products (gases) are directed through the turbine, where they expand rapidly and impart rotation to the shaft. Moreover, the turbine consists of several stages, each with a row of stationary blades (or nozzles) for the purpose of directing the expanding gases, followed by a row of moving blades. Rotation of the shaft causes the compressor to draw in and compress more air in order to maintain continuous combustion. Electricity is produced by using the remaining shaft power to drive a generator. In fact, a gas turbine, also known as a combustion turbine, is a rotary engine that extracts energy from combustion gases. There is an upstream compressor coupled to a downstream turbine and an intermediate combustion chamber. During combustion, air is mixed with fuel and ignited to add energy to the gas stream. As a result of combustion, the temperature, velocity, and volume of the gas flow increase. By directing this flow through nozzles over the turbine’s blades, the turbine spins and the compressor is powered. As a result of shaft power, compressed air, and thrust, energy can be extracted and used to power aircraft, compressors, or generators. Gas turbines can be used to drive mechanical devices (compressors or pumps) as well as generators. During a mechanical or compressor drive, the power from the gas turbine will drive the shaft that connects to the compressor. As a result of the shaft rotation, the impeller of the compressor will be directly rotated. In a generator drive, the power shaft will be connected to the generator, in contrast to a compressor drive. By rotating the shaft, the generator will produce electricity for other users. The compressor consumes approximately 55 to 65% of the power produced by the turbine. Multiple compressors and turbine stages can be used in gas turbines to optimize the transfer of kinetic energy from combustion gases to shaft

Prime Movers

213

FIGURE 6.1  Gas turbines.

FIGURE 6.2  Gas turbines.

rotation. As a result of the power required to drive the compressor, the energy conversion efficiency of a simple cycle gas turbine power plant is typically about 30%, with even the most efficient designs being limited to 40%. There is a significant amount of heat remaining in the exhaust gas, which is around 600°C when

214

Equipment and Components in the Oil and Gas Industry

it leaves the turbine. It is possible to achieve 55 to 60% efficiency for gas turbine power plants if waste heat is recovered in a combined cycle configuration and used to produce more useful work. Depending on the application, gas turbines have different shaft arrangements. In this regard, a gas turbine can be categorized as a single shaft engine, a twoshaft engine, or a multi-shaft engine. A  single shaft gas turbine consists of a turbine, compressor, and driven load located on a single shaft. Combustion heat drives the turbine, the turbine in turn drives the compressor, and the remaining energy is used to run the load (generator, compressor, pumps, etc.). The differences between a single-shaft gas turbine and a double-shaft gas turbine are due to the drive machine. Generally, gas turbines have a single shaft or a double shaft, except for jet turbines, which can have up to three shafts. There are several reasons for the difference in the number of shafts:

1. In order to drive a generator, a shaft must be rotated at a constant speed. Therefore, a single-shaft gas turbine is used that rotates at a constant speed. It is, however, necessary to use a double shaft when the rotation speed is not constant. Accordingly, the choice between a single-shaft or two-shaft power plant is largely determined by the characteristics of the driven load. As with an electric generator, a single-shaft unit is commonly specified when the load speed is constant; an engine designed specifically for electric power generation would make use of a single-shaft configuration. Alternatively, a two-shaft engine may be used. Two-shaft engines are advantageous when the load must be driven at varying speeds (e.g. compressors, pumps). 2. There are more than two shafts in multi-shaft engines. There are two sections of the compressor, the high pressure (HP) compressor and the low pressure (LP) compressor. In addition, there are two turbines, the HP turbine and the LP turbine. In order to drive the LP compressor, an LP turbine is mounted on a shaft that rotates concentrically within that shaft, which drives the HP turbine to drive the HP compressor. There is a difference in speed between these two shafts. Therefore, a two-shaft gas turbine has two turbines. HP turbines and LP turbines (or power turbines) are two types of turbines. In both HP and LP turbines, hot gas is released from the combustor. As the HP turbine is located on the same shaft as the compressor, it serves only as a power source for the compressor. The LP turbine runs on the second shaft, and it drives the load at a different speed than the compressor/HP turbine. It is possible for the power turbine and the compressor to run at different speeds in a two-shaft turbine. 3. This feature greatly improves the fuel economy and extends the life of a gas turbine. Gas turbines use a thermodynamic cycle known as the Brayton cycle. Figure 6.3 illustrates a gas turbine diagram. A  diagram such as this one can be helpful in understanding the thermodynamic cycle more clearly. There are three

Prime Movers

215

FIGURE 6.3  A gas turbine diagram (Brayton cycle).

thermodynamic processes that take place in an ideal gas turbine: an isentropic compression, an isobaric combustion (constant pressure), and an isentropic expansion. The Brayton cycle is composed of these components. Isentropic or adiabatic compression or expansion occurs when gas is compressed or expanded without heat energy flowing into or out of it. In an ideal gas, molecules do not interact. Pressure varies linearly with quantity and temperature and inversely with volume. Isobaric combustion refers to the process of burning fuel at a constant pressure. This type of combustion is commonly found in engines where the fuel is burned in a combustion chamber. The pressure in the chamber is maintained at a constant level during the combustion process. When gases are compressed (either by centrifugal or axial compressors) in a practical gas turbine, mechanical energy is irreversibly converted into heat. There is a slight loss in pressure as the gases pass through the combustion chamber, where heat is added and the specific volume of the gases increases. When the stator and rotor blades of the turbine expand, irreversible energy transformations occur once more.

6.2.3 Efficiency Improvements and Technology Advancements Pressure ratio and firing temperature are two important turbine performance parameters. By increasing the difference between the compressor discharge pressure and the inlet air pressure, the fuel-to-power efficiency of the engine can be optimized. It is dependent on the design of the compressor that determines the compression ratio. There are two types of gas turbines that can be used in power generation, industrial (heavy frame) or aeroderivative. Gas turbines for industrial applications are typically designed for stationary applications and have a lower pressure ratio—typically 18:1. An aeroderivative gas turbine is a lightweight, compact engine that is derived from aircraft jet engines and operates at

216

Equipment and Components in the Oil and Gas Industry

high compression ratios—up to 30:1. Generally speaking, the smaller the engine, the higher the rotation rate of the shaft(s) must be in order to maintain tip speed. A turbine’s blade-tip speed determines the maximum pressure ratio that can be achieved by a compressor. In addition to providing better fuel efficiency and lower emissions, they are also smaller and require a higher initial investment (capital). The temperature of the compressor inlet is more critical for aeroderivative gas turbines. Moreover, the temperature at which the turbine operates (firing temperature) has a significant impact on the efficiency of the turbine, with higher temperatures resulting in greater efficiency. In spite of this, the temperature at which the turbine blade metal alloy can tolerate thermal conditions limits the turbine inlet temperature. Typical gas temperatures at the turbine inlet range from 1200°C to 1400°C, but some manufacturers have increased gas temperatures as high as 1600°C by incorporating blade coatings and cooling systems to prevent thermal damage to the metallurgical components. The technology of gas turbines has steadily advanced since the beginning and continues to develop. Development is actively taking place to produce both smaller gas turbines and engines that are more powerful and efficient. A  key component of these advancements is computer-based design (specifically computational fluid dynamics [CFD] and finite-element analysis) as well as the development of advanced materials. The structure must be protected from ever-higher temperatures by thermal barrier coatings or base materials with superior high temperature strength (e.g. single crystal superalloys with yield strength anomalies). As a result of these advancements, we have been able to achieve higher compression ratios and turbine inlet temperatures, more efficient combustion, and better cooling of engine components. By improving the understanding of the complex viscous flow and heat transfer phenomena involved in gas turbine engines, computational fluid dynamics has contributed to substantial improvements in their performance and efficiency. The CFD method is therefore one of the most important computational tools used in the design and development of gas turbine engines. By incorporating inter-cooling, regeneration, and reheating, the simple-cycle efficiencies of early gas turbines were practically doubled. Improvements such as these, however, come at the cost of increased initial and operating costs, which can only be justified by fuel cost increases. The relatively low fuel prices, the general desire in the industry to minimize installation costs, and the tremendous increase in simple-cycle efficiency to about 40% left little desire to opt for these modifications.

6.2.4 Advantages and Disadvantages Advantages of gas turbines are listed as follows: • Compared to reciprocating engines, it has a high power-to-weight ratio. • A smaller engine than most reciprocating engines of the same power rating. • It moves in one direction only, with far less vibration than a reciprocating engine.

Prime Movers

217

• A reciprocating engine has fewer moving parts than a piston engine. • The ability to sustain a high power output for a sustained period of time, especially in applications requiring high power output • Almost all of the waste heat is dissipated in the exhaust. As a result, the exhaust stream has a high temperature, which is suitable for boiling water in a combined cycle or for cogeneration. • Low operating pressures. • High operation speeds. • Low lubricating oil cost and consumption. • Can run on a wide variety of fuels. • Very low toxic emissions of undesirable compounds due to excess air, complete combustion, and no “quench” of the flame on cold surfaces. Disadvantages of gas turbines are listed as follows: • • • •

Cost is very high. Less efficient than reciprocating engines at slow speed. A longer startup time than reciprocating engines. Compared to reciprocating engines, they are less responsive to changes in power demand. • It can be difficult to suppress the noise.

6.2.5 Gas Turbine Main Sections As described in the following, gas turbines are composed of three main sections: 1. Compressor: A  centrifugal compressor consists essentially of a stationary casing that contains a rotating impeller that imparts a high velocity to the air and a number of fixed diverging passages that decelerate the air, resulting in an increase in static pressure. By means of the vanes on the impeller disc, air is sucked into the impeller eye and whirled around at high speeds. The centrifugal force acting on the air causes it to move towards the outer edge of the impeller. When air strikes the diffuser casing, its high velocity is reduced, resulting in an increase in pressure.   Axial-flow compressors are mostly used in this system. An axial-flow compressor produces high air flows, resulting in the high value of useful power with reduced dimensions. A compressor is composed of a series of rotating blades that increase air speed in terms of kinetic energy into higher pressure. Generally, the number of compression stages is related to the structure of the gas turbine and, most importantly, to the desired pressure ratio. Furthermore, the compressor is used to provide a source of air for cooling the walls of nozzles, buckets, and turbine disks, which are connected via channels inside the gas turbine, as well as external connections.

218

Equipment and Components in the Oil and Gas Industry

2. Combustion section: Without a combustion chamber, a gas turbine directly coupled to a compressor would not generate enough power to drive the compressor, overcome friction, and have sufficient power left over to drive other equipment. Fuel is burned in the combustion chamber to provide the additional energy required.   The air leaving the compressor must first be slowed down and then split into two streams. The smaller stream is fed centrally into a region where atomized fuel is injected and burned with a flame that is held in place by turbulence. The larger, cooler stream is then fed into the combustion chamber through holes along a “combustion liner” (a kind of shell) in order to lower the overall temperature for turbine operation.   The air enters each combustion chamber in the opposite direction from the hot inner gas path. One or more spark igniters ignite the combustion process at the beginning. Once ignited, combustion continues unassisted as long as fuel and combustion air supply conditions are maintained. The hot gas path from the combustion system to the turbine inlet passes through transition pieces that transform the gas flows from the single combustion chambers into a continuous annular stream matching the first-stage nozzle ring inlet. 3. Turbine section: The turbine section comprises a number of stages, each of which consists of a stator stage and a rotor stage. In the stator stage, high-temperature and high-pressure gas is delivered by the transition piece, which accelerates the gas and directs it to a rotor stage composed of buckets mounted on a disk attached to the power shaft. By converting kinetic energy to shaft driving energy, the rotor stage completes the energy conversion process, generating the power necessary to drive the compressor or alternator (generator).

6.2.6 Gas Turbine Performance A gas turbine’s performance is affected by four factors: external factors, internal factors, compressors, and surges. 6.2.6.1 Influence of External Factors Because gas turbines use atmospheric air, their performance is greatly influenced by all factors that influence the flow rate of air delivered to the compressor. The following are some external factors that influence gas turbine performance. 6.2.6.1.1 Temperature When the compressor inlet temperature increases, the specific compression work increases, while the weight flow rate of the air decreases (because of a decrease in specific weight). As a result, the turbine efficiency and useful work (power) are reduced.

Prime Movers

219

6.2.6.1.2 Pressure As the atmospheric pressure decreases, the weight flow rate of air also decreases (due to a reduction in its specific weight). This results in a decrease in turbine efficiency and useful work (power). 6.2.6.1.3 Relative Humidity The relative humidity of compressor inlet air influences its specific weight. The density of humid air is lower than that of dry air. As a result, if the relative humidity increases, the power output will decrease. 6.2.6.2 Influence of Internal Factors There are factors that affect the performance of a gas turbine in addition to the three external factors described in the preceding section. Due to their relationship with the gas turbine’s auxiliary systems, these factors may be referred to as internal factors. The following are among them. 6.2.6.1.1 Fuel Type There are two types of fuels for gas turbines: liquid and gaseous. Among the most common liquid fuels are kerosene, diesel, crude oil, and heavy oil; among the most common gaseous fuels are natural gas, liquid natural gas, hydrogen, refinery gas, and biomass gasification (synthesis) gas. In order to achieve the best performance, natural gas should be used rather than diesel oil. The reason for this behavior is the higher heating value of the product derived from natural gas combustion, since diesel oil contains more water vapor. 6.2.6.1.2 Pressure Losses in the Compressor Inlet Section Losses in pressure are caused by the gas turbine inlet system, which consists of an air filter, a silencer, an elbow, variations in pipe section, and so on installed upstream of the compressor suction flange. During the flow of air through this system, friction reduces the pressure and specific weight of the air. As a result of these losses, useful power is reduced, and heat rate is increased, as previously mentioned. 6.2.6.1.3 Pressure Losses in the Turbine Exhaust System Gas turbine exhaust systems consist of one or more silencers, an elbow, a recovery boiler (in the case of a combined cycle or cogeneration), diverters, diffusers, and so on, through which exhaust gases are expelled. In this system, exhaust gases are subjected to friction losses, which increase back pressure as opposed to external, atmospheric pressure. By reducing the amount of turbine expansion, these losses result in a reduction in useful power and an increase in heat rate. 6.2.6.1.4 Air Extraction from the Axial Compressor Compressed air may need to be extracted from the compressor discharge in some gas turbine applications. Extracting air will influence the output power and heat rate, taking into account the ambient temperature as well.

220

Equipment and Components in the Oil and Gas Industry

6.2.6.3 Compressor Stalls A multi-stage axial compressor is used to develop high pressure ratios. The operation of each stage at the same speed may result in early stages being overloaded and later stages operating inefficiently at some compressor speeds if all stages operate at the same speed. The worst-case scenario may result in compressor stalling, which is similar to the stall of an aircraft wing. There are some blades that resemble miniature aerofoils. Compressors are also subject to this limitation. It is possible that the air flowing around the blades is at a high angle of attack at certain speeds, causing the air to separate and cause the compressor to stall. During a compressor stall, the airflow in the compressor of a gas turbine or turbocharger is disrupted locally. In the event of a compressor surge, the airflow through the compressor is disrupted completely as a result of a stall. Figure 6.4 shows the stalling effect. According to these figures, the lift force of the aerofoil has decreased, while the drag force has increased as a result of the large turbulent wake. Air flow creates different pressures at the top and bottom of the airfoil, which causes lift force or turbine blade rotation.

FIGURE 6.4  Stalling effect.

Prime Movers

221

6.2.6.4 Surge In compressors, surge occurs when the amount of gas they are trying to compress is insufficient for the size of the compressor, resulting in the blades losing their ability to transfer energy from the shaft to the fluid, causing a reverse flow of the gas. When the mass flow through the compressor is reduced beyond a certain point, the directions of the velocities and the blade angles are so different that the flow ceases to exist. As a result, the compressor surges. As a result of the surge effect, the turbine will be subjected to extreme vibration, damage to the blades, and noise.

6.2.7 Gas Turbine Types Gas turbines can be divided into four types: turbojets (jet engines), turboprops, turbofans, and afterburning turbojets. 6.2.7.1 Turbojets (Jet Engines) A typical axial-flow gas turbine turbojet, the J85, is shown in Figure 6.5. In the diagram, the flow is left to right, with the multistage compressor on the left, the combustion chambers in the middle, and the two-stage turbine on the right. Before World War II, German and British engineers developed turbojet engines, which have a limited range and endurance, as well as a high fuel consumption. As air is passed at a high rate of speed into the combustion chamber, where the fuel inlet and igniters are located, this type of engine produces a lot of heat. Turbines are driven by expanding air, causing accelerated exhaust gases to cause thrust. Turbojets are air-breathing jet engines that are typically used in aircraft. The propeller nozzle is attached to a gas turbine. An airbreathing jet engine is a type of gas turbine that is designed to produce thrust from exhaust gases or ducted fans connected to the gas turbine. The term turbojet refers to a jet engine that produces thrust directly from exhaust gases, while turbofan, or sometimes fan-jet engines, refers to a jet engine with a ducted fan to generate thrust. Among all turbine engines, the turbojet is the simplest.

FIGURE 6.5  A jet engine.

222

Equipment and Components in the Oil and Gas Industry

The first jet engines were turbojets, also known as air-breathing jet engines with turbines. Air is drawn into the engine through the inlet and is compressed. This design provided the basis for future jet engines. In the combustor, it is compressed by blades prior to entering the combustion chamber. It is the injection nozzles that are responsible for creating a mixture of fuel and air that is then burned. Gases from the combustion process expand explosively and flow at high pressure into the turbine, which drives the compressor. 6.2.7.2 Turboprop Engines A turboprop engine is a type of turbine engine that drives an external aircraft propeller through a reduction gear. In addition to being used on small subsonic aircraft, turboprop engines have also been used on large military and civil aircraft, such as the Airbus A400M, Lockheed L-188 Electra, and Tupolev Tu-95. Because of their superior fuel efficiency, turboprop turbines are commonly used in small aircraft, cargo planes, and agricultural applications. A  reduction gear drives the propellers of these engines, resulting in an optimum propeller performance at low speeds. 6.2.7.3 Turbofans A turbofan engine combines the best features of both turbojets and turboprops. A secondary flow of air is diverted around the combustion chamber in this engine, thereby providing additional thrust. In addition to being heavier than turbojets, they are also quite inefficient at higher altitudes. Today, turbofan engines are used by the majority of airlines.

6.3 STEAM TURBINES 6.3.1 Introduction Steam turbines are one of the oldest and most versatile prime mover technologies still in use today. Many plants around the world use them to drive machines and generate electricity. Since their introduction more than 120 years ago, steam turbines have replaced reciprocating steam engines due to their higher efficiency and lower costs. As you may recall from high school physics, water boils at a temperature of 100°C. As a result, the molecules expand, and vaporized water is formed—steam. Steam provides exceptional efficiency for energy production by utilizing the energy contained in the rapidly expanding molecules. In a steam turbine, thermal energy is extracted from pressurized steam and used to do mechanical work on a rotating shaft. It was invented by Charles Parsons in 1884 in its modern form. The turbine was used for lighting an exhibition in Newcastle, England, and produced only 7.5 kilowatts of energy. In large-scale power plants, steam turbine generators can generate over 1,000 megawatts of energy. The fabrication of a modern steam turbine requires advanced metalwork to create precision parts by forming high-grade steel alloys using technologies that were available in

Prime Movers

223

the 20th century; steam turbines remain an integral part of energy economics for the 21st century as long as they remain durable and efficient. A steam turbine is illustrated in Figure 6.6. A steam turbine is used to drive an electric generator, a gas compressor, and a number of critical pumps. There is no doubt that steam turbines are prime movers. Gas plants and refineries use them extensively because the processes used in these plants are exothermic and generate high-pressure steam (600 psig) as a result. An exothermic reaction is a chemical reaction that involves the release of energy in the form of heat or light. A steam turbine converts the pressure and heat energy of steam into mechanical energy (work). As with gas turbines, steam turbines can be divided into two classes, power generation and mechanical drive. Power generation turbines drive electric generators at a constant speed in order to maintain the frequency of the generated power. As the turbine runs at constant speed, features can be designed to provide a very high level of efficiency. The tolerances between the moving and stationary parts are very close. When variable speed is required for machinery such as compressors and pumps, mechanical drive turbines can be used. As a result of increasing mechanical strength, some efficiency is sacrificed. The tolerances are greater, and fewer stages are required.

FIGURE 6.6  A steam turbine.

224

Equipment and Components in the Oil and Gas Industry

FIGURE 6.7  Three-stage steam turbine.

There are many configurations of steam turbines. In order to maximize the energy transfer from steam, large machines are usually built with multiple stages. A three-stage turbine is shown in Figure 6.7.

6.3.2 Steam Turbine Components Component design for steam turbines is a complex task since it involves the design of three-dimensional parts. It is important to consider a number of factors when designing a machine, such as heat, pressure, impulsive force, sensitivity, stress, strain, vibrations, number of rotations, and efficiency, among others. Steam turbine components are explained as follows: Casing: To prevent steam leakage from the steam turbine, a casing is required. It is necessary to seal the ends of the casing where the shaft of the rotor passes in order to prevent steam leakages. In spite of the fact that leaks are not completely eliminated, they can be kept to a minimum. Depending on whether it is a high-pressure (HP) or low-pressure (LP) casing, the shape and construction details will vary. Single shell casings are used for low and moderate steam inlet pressures up to 120 bar. In response to an increase in inlet pressure, the casing thickness increases. It is very difficult to handle such heavy casings. If not, the thick casing may be subject to undue stress or distortion. Double casings are used in high-pressure and high-temperature applications in order to overcome this problem. A double casing consists of an inner casing for high pressures and an outer casing for holding low pressures. It is common for turbine casings to be heavy in order to withstand high pressures and temperatures. Due to the decrease in steam pressure from inlet to exhaust, it is generally accepted that the thickness of walls and flanges decreases from inlet to exhaust. The majority of turbines have horizontal

Prime Movers

225

FIGURE 6.8  A steam turbine casing.

split casings. The horizontal split makes it easy to assemble and dismantle the turbine for maintenance. It is also important to maintain the proper axial and radial clearance between the rotor and stationary parts. A gray casing is shown in Figure 6.8, which covers the internals of the steam turbine.   Cast carbon steel casings are generally used for low and intermediate pressure applications. They are capable of withstanding temperatures up to 425°C. For high-temperature high-pressure turbines, the casings are made of alloy steel, such as 3 Cr 1Mo (3% Chromium + 1% Molybdenum). The turbine casings are subjected to maximum temperatures and constant pressures. As a result, the casing material must undergo a high degree of creep. When a solid material is subjected to persistent mechanical stresses, creep occurs (sometimes called cold flow). In some cases, it is caused by long-term exposure to high levels of stress that are below the material’s yield strength. A material’s creep rate increases as it approaches its melting point when it has been heated for a prolonged period of time. Shaft: A  turbine shaft connects the turbine to the generator and rotates at the same speed as the turbine. Basically, it is a component used in a machine that is designed to produce continuous power. In the system it is used in, energy is extracted from a fluid flow and then converted into mechanical force. Steam turbine shafts are turned to various sizes along their length. There are wheels, bearing, and other parts attached to it.

226

Equipment and Components in the Oil and Gas Industry

A shaft is primarily responsible for transmitting power from wheels and blades to driven mechanisms. Turbine shafts are divided into low-pressure, intermediate-pressure, and high-pressure turbines in order to increase efficiency. A  turbine shaft is subjected to mechanical forces as a result of the dynamic action of steam. As a result of the action of pressurized moving steam, mechanical forces are acting on the steam turbine shaft. These mechanical forces take the form of tangential, axial, and centrifugal thrusts. Analytical calculations are performed to determine the mechanical forces acting on the shafts. It is important for large shafts to be manufactured in a way that will optimize the durability and performance levels when they are installed. High alloys are typically used in the manufacture of turbine shafts. It is common for shafts to be forged. Besides the forging operation, as with other types of large shafts, machining is performed on the shafts, and some metallic parts are removed. Figure  6.9 illustrates the machining of a steam turbine shaft connected to rotating wheels. Rotor: Steam turbines consist of a casing and a rotor with moving blades. During operation, the rotor is mounted inside the casing, which is composed of rows of moving blades inserted between rows of fixed blades. It is possible, however, to define the rotor as the part of a steam turbine that is moving, including the shaft and the moving wheels. In a turbine, high pressure steam passes through both fixed and moving wheels and blades alternately. As a result of the mechanism, the fixed blade directs the steam at a right angle for entry into the moving blades. To ensure that

FIGURE 6.9  A steam turbine shaft and rotating wheels. (Courtesy: Shutterstock)

Prime Movers

227

the rotor and its casing withstand thermal stress, as well as the moving blades fitted to the rotor, the utmost care must be taken. It is important to consider the operating principle of the turbine when designing a turbine rotor. Turbine rotors are typically forged from high-strength materials. Blades: In plants, steam turbine blades convert the linear motion of high-temperature, high-pressure steam flowing down a pressure gradient into a rotary motion of the turbine shaft. In a steam turbine, blades are the principal components that convert thermal steam energy into kinetic energy. Blades are mounted on rotating wheels, and they can be called buckets. An illustration of a steam turbine mounted on a rotating wheel is shown in Figure 6.10. As a result, the blades are highly resistant to the following factors: high temperatures and stresses caused by the pulsating steam load, stress caused by centrifugal force, and resistance to corrosion and erosion. There are many different designs of steam turbine blades. Several factors affect the design of the blades, including the size and style of the turbine. An impulse design and a reactive design are the two most common types of design. Impulse turbines are types of steam turbines in which the rotational force of the rotor is derived from the impact force or direct force of steam on the blades. This type of turbine consists of a free-rotating shaft mounted on a rotor. A set of curved blades

FIGURE 6.10  Blades of a steam turbine mounted on a rotating wheel. (Courtesy: Shutterstock)

228

Equipment and Components in the Oil and Gas Industry

is attached to the rotor. Afterwards, nozzles direct the high-pressure, high-temperature steam towards the turbine blades. From the impact force of the rapidly moving steam, the blades rotate. Reaction turbines are types of steam turbines that operate on the principle that the rotor spins as a result of a reaction force rather than an impact or impulse force. As a result of the reaction between the pressure and mass of the gas or fluid, reaction turbines produce torque. During the passage of gas or fluid through turbine rotor blades, the pressure of the gas or fluid changes. A primary difference between an impulse turbine and a response turbine is that in an impulse turbine, steam passes through the nozzle and the pressure decreases, whereas in a reaction turbine, steam passes through the guiding mechanism prior to passing through the rotating blades, and the pressure does not decrease. A comparison of impulse and reaction blade turbines is shown in Figure 6.11. Nozzle: Nozzles are used to guide steam to the moving blades and to convert pressure energy into kinetic energy. When it comes to small impulse turbines, the nozzles are located at the bottom of the casing. However, in the case of the larger turbine, the nozzles are located on the upper half of the casing. Therefore, a steam nozzle is a duct or passage with

FIGURE 6.11  Functions of impulse and reactive (reaction) turbine blades.

Prime Movers

229

a smoothly varying cross-sectional area that converts the heat energy of steam into kinetic energy. As a result of the shape of the nozzle, this conversion of energy will be accomplished with the least amount of loss possible. As the steam moves through the first portion of the nozzle, the velocity of the steam increases. There is also a later portion of the nozzle in which the steam is more influenced by volume than velocity. As steam passes through any section of the nozzle, its mass remains constant. The variation in steam pressure in the nozzle is determined by the velocity and specific volume of the steam. Generally, steam turbines use steam nozzles to produce a high-velocity jet of steam. The throat is the smallest part of the nozzle. Generally, there are three types of nozzles: convergent, divergent, and convergent-divergent. The cross-sectional area of a convergent nozzle decreases continuously from its entrance to its exit. In cases where the backpressure is equal to or greater than the critical pressure ratio, this type of nozzle is used. Divergent nozzles have an increasing cross-sectional area from their entrance to their exit. They are used in situations in which the back pressure is less than the critical pressure ratio. In convergent-divergent nozzles, the cross-sectional area decreases from the entrance to the throat and then increases from the throat to the exit. Stationary blades (diaphragms): A steam turbine has both moving and fixed blades, and the stationary blades are fixed to the diaphragm of the turbine. Diaphragms are stator parts of steam turbines that regulate the flow of steam to rotor blades and increase the turbine’s efficiency. In Figure  6.12, you can see the stationary blades or diaphragm of a steam turbine. Figure 6.13 illustrates how steam turbine diaphragms are installed within the casing. As shown in Figure 6.14, steam passes through the nozzle, rotating blades on the wheels, and diaphragm. Speed regulator: The speed regulator controls the overall speed of the turbine. Turbines are designed to operate at a rated speed known as synchronous speed, and if the turbine operates above this speed, it can damage the machine. When the turbine is operating at synchronous speed, its efficiency is at its maximum. Lubrication system: Small turbines are lubricated with oil floods, and larger turbines are lubricated with pressurized oil. Among the components of the pressurized lubrication system are the lube oil tank, the oil pump, the filter, the cooler, the pressure regulating valve, and so on. The pressurized lubrication system of a turbine shall conform to the American Petroleum Institute standard 614 (API) “Lubrication, ShaftSealing, and Oil-Control Systems and Auxiliaries.” The lubrication system is applied to the bearings that support the rotor by absorbing thrust forces generated within the turbine. It is possible that any other force that is created within the turbine may disturb the stability of its operation, resulting in a reduction in power output.

230

Equipment and Components in the Oil and Gas Industry

FIGURE 6.12  Stationary blades (diaphragms) for a steam turbine.

Turbine bearings: Considering that the turbine works at a high speed and with a large load, bearings are necessary in order for the turbine to operate safely and reliably. As previously discussed, lubrication is typically used to prevent friction between the bearing and the protected component. Bearings are one of the basic components of a steam turbine. Depending on the type of load acting on the bearing, radial (journal) bearings and thrust bearings are used. At each end of each rotor, journal bearings support the rotor’s weight. Journal bearings consist of two halves that enclose the shaft. Typically, one thrust bearing is provided for the entire steam turbine in order to maintain the axial position of the rotor. In addition to keeping the rotor in an exact position in the casing, the thrust bearing serves the following purpose: to absorb axial thrust on the rotor due to steam flow. The thrust bearing is used not only for taking up thrust loads but also for maintaining the rotational position of the rotor. An axial position indicator is often applied to the thrust bearing

Prime Movers

FIGURE 6.13  Stationary blades (diaphragms) installed inside the casing.

FIGURE 6.14  The passage of steam through the nozzle, wheels, and diaphragm.

231

232

Equipment and Components in the Oil and Gas Industry

FIGURE 6.15  Bearings in a steam turbine by softInWay.

in order to determine the rotor’s axial position. When the axial position of the rotor exceeds 0.3 mm, the alarm will sound and the machine will be shut down at 0.6 mm. Figure 6.15 illustrates the thrust and journal bearings in a steam turbine. Turbine seals: Seals are used to prevent steam from leaking between the rotary and stationary parts of the steam turbine. Seals are classified into two types based on where they are located, shaft seals and blade seals. Steam leakage is prevented by shaft seals located where shafts extend through casings. Up to a shaft surface speed of 50 m/s, carbon rings are used as shaft seals in small turbines. There could be segments in the carbon ring, which are tightly connected by a garter spring. In order to prevent the carbon rings from rotating within the housing, an anti-rotating pin is used to prevent their rotation. As a result of the self-lubrication properties of the carbon rings, they maintain a close clearance with the shaft. A labyrinth seal is used as a shaft seal on larger steam turbines. The labyrinth seal is a mechanical seal that provides a curved path to prevent leakage. Governor: A governor is one of the basic components of a steam turbine. The main purpose of this device is to control the operation of a steam turbine. There are two types of governors: speed-sensing governors and pressure-sensing governors or load governors. A speed-sensing governor is used in power generation applications to maintain a constant speed regardless of the load change in the governor. Trip and throttle valve: A  trip and throttle valve is a manual (start-up) valve that shuts off the supply of steam in the event of a malfunction or an emergency shutdown signal (ESD). Frequent malfunctions are overspeed, oil shortage, high vibration, and abnormal process conditions.

Prime Movers

233

When the trip valve is opened, the inlet steam takes a minimum pressure drop. The trip valve is sometimes combined with the governor valve. The governor valve controls the rate at which steam flows into the turbine. In conjunction with the governor, it maintains the turbine’s speed. Governor valves can be single or multiple valves, depending on the complexity of the machine. There are two types of operation available: mechanical and hydraulic. Steam chest: The steam chest is a chamber located between the governor valve and the nozzles. It is in this chamber that the steam pressure and temperature are at their peak in the turbine.

6.3.3 Principles of Operation The steam turbine converts the energy of high-pressure, high-temperature steam produced by a steam generator into shaft work. In order to convert energy, the following steps are taken:

1. Initially, the high-pressure, high-temperature steam expands within the nozzles and then emerges as a high-velocity fluid stream. 2. It is the high-velocity steam that comes out of the nozzles that impinges on the blades mounted on the wheels. While flowing past the blades, the fluid stream loses momentum, which is absorbed by the rotating wheel, thereby producing torque. 3. As a result of the expansion and acceleration of the steam relative to the moving blades, the blades move as a result of the impulse of steam (caused by the change of momentum). Therefore, they also function as nozzles. There are two major components of a steam turbine: nozzles and blades. Blades are sometimes referred to as buckets, as illustrated in Figure 6.16. The nozzles are stationary, while the blades rotate. It is important to note that steam contains energy in the form of pressure and temperature. The nozzles convert this energy into velocity energy. A nozzle is characterized by a drop in pressure and an increase in velocity. Jets of high velocity are fired from the nozzles and strike the blades, causing them to move. During the movement of the blades, velocity energy is converted into mechanical work, or electrical power. On rotating wheels, blades are arranged in rows.

6.3.4 Classifications of Steam Turbines Many factors determine how a steam turbine is classified, including exhaust conditions, stage designs, steam flows, shaft designs, and types of drives. 6.3.4.1 Exhaust Conditions Condensing steam turbine: The most common application of condensing steam turbines is in electrical power plants. In a condensing steam turbine, the maximum amount of energy can be extracted from the steam.

234

Equipment and Components in the Oil and Gas Industry

FIGURE 6.16  Steam turbine low-pressure rotor blades on wheels made of stainless steel.

This is accomplished by passing the exhaust steam through a condenser, which condenses the exhaust steam from the low-pressure stages of the main turbine. As a result of the large enthalpy difference between the initial and final steam conditions, a condensing steam turbine is able to extract the maximum amount of energy from the steam. It is the condensing steam turbine’s processes that produce the maximum mechanical power and efficiency from the steam supply. There is, however, a significant relationship between ambient temperature and the power output of condensing steam turbines. In addition to being expensive, this type of steam turbine is also very complex. Non condensing steam turbine or back-pressure steam turbine: During the rotation of the blades of a non-condensing steam turbine, high-­ pressure steam is used. Upon leaving the turbine, the steam is at atmospheric pressure or at a lower pressure. In industrial plants, back-pressure turbines are either single-stage or multi-stage devices that serve as a reducing station between the boiler and the process steam header. The most common application of back-pressure steam turbines is the production of process steam. Steam is a primary energy source for many industrial processes. There are many advantages to using steam as an energy source, including its high heat capacity, transportability, and low toxicity. Steam is produced by back-pressure steam turbines, which are also capable of generating mechanical work (or electricity). Using

Prime Movers

235

back-pressure turbines, live steam is expanded from the boiler to the pressure at which the process requires steam. Extraction steam turbine: In an extraction turbine, one or more openings are provided in the casing for the extraction of some portion of the steam at an intermediate pressure. Steam extracted from the process can be used for a variety of purposes. Depending on the design of the steam turbine, the steam extraction pressure may or may not be automatically regulated. In all applications, extraction-type turbines are commonly used. A  steam extraction turbine is used in some applications when steam extraction is required before steam passes through the final stage, known as the extraction turbine. Different types of extraction can be obtained from the steam turbine depending on the requirements of the customer’s plant. Mixed-pressure steam turbine: A mixed-pressure turbine is driven by two different types of steam (high pressure and low pressure) and can also be designed to use three types of steam (high pressure, intermediate pressure, and low pressure). In addition to enabling economical and optimal selection of pressure and temperature conditions for heat-recovery steam generators and boilers, these turbines can also be used when different steams from different boilers are used to drive the turbine. Regenerative extraction steam turbine: As a thermal process, regenerative extraction uses the remaining heat energy from the exhaust steam leaving the steam turbine. Reheat steam turbine: It is also common for reheat turbines to be used in electrical power plants. Steam exits a high-pressure section of the turbine and returns to the boiler, where additional superheat is added. The steam then returns to the turbine’s intermediate-pressure section and continues to expand. Reheating in a cycle increases the work output from the turbine and also allows expansion to take place before the steam condenses. Most of the time, the maximum number of reheats employed in the cycle is two, as the cost of superheating the steam cancels out any increase in turbine output. 6.3.4.2 Turbine Blades Steam turbine blades can be designed in a variety of ways, as previously explained. Several factors influence the design of the blades, including the size and style of the turbine. As discussed earlier in this chapter, impulsive and reactive turbine blade designs are most common. 6.3.4.3 Steam Flow There are three types of steam flow: axial, radial, and mixed. In an axial turbine, the flow of the working fluid is parallel to the shaft, as opposed to a radial turbine in which the fluid flows around the shaft. With mixed flow, steam flows both

236

Equipment and Components in the Oil and Gas Industry

radially and axially, providing a balance between the advantages of axial and radial turbines. In power plants, this type of turbine is commonly used. 6.3.4.4 Number of Stages Single stage refers to the process of converting kinetic energy into mechanical work in the turbine by expanding the steam only once. In the process industries, the single-stage steam turbine provides reliable and cost-effective drive solutions for fans, compressors, water pumps, and generators. The single-stage turbine is a reliable machine that is typically used for smaller power capacities of up to 300 kW. There are numerous practical applications for single-stage steam turbines, including water pumps, process pumps, oil pumps, compressors, generator drives, and fans. In a multiple-stage turbine, the energy is converted by two or more expansions of steam. In order to accommodate the volume expansion of steam as the pressure drops, turbines are designed with multiple stages. Steam expands in volume as it moves through the system and loses pressure and thermal energy, requiring larger diameters and longer blades in each subsequent stage to recover the remaining energy. 6.3.4.5 Casing Design There are three types of turbine arrangements: single casing, tandem compound, and cross compound. Single-casing units consist of a single casing and shaft coupled to a generator. A  tandem compound consists of two or more casings that are directly coupled together in order to drive a single generator. The cross-compound turbine arrangement consists of two or more shafts that are not parallel and drive two or more generators that operate at different speeds. The cross-compound turbine is typically used in a wide variety of large applications. 6.3.4.6 Types of Drive As with gas turbines, steam turbines can be divided into two categories, power generation and mechanical drive. Power generation turbines drive electric generators at a constant speed in order to maintain the frequency of the electricity generated. Due to the constant speed of the turbine, features can be designed to maximize efficiency. A mechanical drive turbine can be used when variable speed is required for machinery such as compressors and pumps. In order to increase mechanical strength, some efficiency must be sacrificed.

6.4 RECIPROCATING ENGINES A reciprocating engine, also known as a piston engine, is a heat engine that converts high temperatures and high pressure into rotation by using one or more reciprocating pistons. Several types of reciprocating engines exist, including the internal combustion engine, which is used in most motor vehicles. In addition, the steam engine, which is a type of external combustion engine. Heat engines consist of internal combustion engines (ICEs), which are commonly found in vehicles, boats, ships, airplanes, and trains. Because the fuel is ignited inside the engine,

Prime Movers

237

they are called ignitor engines. External combustion (EC) engines are reciprocating heat engines in which a working fluid, contained internally, is heated by combustion in an external source through the engine wall or a heat exchanger. It is generally believed that external heat or combustion engines are steam engines, and they differ from internal combustion engines in that the heat source is separate from the fluid that is used to perform the task. The external combustion engine, for example, heats water into steam by using a flame, then turns a turbine with the steam, as opposed to internal combustion, such as in a car engine, in which gasoline ignites inside a piston, performs work, and then is expelled. Despite the fact that external combustion engines are no longer used in transportation due to mobile designs not being efficient enough, they are still used in power plants. All reciprocating engines contain one or more pistons that follow a four-stroke cycle. A four-stroke engine is one of the most common types of internal combustion engines and is used in a wide range of automobiles (which specifically use gasoline as fuel) such as cars, trucks, and some motorbikes (many motorbikes use two-stroke engines). A four-stroke engine delivers one power stroke for every two cycles of the piston (or four piston strokes). The following is a description of the four-stroke engine and a further explanation of the process. 1. Intake stroke: As the piston moves downward to the bottom, the volume increases, allowing the mixture of fuel and air to enter the chamber. 2. Compression stroke: Upon closing the intake valve, the piston moves upwards until it reaches the top of the chamber. As a result, the mixture of fuel and air is compressed. A spark plug provides the activation energy necessary for combustion to begin at the end of this stroke. 3. Power stroke: When the fuel reaches the end of its combustion cycle, the heat released from the combusting hydrocarbons increases the pressure in the engine, which causes the gas to push down on the piston and generate power. 4. Exhaust stroke: The exhaust valve opens as the piston reaches the bottom of the cylinder. While the piston is moving back upward, the remaining exhaust gas is pushed out. The four-stroke cycle provides the engine with its energy, but now it must translate that energy into rotational energy for the transmission, drive shaft, and wheels. The crankshaft performs this function. It is the crankshaft that converts the up-and-down motion into rotational motion, which is usually combined with a flywheel in order to retain the discontinuous reciprocating energy in the form of rotational motion. The thermal efficiency of these gasoline engines will vary depending on the vehicle’s model and design. In general, gasoline engines convert 20% of the fuel (chemical energy) into mechanical energy, of which only 15% is used to move the wheels (the remainder is lost as a result of friction and other mechanical factors). A higher compression ratio is one way to improve thermodynamic efficiency in engines. This ratio is the difference between the minimum and maximum engine chamber volume.

238

Equipment and Components in the Oil and Gas Industry

QUESTIONS AND ANSWERS



1. The operation of a gas turbine can be summarized as follows. _______ increase the pressure of inlet air and feed it into _______, where ________ is added and ignited to raise the temperature of the compressed air. A nozzle converts the high-pressure gas into high _______, and a turbine rotor absorbs this energy, converting it into rotary motion to generate __________. A. Compressors, furnace, gas, velocity, energy B. Compressors, combustor, fuel, velocity, electricity C. Air turbine, furnace, gas, energy, energy D. Air turbine, combustor, fuel, energy, electricity Answer) Option B is the correct answer.



2. Regarding the gas turbine, which statement is incorrect? A. Generally, a gas turbine is a combustion engine that rotates a turbine using a gas as a working fluid. B. Most notably, gas turbines can be used for powering aircraft of all types, but they can also be used in industrial applications as prime movers for driving pumps, compressors, and producing electric power in the utilities sector. C. There are three components to a gas turbine: a compressor, a combustion chamber, and a turbine, all of which are mounted on the same shaft. D. The compressed air in a gas turbine enters the combustion chamber, where it is mixed with gas injected through nozzles. A mixture of gas and air is then ignited at a constant temperature and volume under constant conditions.

Answer) It is incorrect to choose option D because it contains two errors: First, air is mixed with fuel rather than gas in the combustion chamber. Second, the fuel and air mixture is ignited at constant pressure, but the temperature and volume of the gas are increasing.

3. What is the incorrect statement regarding the efficiency of gas turbines? A. The surge in compressors occurs when the amount of gas they are trying to compress is insufficient for the size of the compressor, resulting in the blades losing the ability to transfer energy from the shaft to the fluid, resulting in a reverse flow of the gas. The efficiency of gas turbines is not affected by this parameter. B. Some gas turbine applications require the extraction of compressed air from the compressor discharge. A gas turbine’s output power and efficiency will be affected by the extraction of air. C. The efficiency of gas turbines decreases with an increase in air temperature and a decrease in air pressure. D. It is recommended that natural gas be used instead of diesel oil in order to achieve optimum performance.

Prime Movers



239

Answer) Option A is the wrong answer. The efficiency of the gas turbine is reduced by surges in the compressor.

4. Which of the following statements about gas turbine components is correct? A. It is common for turbine casings to be vertically split in order to facilitate maintenance and reassemble the turbine. B. In operation, the nozzle is mounted inside the casing, which consists of rows of moving blades inserted between rows of fixed blades. C. The blades of a steam turbine convert the linear motion of high-pressure, high-temperature steam flowing down a gradient into a rotary motion of the shaft. D. Steam turbine shafts are commonly made of carbon steel.

Answer) Option A is incorrect because turbine casings are usually horizontal, not vertical, as horizontal casings are easier to maintain and assemble. The provided definition of option B is incorrect because it refers to a rotor rather than a nozzle. It is correct to choose option C. It is incorrect to choose option D because shafts should be manufactured from high strength materials such as high alloy chromium molybdenum, and carbon steel does not possess high strength properties.



5. The use of this type of turbine is indicated when shaft work is required and steam is required for process heating. Steam is fed to the turbine at high pressure. Turbines produce work. As the steam leaves the turbine, it is at a medium to low pressure, ranging from 225 to 15 pounds per square inch. The remaining steam is then distributed to those parts of the plant requiring steam energy to produce heat or to steam turbines with lower inlet steam pressures. A. Condensing steam turbine B. Backpressure steam turbine C. Extraction steam turbine D. Mixed pressure steam turbine



Answer) Option B is the correct answer. To produce steam for process applications, backpressure or non-condensing steam turbines are used.



6. What is the component of the turbine with the highest steam pressure and temperature? A. Shaft B. Steam chest C. Nozzle D. Blades

Answer) Option B is the correct answer.

7. Which statement is correct regarding the bearings in a steam turbine? A. Bearings are not responsible for the safety or reliability of steam turbine operation.

240



Equipment and Components in the Oil and Gas Industry



B. It is not necessary to lubricate the bearings. C. Depending on the type of load acting on the bearing, radial (journal) bearings and thrust bearings are used. D. All three options are incorrect.



Answer) Option C is the correct answer.

8. In a reciprocating engine, what is the last stroke? A. Intake B. Compression C. Ignition D. Exhaust

Answer) Option D is the correct answer.

9. Identify the correct statements regarding reciprocating engines. A. A two-stroke engine is one of the most common types of internal combustion engines. B. The term “heat engine” refers to an external combustion engine, which is commonly found in vehicles, boats, ships, and planes. C. Combustion engines with external combustion utilize an external source of heat to heat a working fluid contained internally. D. A reciprocating engine, also known as a piston engine, is a heat engine.

Answer) Reciprocating engines have four strokes, which makes option A incorrect. Option B is incorrect since the sentence refers to an internal combustion engine, not an external one. The statements in options C and D are both correct.

10. On the basis of which parameter are steam turbines classified as impulsive and reactive? A. Steam flow B. Blade design C. Exhaust condition D. Casing design

Answer) Option B is the correct answer.

FURTHER READING 1. Basha, M., Shaahid, S. M., & Al-Hadhrami, L. (2012). Impact of fuels on performance and efficiency of gas turbine power plants. Energy Procedia, 14, 558–565. 2. Boyce, M. P. (2011). Gas turbine engineering handbook. Texas, USA: Elsevier. ISBN: 978-0-12-383842-1 3. Burnes, D., & Camou, A. (2019). Impact of fuel composition on gas turbine engine performance. Journal of Engineering for Gas Turbines and Power, 141(10), 101006. 4. Chola Turbo Machinery International PVT. Ltd. Steam turbine and its components. [online] available at: www.cholaturbo.com/steam-turbine-and-its-components/ [access date: 21st June, 2023]

Prime Movers

241

5. Energy Education. (2023). Four stroke engine. [online] available at: https://energyeducation.ca/encyclopedia/Four_stroke_engine [access date: 25th June, 2023] 6. Energy Education. (2023). Reciprocating engine. [online] available at: https://energyeducation.ca/encyclopedia/Reciprocating_engine [access date: 25th June, 2023] 7. Han, J. C. (2013). Fundamental gas turbine heat transfer. Journal of Thermal Science and Engineering Applications, 5(2). 8. Mechanical Engineering Site. (2017). Steam Turbine Basic Parts. [online] available at: https://mechanicalengineeringsite.com/steam-turbine-basic-parts/ [access date: 21st June, 2023] 9. Poullikkas, A. (2005). An overview of current and future sustainable gas turbine technologies. Renewable and Sustainable Energy Reviews, 9(5), 409–443. 10. Sheikhbahaei, R., Vossughi, G., & Alasty, A. (2020). Optimal tuner selection using Kalman filter for a real-time modular gas turbine model. Scientia Iranica, 27(2), 806–818. 11. Thorat, S. (2023). Steam nozzle—definitions, types, efficiency, application. [online] available at: https://learnmech.com/what-is-steam-nozzle-types-of-steam-nozzleshapes/ [access date: 22nd June, 2023] 12. Walsh, P. P., & Fletcher, P. (2004). Gas turbine performance. New York: John Wiley & Sons. ISBN: 0–632–06434-X

7

Storage Tanks

7.1 INTRODUCTION Typically, oil and gas production and transportation are not continuous processes. In spite of the fact that there is a direct pipeline between the point of oil and gas production and the customers, the rate of consumption does not exactly match the rate of production, which suggests that petroleum transportation should be stopped. In such cases, it is necessary to store the product for a period of time. Without storage tanks, oil and related products cannot be transported from their point of production to their final destination. This is only one example of the use of a storage tank. A storage tank is a container used to store liquids or gases for a variety of purposes. Storage tanks can be either underground or aboveground and are typically made of steel or plastic. They are used in a variety of industries, including oil and gas, chemical, water treatment, and manufacturing. Historically, it has been a tremendous achievement for many industries, such as the oil and gas industry, to be able to store large quantities of liquids and gases. Storage tanks are primarily used to store liquids and pressurized gases. A variety of materials are stored in storage tanks in chemical, petrochemical, and refinery operations, including crude oil, intermediate and refined products, gas, chemicals, and water. Various types and sizes of tanks are available depending on the type of product they store and the volume they hold. Tanks are designed according to the characteristics of the fluid stored, including quantity, volatility, chemical properties, and corrosion resistance, as well as considerations such as required storage pressure. There are three types of storage tanks: aboveground, underground, and in the ground. It is possible for the storage to last for a short period or for a long period of time. A storage tank operates under no (or very little) pressure, which sets it apart from a pressure vessel. Vertical cylinders are the most common form, although horizontal cylinders and spherical and rectangular forms may also be found. A number of aboveground tanks in the horizontal cylindrical shape in Figure  7.1 are used to store chemical products such as oil and gasoline.

7.2 STORAGE TANK TYPES There are three general types of storage tanks: atmospheric storage, pressurized storage, and low-temperature storage.

7.2.1 Atmospheric Tanks It is possible to store liquids in atmospheric storage tanks, including crude oil, gasoline, and other products, as well as water. There is typically an internal pressure 242

DOI: 10.1201/9781003467151-7

Storage Tanks

243

FIGURE 7.1  In order to store chemical products such as oil, petrol, and gas, multiple storage tanks are used. (Courtesy: Shutterstock)

of approximately atmospheric pressure within an atmospheric storage tank (lower than the weight of the roof of the tank). In general, these tanks are constructed using all-welded carbon steel; however, they may also be bolted or riveted if they were constructed prior to the development of reliable welding equipment and practices. Typically, atmospheric storage tanks are classified based on the type of roof installed on them. Generally, there are three types of atmospheric storage tanks: fixed roofs, floating roofs, and fixed roofs with floating roofs inside. 7.2.1.1 Fixed-Roof Storage Tanks The most basic type of atmospheric storage tank is a fixed-roof tank. Based on current tank designs, fixed-roof tanks are the least expensive to construct and are generally regarded as the minimum acceptable equipment for storing liquids. Typically, a fixed-roof tank is constructed with a cylindrical steel shell attached permanently to a cone- or dome-shaped (spherical) roof. As a general rule, modern storage tanks are fully welded and designed to be liquid and vapor tight, while older tanks frequently have riveted or bolted constructions that are not vapor tight. In the case of welded storage tanks, API 650, a standard issued by the American Petroleum Institute, applies. In general, it refers to a tank for storing liquids with high flash points (such as fuel oil, water, diesel, kerosene, bitumen, and so forth). It is important to note that a “flash point” refers to the lowest temperature at which a liquid will emit vapor in sufficient concentration to ignite the air near its surface. It is generally believed that the lower the flash point of a liquid solvent, the easier it is to ignite it. As illustrated in Figure 7.2, the roof of a fixed-roof storage

244

Equipment and Components in the Oil and Gas Industry

FIGURE 7.2  Cone roof storage tanks (left side) vs dome roof storage tanks (right side).

tank is typically shaped like a cone or dome and is permanently attached to the cylindrical shell. Compared to dome roof tanks (DRTs), cone roof tanks (CRTs) are less expensive. CRTs are suitable for fluids at atmospheric pressure and low vapor pressure when it comes to fugitive emissions and evaporation losses. The CRT is capable of storing two types of fluid: diesel and heavy fuel oil. When a CRT is used to store fluids with high vapor pressure, it is susceptible to evaporation losses due to its low mechanical strength. Despite their higher cost than CRTs, dome roof tanks are better suited to fluids with high vapor pressure, such as pentane. As a matter of fact, DRTs have a greater mechanical strength against internal pressure than CRTs. Both CRTs and DRTs have a common weakness, which is the risk of corrosion damage to the vapor space inside the tank. 7.2.1.2 Floating-Roof Storage Tanks A floating-roof tank is equipped with a floating roof, as its name suggests. According to the level of the product, this floating roof adjusts its height by floating up and down. Such industrial storage tanks are widely used to store volatile oils, such as aviation fuel, gasoline, crude oil, diesel oil, and other light oils. The floating roof is an essential factor of these tanks. The price of these tanks is generally higher than that of fixed-roof tanks. Floating-roof tanks have a shell and bottom similar to cone roof tanks, except that the roof is designed to float above the liquid being stored. Historically, floating-roof tanks were developed by the Chicago Bridge & Iron Company (CB & I) following the end of World War I. Researchers conducted research to develop a roof that floats directly on the surface of the product in order to reduce evaporation losses caused by fixed roofs. In the case of oil storage, it has been demonstrated that floating-roof tanks reduce oil loss by approximately 80% as compared to fixed-roof tanks. When filling and emptying floating-roof storage tanks, hydrocarbon vapor is minimized through breathing losses. As a result of the floating roof, any vapor space above the stored liquid is eliminated or maintained at a small and constant level, thereby reducing the risk of fire significantly compared to fixed-roof tanks. A floating-roof storage

Storage Tanks

245

tank can reduce evaporation losses, therefore reducing economic losses and complying with environmental regulations. Gasoline, jet fuel, and other volatile oils can be stored in a floating-roof tank, as well as liquid chemicals such as aldehydes, alcohols (methanol, ethanol), ketones (acetone), and benzene (benzene, toluene, xylene, and styrene). It is not appropriate to use floating-roof tanks for all products. Generally speaking, it is not recommended that they be used in applications in which the products have not been stabilized (the vapors have not been removed). The process of fractionation can stabilize crude oil by subjecting it to high temperatures and pressures, which drive off light hydrocarbon components and create “dead” crude oil with a lower vapor pressure. Floating storage tanks consist of three primary components: the roof itself, the sealing, and the roof supports. Floating roofs can be added to enclosed or open-top tanks. A floating roof is a circular steel structure with built-in buoyancy so it can sit and float on top of liquid products. It is common for the roof diameter to be smaller than the inside diameter of the tank, which results in a small gap between the roof and the inside wall of the tank. It is possible for the floating roof to rise and fall without binding to the tank walls as a result of the gaps. In order to protect the product inside the tank from evaporation and contamination from rainwater, a flexible sealing system will be used to seal the gaps between the floating roof and the tank wall. Similar to the tube inside a bicycle tire, floating-roof tanks have a seal. When the liquid level in the tank increases or decreases, it runs against the side of the tank to ensure it does not pass the seal. Due to environmental concerns, choosing the right roof seal is a major concern when designing floating-roof tanks. There are two positions in which you can adjust the roof’s support legs. In order to clean and maintain the tank, the upper position is sufficient. In the lower position, the roof is just above the inlet and outlet nozzles, drainage system, and other accessories or nozzles located on the bottom side. In conclusion, floating-roof storage tanks have the following advantages: • A floating-roof tank offers the most cost-effective solution to reducing emissions and the loss of product. • The use of these types of tanks will allow for a greater utilization of storage capacity and a reduction in evaporation losses. • Floating roofs reduce the risk of fire and explosion in aboveground tanks for dangerous liquids with high volatility • The use of these tanks ensures that there is no possibility of an implosion and that the most beneficial ecological results are achieved. • The presence of highly corrosive fluids in a fixed-roof tank will always result in corrosion of the shell in the vapor space. Floating-roof tanks, on the other hand, reduce shell corrosion by reducing or eliminating the vapor space, in addition to reducing fire risks. • Floating-roof tanks prevent the stored oil from becoming polluted due to rain, wind, sand, snow, or dust. This advantage is only available with internal floating-roof storage tanks.

246

Equipment and Components in the Oil and Gas Industry

Floating-roof storage tanks come in two types: external and internal. 7.2.1.2.1 Internal Floating-Roof Tanks An internal floating-roof storage tank has both a floating roof and a fixed roof, which is a new type of storage tank that combines the dome storage tank with the floating-roof storage tank. The roof of an internal floating-roof tank is a combination dome roof with a fixed roof on the exterior and a floating roof on the interior (see Figure 7.3). As a result of the internal floating-roof tank, wind, sand, rain, snow, and dust are prevented from invading, therefore ensuring that the liquids stored remain in good condition. Further, the internal floating roof floats within the liquid, eliminating vapor spaces in the liquid; reducing evaporation losses by 85%–96%; and reducing air pollution, fire, and explosion risks, as well as maintaining the quality of stored liquid, particularly high-grade gasoline, jet fuel, and toxic petrochemicals. The absence of gas spaces on the liquid level reduces corrosion of the tank wall and roof, thus extending its useful life. Under the same sealing conditions, the internal floating-roof tank has the advantage of being able to reduce evaporation losses even further than the external floating-roof tank. Furthermore, internal floating-roof tanks are subject to the same disadvantages as dome roof tanks, such as higher construction requirements and a greater consumption of steel plates. In comparison with external floating-roof tanks, maintenance is more challenging, the structure is sealed, and it is not easy to construct a large tank.

FIGURE 7.3  An internal floating-roof tank.

Storage Tanks

247

FIGURE 7.4  An external floating-roof tank.

7.2.1.2.2 External Floating-Roof Tanks The floating roof of a storage tank moves up and down in response to the input and output of liquid. An annular space exists between the floating roof and the tank wall, which is sealed with a sealant. When the top roof of the storage tank is floating up and down, the liquid in the tank is isolated from the atmosphere, thereby reducing evaporation losses. Figure 7.4 illustrates an external floating-roof tank. 7.2.1.3 Low-Pressure Storage Tanks The internal pressure of low-pressure storage tanks is designed to exceed the limits of atmospheric tanks, but not to exceed 103 kPa (15 psig). They are usually made of carbon steel welded together; however, stainless steel and nickel alloys may be required for applications requiring very low temperatures. In low-pressure storage tanks, substances with a true vapor pressure greater than 17 kPa (2.5 psig) but less than 103 kPa (15 psig) are stored. Low-pressure storage tanks are used to store liquids such as light crude oil and volatile chemicals. For the design and manufacture of these tanks, API 620 is used as a standard. In general, low-pressure storage tanks are classified based on their shape. There are four types of

248

Equipment and Components in the Oil and Gas Industry

low-pressure tanks: cylindrical shell, hemispheroidal, spheroidal, and noded spheroidal. A cylindrical shell is typically used for pressures of less than 34 kPa (5 psig), as well as cylindrical tanks with cone roofs or dome roofs. Cylindricalshell storage tanks are one of the most common types of low-pressure storage tanks. In general, the bottom of a tank is flat, though it may also be shaped in the form of a roof. Tanks that are hemispherical, spherical, or noded spheroidal are usually used when the pressure exceeds 34 kPa (ga; 5 psig). 7.2.1.4 Low-Temperature Storage Tanks A tank designed for low-temperature storage operates at a pressure no greater than 103 kPa (15 psig) in its vapor space below ambient temperatures. Welded steel is used in the construction of the tanks. The use of low-temperature storage tanks is common for storing refrigerated products and liquefied hydrocarbon gases, such as ethane, ethylene, and methane. A number of studies have shown that low-temperature storage tanks are economically more advantageous than pressurized storage tanks, which are typically used for large quantities of material. Tanks that are designed to be refrigerated can either be single-wall insulated or double-wall insulated. In simple terms, a double-wall tank consists of an inner tank which contains the refrigerated liquid and an outer tank which encloses the inner tank with insulation. It is not necessary for the outer tank to contain the product that is enclosed in the inner tank.

7.3 STORAGE TANK COMPONENTS The primary components of storage tanks are foundations, shells, bottoms, and roofs.

7.3.1 Foundations Under the storage tank, the foundation supports the tank and its contents. The structure of the tank is also elevated above the ground level of the surrounding pit. Under all design load conditions, the foundation must provide the necessary support. A foundation can be constructed from concrete, crushed stone, compacted earth, or a combination of these materials, depending on the application. A concrete ringwall foundation is used for large-capacity storage tanks with high weight loads on the foundation beneath the shell. A concrete ring surrounds a compacted fill material (earth, sand) in an earthen ringwall foundation (Figure 7.5). Ringwalls provide a better distribution of the concentrated load from the shell and provide a more uniform load to the soil under the tank than foundations without ringwalls. A  ringwall foundation is not necessary in the case of small storage tanks. As a foundation material, compacted crushed stones, screenings, fine gravel, clean sand, or other materials may be placed directly on virgin soil. It may be necessary to install a release prevention barrier under the tank foundation in order to prevent the emission of the storage tank content and their escape into the soil. Examples of these barriers include synthetic materials, steel bottoms, and clay liners.

Storage Tanks

249

FIGURE 7.5  A storage tank foundation with a concrete ring and earth (soil).

As well as supporting the tank and its contents, the foundation also elevates the structure of the tank above the surrounding surface. The foundation must provide adequate support under all design load conditions. There are three main functions associated with storage tank foundations: First, to spread and transfer the load from the tank and its contents via the tank foundation so that settlement remains within acceptable limits. For the construction and operation of tanks, it is important to provide a smooth surface that is stable and has sufficient bearing capacity. Last but not least, the foundation of the storage tank must be designed to channel rainwater away from the bottom and shell of the tank. The settlement of a storage tank refers to the movement or deflection of the bottom or shell of the tank caused by a variety of factors, such as soil movement or foundation movement. Foundations for storage tanks can be categorized into five general categories. In all circumstances, there is no universal answer to the question of which tank foundation is the best. Depending on the specific circumstances of each case, each case should be assessed individually. The first type of foundation is the earth foundation (Figure  7.6, first picture from the top). This type is the most economical. In addition to being the most economical foundation for tanks, earth foundations are also easy to construct and provide a straightforward construction process. As a result of the lack of support under the tank shell, settlement may become critical there, resulting in a non-uniform settlement that may cause bottom damage. Moreover, heavy loads applied by the shell and roof may cause stress concentrations under the edges of the tanks, resulting in local failures. The most common type of tank foundation is an earth foundation surrounded by a concrete ringwall. To support the heavy loads imposed by the shell, a concrete ring foundation is used (Figure 7.6, second picture from the top). Ringwalls are highly recommended when there are large tanks, tanks with heavy or tall shells, or tanks with self-supporting roofs that place a substantial load on the foundation under the shell. Under the tank, a uniform soil load is produced by evenly

250

Equipment and Components in the Oil and Gas Industry

FIGURE 7.6  Storage tank foundation types.

Storage Tanks

251

distributing the concentrated load of the shell. A  concrete ringwall provides a level, solid starting plane for the construction of the shell, preserving its contour during construction. As a result, the tank bottom material is prevented from eroding and moisture is minimized under the tank. The third type of foundation for a tank is an earth foundation surrounded by crushed stone or gravel (Figure 7.6, third picture from the top). It is possible to install crushed stone ringwalls on an earth foundation instead of the concrete ringwall discussed in the previous section. A crushed ringwall is installed beneath the shell, and the tank bottom area is filled with fine gravel, coarse sand, or other stable materials that have been compacted thoroughly. Crushed stone ringwalls have a number of disadvantages. However, the main disadvantage is that they are more difficult to construct to close tolerances and achieve a flat, level surface for the construction of the tank shell. The fourth type of foundation construction is reinforced concrete slabs (Figure 7.6, fourth picture from the top), which are typically used for small storage tanks but not for large ones. It may be necessary to use these methods when soil-bearing loads need to be distributed over an area greater than the tank area or when the tank owner requires a rigid uniform foundation. A piled foundation may be the best option if the tanks or equipment are sensitive to settlement or if the subsurface conditions are extremely poor. This type of foundation replaces the concrete slab beneath the tank with piles of concrete or other suitable materials (Figure 7.6, last picture at the bottom). A refinery storage tank with an earthing foundation and concrete ringwall is illustrated in Figure  7.7. An asphalt layer is applied to the earthing foundation as a surface finish layer. An important function of the surface finishes of the tank foundation is to protect it from damage caused by weathering, erosion, and construction, operation, and maintenance activities. Besides promoting uniform stress distribution between the bottom of the tank and the foundation, the bitumen layer also allows the bottom of the tank to expand under thermal conditions.

7.3.2 Shells As used here, the shell refers to the vertical component of the tank that is welded to the floor plates. Steel plates are used in the construction of the shell in accordance with applicable specifications. The shell of a tank is constructed from rolled plates that are welded together to form a cylindrical shape. During the process of forming the cylindrical shape over the previous plate, the height of the tank gradually increases. A tank course refers to the height of each plate. For example, the first plate welded to the bottom plate is referred to as course one, the second as course two, and so on. API 650 specifies a minimum width of 1800 mm, unless otherwise agreed by the purchaser. Plate widths of 1800 mm correspond to course heights of 1800 mm. As shown in Figure 7.8, workers inspect welding joints between the plates forming a storage tank’s shell while working at height on scaffolding.

252

Equipment and Components in the Oil and Gas Industry

FIGURE 7.7  Earth foundation with concrete ringwall for storage tanks. (Courtesy: Shutterstock)

FIGURE 7.8  During the fabrication of the storage tank shell, workers inspect the plates that are welded together. (Courtesy: Shutterstock)

Storage Tanks

253

7.3.3 Bottoms (Floors) The bottom or floor of a storage tank is located above the foundation. It is the foundation that continuously supports the bottom of the storage tank. Tank floors can be constructed using two types of plates: bottom plates and annular plates. A tank’s annular plate is a ring of plates located directly beneath its shell plates. The top plate is usually thicker than the bottom plate as it supports the weight of the shell and/or self-supporting roof. API 650 requires an annular bottom plate to have a radial width of at least 600 mm (24”) between the inside of the shell and any joints on the rest of the bottom. The bottom plate of a storage tank is seated inside the shell plate and welded to the annular ring plates. According to API 650, the bottom plate shall have a minimum thickness of 6 mm, excluding any corrosion thickness specified by the purchaser. Figure 7.9 shows an inspection of the weld joints between the bottom plates of a storage tank. Figure 7.10 illustrates the floor of a storage tank, including its bottom and annular plates. You may refer to API 650 or another code for information regarding the dimensions of tank bottom plates and the requirements for plate overlap. According to API 650, there are four types of storage tank floors: flat horizontal, flat sloping, coned-up bottom, and coned-down bottom. The choice of the storage tank floor has a significant impact on the possibility of full drainage. The following paragraph provides a more detailed explanation of why storage tanks may require complete drainage.

FIGURE 7.9  Workers inspect the weld joints between the bottom plates of a storage tank. (Courtesy: Shutterstock)

254

Equipment and Components in the Oil and Gas Industry

FIGURE 7.10  The floor of a storage tank, including the annular and bottom plates. (Courtesy: Shutterstock)

7.3.3.1 Flat Horizontal Bottoms Smaller volumes of storage are generally accommodated by tanks with flat bottoms. Storage tanks with this type of floor are solid and simple in design, making them an affordable alternative to other types of tanks. As a result of its simplicity, this type of tank can be used in a variety of environments. Nevertheless, it is not an ideal solution for situations in which a thorough and complete drainage is essential. As a result of its flat shape, it is not well suited for thorough drainage as other types of storage tanks are. Flat horizontal bottom tanks are not suitable for fluid storage tanks that must be drained completely during a fluid change. 7.3.3.2 Flat Sloping Bottoms In contrast to tanks with flat horizontal bottoms and coned-up bottom tanks, this design provides 2% of flat sloping at the bottom. In accordance with their name, these tanks have a sloped floor that makes it easier to access the drain. A  flat sloping bottom (sloped bottom) tank would be an excellent choice if the storage tank will be drained frequently and coned bottom tanks are not an option. Storage tanks with flat sloping bottoms have some disadvantages, such as a lower capacity and higher costs. 7.3.3.3 Coned-Up and Coned-Down Bottoms A cone-shaped or dish-shaped bottom provides two major advantages over a flat floor: improved structural strength and greater ease of drainage for cleaning and maintenance purposes. A  conical bottom tank is ideal for situations in which a complete and proper drainage system is required. In order to prevent contamination issues associated with lingering remnants of older batches of chemicals, it is important to drain storage tanks properly. Because the unique shape of a conical bottom tank acts as a funnel, the entire bottom of the tank can be

Storage Tanks

255

thoroughly drained. It may be appropriate to use the coned-up bottom design for larger tanks with a slope between the center of the floor and the surrounding sides of the shell. The design of this type is ideal for the transportation of liquids with a higher specific density than water. Compared to two alternative designs, including flat horizontal and coned-bottom designs, a coned-up design has two main disadvantages, including a lower-capacity storage tank. Second, the fluid within the tank drains toward the shell. As a result, poor drainage of corrosive fluids inside a cone-up bottom storage tank can result in corrosion of the shell and outer floor plates. In comparison to the other three types of bottom tanks, the coned-down tank provides a greater capacity for storage. The latter design is suitable for floating storage tanks that handle liquids and must be drained frequently for a variety of reasons, such as changing the fluid service. Approximately 2% to 4% of the slope slopes downward toward the center. Among the major problems associated with coned-down floors, corrosion is the most significant. Additionally, there are disc-bottomed tanks. This type of tank has a rounded shape, which makes it ideal for those who need to mix their storage contents. It is the round shape of disc-bottomed tanks that contributes to the mixing and flow of materials within the tank.

7.3.4 Roofs There is a roof covering all tanks that protects the stored product from the environment around it. As well as reducing the amount of vapor released into the atmosphere, the roof also reduces heat loss. Several types of roofs are discussed in this chapter, such as domes, cones, and floating roofs. Several factors must be considered when selecting a roof type, including the size of the tank, local regulations, emission considerations, and the type of fluid being stored.

7.3.5 Accessories An accessory is an item of equipment that enhances the functionality of a storage tank. Depending on the type, size, and service of a particular storage tank, the types and number of appurtenances installed on the tank may vary. In this chapter, we will discuss some of the storage tank accessories that contribute to fugitive emissions from storage tanks, such as breather valves, gauges, sampling components, and manholes. The purpose of this section is to provide a more comprehensive overview of storage tank accessories. The following appurtenances serve a wide range of functions: vents, drains, seals, heaters, mixers, hatches, gauges, platforms, ladders, and stairs. After industrial valves, including safety valves, storage tanks are considered the second largest source of fugitive emissions in the oil and gas industry. Oil and gas plants emit approximately 75% of all fugitive emissions from valves, including pressure safety valves, while storage tanks emit 10%. This section provides an overview of some of the main accessories used in storage tanks, particularly fixed-roof tanks, which contribute to fugitive emissions and environmental

256

Equipment and Components in the Oil and Gas Industry

pollution. Some of these accessories prevent fugitive emissions, while others may cause evaporation loss and fugitive emissions from the tanks. 7.3.5.1 Gauge and Sampling Components The purpose of tank gauging is to quantify the volume and mass of liquids within large storage tanks. In the oil and gas industry, static volumetric assessments of tank contents are commonly used. There is a measurement of level, a measurement of pressure, and a measurement of temperature associated with this process. A  floating-roof storage tank’s sampling pipes can also contribute to emissions. In floating-roof tanks, it is common to have one or more still-pipes connected to gauges that extend through the tank’s roof to its top. The still-pipe can be used for sampling, hand level measurement, hand temperature measurement, and automatic tank measurement. Measuring the volume and level of storage tanks is primarily intended to prevent overfilling. The consequences of overfilling a tank can be disastrous. There is a risk that a spill could lead to explosions and fires spread throughout a tank farm and its surrounding area if a spill occurs. Since the tanks contain large amounts of stored energy, a fire can have far-reaching consequences. Fires caused by overfilling have resulted in over $1 billion in legal damages. As a result of this and a number of other considerations, it is extremely important to prevent tanks from overfilling. The term “tank farm” refers to a facility or an area that is exclusively used for the storage of chemicals, such as petroleum. Tanks and equipment are included in this area. Petrochemical liquids are often stored in tank farms before they are shipped to consumers or retail outlets. Tank farms are susceptible to corrosion and fire, so proper corrosion and fire protection is essential. Besides measuring the level of liquid in the storage tank, it is also possible to detect any leaks within the tank. If the tank gauging system is accurate and stable, it may be used to detect tank leaks. 7.3.5.2 Breather Valves In order to maintain a slight pressure or vacuum inside a fixed-roof tank, breather valves (pressure-vacuum valves) are commonly installed on top. A breather valve must be installed correctly so as to prevent tank explosions due to overpressure or collapse due to vacuum conditions. A breathing valve consists of an inhalation valve and an exhalation valve. It is possible to arrange them side by side or overlapped. In the first case, a breather valve may be used as a relief valve. Imagine that an oil pump is feeding oil into a storage tank. As a result of continuous pumping into the tank, the tank becomes pressurized, requiring air flow to breathe. During this period, the tank may explode or rupture if the vent connection is too small or closed. When the pressure exceeds the set pressure of the breather valve during this time period, the valve will open and release the pressure. If, however, a pump is used to transport crude oil from a storage tank to its final destination, the internal pressure within the tank will decrease as the tank becomes empty. During the continuous pump emptying process, the tank is required to breathe air. In the event that the vent is not large enough or is closed, the tank may implode. In this situation, a breather valve will be opened in order to allow air to

Storage Tanks

257

enter the tank in order to relieve the vacuum. There are several types of breather valves, including pressure-only, vacuum-only, and pressure/vacuum combined valves. Under excessive pressure or vacuum, it prevents the storage tank from rupturing or imploding. Storage tanks are equipped with pressure-only breather valves on the roof to handle excessive pressure conditions. When the pressure increases, it will open and maintain the regular pressure regardless of whether it is a spring-operated valve or a weight-operated valve. There is also a vacuum-only breather valve mounted on the roof of the storage tank. As a result of breathing in air when a vacuum is generated, the valve opens and maintains a set pressure. A combined pressure/vacuum breather valve, as its name implies, combines both mechanisms into one unit for ease of use. Breather valves have several advantages, including reducing emissions from the tank, preventing fires in storage tanks, protecting storage tanks from explosions and explosions, ensuring the safety of pumping operations, and reducing maintenance and operational costs. Manufacturers of breather valves and tank pressure regulators can, for example, guarantee a 15% reduction in emission loss from tanks when these devices are used. A breather valve is also important for preventing evaporation loss from storage tanks. Breathers are required in addition to pressure safety valves (emergency vents) and emergency pressure vacuum relief valves, which are typically mounted on the roof of storage tanks. In order to prevent the fugitive emission of gases inside a tank, breathing valves with both pressure and vacuum relief functions can regulate the pressure inside the tank between normal low- and high-pressure ranges. Nevertheless, if the temperature and pressure inside the tank exceed the high-pressure point, the breather valve will not be able to control the overpressure, and the pressure safety valve will be forced to release it into the atmosphere. Additionally, if the vacuum condition exceeds a level that can be controlled by the breather valve, the emergency vacuum vent must act accordingly to prevent an implosion of the storage tank. 7.3.5.3 Manholes They are commonly referred to as manways, manholes, handholes, access ports, or hatches, but their function remains the same. Obtaining access to the interior of a storage tank requires the use of a manhole or manway. One manhole can be installed at the bottom of a small storage tank, whereas tanks with a diameter of medium to large should have multiple manholes. Additionally, a manhole should be provided on the roof of the tank so that the inside of the tank can be accessed. In Figure 7.11, a worker is seen entering a manhole at the bottom of the tank in order to perform cleaning, inspection, or maintenance. 7.3.5.4 Access Hatches Inspection and maintenance of a tank as well as gauging liquid levels require access to its interior. In addition to the manways located within the tank shell, there is a large cleanout fitting located flush with the tank floor, which provides access to the tank’s interior. There are hatches for manual or automatic measurement of tank levels on both fixed roofs and floating roofs.

258

Equipment and Components in the Oil and Gas Industry

FIGURE 7.11  A worker enters a manhole at the bottom of a storage tank. (Courtesy: Shutterstock)

7.3.5.5 Vents Consider a tank that is completely vapor tight and where liquid is being pumped into and out of the tank. When the tank is filled, the liquid level increases and the vapor space decreases (vapors are compressed), resulting in an increase in the pressure in the vapor space. As an alternative, if liquid is withdrawn from the tank, the vapor space increases (vapors expand) and the pressure in the vapor space decreases. Suppose that the tank is once again completely vapor tight, that no liquid is being transferred (the liquid level does not change), but that the liquid in the tank is being heated or cooled. As a result of the addition of heat, vapors are generated and evolve into the closed vapor space. As a result, the pressure in the vapor space increases. By cooling the liquid, the vapors contract and the pressure in the vapor space decreases. A number of hazards are associated with the storage of flammable liquids in fixed-roof tanks, as shown in the scenarios outlined previously. During normal tank operation, changes in the liquid level result from filling and emptying the tank on a regular basis. Variations in the ambient atmospheric temperature affect the temperature of the vapors and liquids in the tank (e.g. higher temperatures during the day; cooler temperatures at night). Venting is defined as the act of releasing the volume of vapors that have been generated (pressure relief), or inhaling the volume of make-up air that has been required (vacuum relief), during such activities. Vent connections in fixed-roof atmospheric storage tanks prevent both excessive pressure and a vacuum condition within the tank during emptying and filling operations, as well as during fire

Storage Tanks

259

emergencies. The safety valves installed in pressurized storage tanks are designed to ensure that the internal pressure of the tank does not exceed its design parameters. Vents are not only used in fixed storage tanks but also in floating-roof tanks. 7.3.5.6 Drains Most atmospheric storage tanks are equipped with an internal sump and drain for the purpose of draining water. During atmospheric breathing, water can enter a tank, and hydrocarbons can be present as either free or dissolved water. It is important to note that when crude oil is decanted into tanks, the water contained in the hydrocarbon is forced to the bottom of the tank due to its density. If the water that has entered the tank is not periodically removed, it will accumulate until it is drawn out along with the hydrocarbon. Water accumulation can cause a product to fail to meet specifications or disrupt downstream processes. Further, the presence of water in the bottom of a tank increases bottom corrosion, promotes biological growth, and can significantly increase the number of bacteria that reduce sulfates. The bottom of the tank may be severely pitted (corroded) as a result of this condition. It is possible to consider the bottom of a storage tank an appropriate location for drain connections. Another type of drainage is associated with external floating-roof storage tanks. Rainwater is collected on the roofs of external floating-roof tanks by drains, which prevent excessive rain from accumulating and damaging the roof. Similarly, flexible hoses can be attached to the roof of the tank so that water can be transported from the roof to the bottom, where a drain valve allows the water to be drained. If the hose is connected to the roof of the storage tank, a check valve may be installed that opens when there is water pressure from rainfall and closes when no water pressure is present. It is possible to install one, two, or more hoses to drain water from the roof depending on the size of the floating tank and the amount of rainfall. As illustrated in Figure 7.12, a swivel pipe joint may be used instead of a flexible hose drain for draining the roof of a floating-roof storage tank. 7.3.5.7 Seals An important function of a storage tank seal is to seal off any vapors or substances contained within the tank. A  floating-roof tank’s seal can become damaged or worn down over time due to a variety of factors, resulting in vapors and substances escaping. The seal’s design and fit are of utmost importance. Both external and internal floating-roof tanks are equipped with seals located between the outside diameter of the roof and the inside diameter of the tank. In between the roof and shell, there is a gap that is sealed by these seals. Whenever the gap is closed in this manner, hydrocarbon emissions are minimized and the roof can be moved vertically as the level of liquid stored changes. As a seal between the roof and tank shell, metal plates or flexible membranes are commonly used. Most often, the seal consists of a relatively thin shoe or ring that is supported against the roof edge. An alternative type of seal consists of a flexible tube that occupies the annular space between the roof and the shell. Metal plate-type seals require the use of a counterweight system in order to force a metal plate against the tank wall.

260

Equipment and Components in the Oil and Gas Industry

FIGURE 7.12  A swivel pipe is provided for draining the external floating-roof storage tanks.

As opposed to those discussed previously, the accessories that will be discussed from now on do not contribute to fugitive emissions. 7.3.5.8 Mixers To ensure smooth and continuous production, refineries rely heavily on crude oil and product storage tanks. The crude oil is generally received by pipeline from ships and stored in large storage tanks for further processing. There are many storage tanks that utilize side entry mixers in order to prevent sludge from settling or layering within them. The use of these mixers results in homogenization of crudes based on basic sediment and water composition (BS&W) and density. For certain impurities in crude oil, basic sediment and water is both a technical specification and a measurement method. Water and suspended solids from the reservoir formation are expected to be present in crude oil extracted from an oil reservoir. BS&W should be as low as possible. BS&W levels of less than 1% are considered acceptable. In storage tanks, mixing products is done to prevent sludge deposition, maintain bottom sediment and water in suspension, and prevent bottom sediment and water from accumulating at the bottom. There are a variety of ways in which mixers can be installed within storage tanks. There are a variety of mixer configurations based on the number of mixers, which can range from one to seven, and the swivel angle of the mixer. It is necessary to adjust the swivel angles of mixers in tanks in accordance with the desired results. A mechanical agitator with a propeller is the most common type of mixer. An axial flow propeller agitator or stirrer works at high speed and is used for liquids of low viscosity. Starting

Storage Tanks

261

from the agitator, flow streams move through the liquid until they are deflected by the bottom or walls. 7.3.5.9 Heaters When a product must be maintained or heated to a final temperature before a batch process can take place, tank heaters provide the perfect solution for directly heating the fluid in a storage or terminal tank. Electricity is converted into heat through resistive coils or heating elements that radiate heat into the tank. As a matter of fact, heating coils or heaters are used to increase the flow rate of products with a high pour point (i.e. viscous products at ambient temperatures). The heaters provide a warming effect to the product, making it easier for it to flow and for the tank to be emptied. Heating coils or heaters in other tanks can sometimes prevent the solidification of sludge. 7.3.5.10 Platforms, Ladders, and Stairways Occupational Safety and Health Administration (OSHA) regulations require ladders, stairs, platforms, and walkways for storage tanks to comply with their strict requirements. Each tank is equipped with a platform that can be accessed at the top. A platform is required to reach the roof and gauge well. In large-diameter tanks, spiral staircases are typically used, while vertical ladders are used in small-diameter tanks. A large storage tank for oil is illustrated in Figure 7.13 with platforms on top and spiral staircases. Besides providing a safe passageway into the inner tank, each access platform/walkway also provides structural support for functions such as manual dip readings and tank access. 7.3.5.11 Gauging Devices The purpose of tank gauging is to quantify the volume and mass of liquids in large storage tanks. Most oil and gas companies use static volumetric assessments to assess the contents of their tanks. Level, temperature, and pressure measurements are involved in this process. It is possible for storage tanks to contain large volumes of liquid product with a significant value. When assessing the tank content at any given time, the accuracy of the tank gauging system is extremely important. Every tank must be equipped with at least one level-gauging device that can be read from grade. A float-type automatic tank level gauge is the most common type of automatic tank level gauge. In the case of non-pressurized storage tanks/vessels, float-type level gauges are used to determine the liquid level by weighing. The device is composed of a balanced counterweight system with an arrow-shaped pointer that facilitates the process of indication. 7.3.5.12 Safety Systems Oil, petrochemicals, and gaseous materials are stored in storage tanks in the industrial sector. There are a number of hazards associated with storage tanks. The storage facilities provided by different units and plants include crude oil import terminals, refineries, petrochemical plants, and chemical storage depots. In most cases, storage tanks are used for the storage of flammable, combustible,

262

Equipment and Components in the Oil and Gas Industry

FIGURE 7.13  Oil and petrol tanks that are large, white, and have platforms at the top as well as spiral staircases. (Courtesy: Shutterstock)

and explosive substances, such as oil and liquefied natural gas (LNG), which require high levels of safety precautions. The presence of flammable liquids and chemicals in the workplace is a necessary but potentially dangerous reality for many businesses. In addition, storage tanks may be used to store hazardous substances, such as corrosive, cryogenic, or toxic substances. The term hazardous materials, or chemicals, refers to substances that may pose a threat to humans, animals, or the environment if they are exposed to them. As a result of chemical storage, there are many hazards that may arise, including health issues, fires, explosions, and the release of toxic substances. One of the most challenging scenarios that firefighters and emergency services face is putting out fires in oil and gas tank farms. In the following paragraphs, we provide a more detailed explanation of all fire safety measures. 7.3.5.12.1 Fire and Gas Detection Systems The appropriate organizational measures should be taken in the event of a fire in a tank farm or near its perimeter to prevent and/or reduce the effects of the fire and/or explosion. It is particularly important to use appropriate sensors in order to detect fires at an early stage. Fire and gas leak detection systems are instrumented systems designed to detect fires and/or leaks of gas. Sensors, logic solvers, and final control elements are components of a fire and gas system (FGS). The

Storage Tanks

263

FIGURE 7.14  Fire detection and monitoring and detection system. (Courtesy: Shutterstock)

FGS system can be equipped with a variety of sensors, including smoke detectors, flame detectors, and temperature detectors. When a fire detection system is activated, alarms are triggered, and automatic responses are initiated, such as isolating electrical supplies and connections. It is common for many systems to employ multiple sensors or detectors in order to improve safety and reliability, particularly when one of the detectors does not perform as expected. Many factors must be considered when designing FGS, including safety, suitability, reliability, cost, and simplicity. According to Figure 7.14, a process plant is equipped with a system for monitoring and detecting fires and gas emissions. An effective fire detection system should detect fires early enough to permit reliable action to be taken to minimize the risk of injury to personnel and damage to the facility. As gas detection plays a more preventive role than fire detection, it is advisable to prioritize gas detection over fire detection. The FGS should communicate a potential hazard to the user and take appropriate measures to minimize the risk of an escalation. 7.3.5.12.2 Firefighting Systems Firefighting is the process of putting out a fire. In the event of a fire, all facilities, including storage tanks, should be equipped with firefighting equipment. According to National Fire Protection Association (NFPA) standards, tank fire protection guidelines are established in the United States. Storage tank firefighting systems consist of the following components, equipment, and systems.

264

Equipment and Components in the Oil and Gas Industry

7.3.5.12.3 Sprinklers A sprinkler system sprays water forcefully over the flames in order to extinguish them completely or, at the very least, control them until the fire department arrives to extinguish the flames. When a fire occurs, only the sprinklers closest to the fire will be activated. Sprinklers are sometimes activated by smoke as well as by heat, but that is not always the case. A sprinkler system is simple, cost effective, and effective. The sprinkler on the left sprays high-pressure water into the spherical tank to extinguish the fire, as shown in Figure 7.15. 7.3.5.12.4 Deluge Systems There is another type of sprinkler system known as a deluge sprinkler system in which all sprinklers are opened simultaneously. In this case, the open sprinklers will distribute water throughout the entire area of the storage tank that is on fire. A deluge valve activates upon receiving a signal from a fire alarm or detector, which forces atmospheric pressure into the sprinkler pipe, allowing water to flow from the water supply pipe into the sprinkler pipe and finally into the open sprinklers. Where rapid fire spread is a concern, the use of deluge systems is recommended. By simultaneously releasing water from each of its sprinkler heads, a deluge system is able to respond to a fire more quickly. The open sprinklers in a deluge system do not have glass bulbs on their nozzle heads and are therefore capable of discharging water much more rapidly than closedhead sprinklers. Figure 7.16 shows open-head sprinklers installed as part of a deluge system near a storage tank. Deluge systems are sometimes referred to as water spray systems.

FIGURE 7.15  A sprinkler sprays high-pressure water into the spherical tank in order to extinguish the fire. (Courtesy: Shutterstock)

Storage Tanks

265

FIGURE 7.16  A deluge system. (Courtesy: Shutterstock)

7.3.5.12.5 Hydrants and Hoses Fire hydrants are essentially pipes that are controlled by valves for the purpose of extinguishing fires with water. Fire hydrants are typically installed in tank farms. Fire hoses are high-pressure hoses designed to carry water or fire retardants (such as foam) to extinguish fires. It is attached to a fire hydrant on the exterior. In Figure  7.17, the fire hydrant is located adjacent to a storage tank within a tank farm. 7.3.5.12.6 Fire Extinguishers Small fires can be extinguished or suppressed with the use of fire extinguishers in an emergency situation. A fire that has become out of control will not be extinguished with fire extinguishers. The typical fire extinguisher consists of a hand-held cylindrical pressure vessel filled with an agent that can be discharged to extinguish the fire. A fire extinguisher’s ability to extinguish a fire is directly related to the amount and type of agent it contains. There are five types of fire extinguishers: water extinguishers, carbon dioxide extinguishers, dry powder or chemical extinguishers, foam extinguishers, and wet chemical extinguishers. It is possible to extinguish oil and fuel fires in storage tanks with all types of extinguishers except those containing water. Figure 7.18 illustrates a fire extinguisher and its components.

266

Equipment and Components in the Oil and Gas Industry

FIGURE 7.17  A fire hydrant located in a tank farm. (Courtesy: Shutterstock)

FIGURE 7.18  A fire extinguisher and its components.

Storage Tanks

267

7.3.5.12.7 Cooling Water Water spray cooling nozzles have many applications in the chemical industry, as well as in storage and processing facilities for flammable liquids, liquefied petroleum gas (LPG), and liquefied natural gas. The purpose of water spray nozzles is to remove radiant heat from an adjacent fire in order to cool tanks or equipment that contain hazardous fuels. Water is the most effective cooling agent. It is typical for industrial plants to have an abundance of clean, well-maintained water supplies. Spray nozzles of high quality ensure that water is sprayed accurately and at an optimum rate. In addition, it is imperative that storage tanks be water cooled as soon as possible after a fire has erupted. 7.3.5.12.8 Foam Firefighting foam is included in tank fire protection systems. A foam fire extinguisher excludes air (blanketing), and its cooling properties prevent or inhibit the fire’s flammability. Foam is generally used for the extinguishing of highly flammable substances, including oils, fats, and liquids. A foam used for fire protection is typically made up of air-filled bubbles formed from aqueous solution and has a lower density than the lightest liquids that are flammable. Generally, foam systems consist of a sufficient supply of water, a supply of foam concentrate, suitable proportioning equipment, a proper piping system, foam makers, and discharge devices. Some systems may include detection devices. Typically, foam makers are used to generate low-expansion foams as the first component of a foam system. Alternatively, generators are used to produce foams with a high expansion rate. The foam concentration must be adjusted based on the contents of the tank and the application system. One of the most important components of the tank protection system is the foam induction proportioning system. The right amount of foam and water is essential to a successful foam mix. In order to determine how much foam solution should be applied, the foam delivery device must be used. When constant foam solution demands are encountered, it is recommended that fixed inline inductors be used. Other suitable systems must be considered when the demand for foam solutions is variable. Foams are classified on the basis of their expansion ratio (expansion), which refers to the ratio of the volume of the foam to the volume of the solution it is made from, as follows: low, medium, and high. Generally, low-expansion foams, with expansion rates between 1 and 20, are intended for use on the surface of flammable liquid fires. In general, foams with medium expansion, between 21 and 200, are intended for surface applications or for use on fires that require a certain depth of foam coverage, up to 4 meters. High-expansion foams, which have expansions between 201 and 1000, are designed for the filling of enclosures where several fires are burning at different levels up to 10 meters in height. 7.3.5.12.9 Rim Seal Fire Protection Systems There are “pontoons” on floating-roof tanks that create a seal against the tank’s wall and work together with the rim seal in order to reduce evaporation and prevent dangerous gas buildup. Actually, the sealing is located between the pontoon

268

Equipment and Components in the Oil and Gas Industry

and the shell of the tank and is pressed against it. Fires caused by rim seals are common in tanks with floating roofs. They can be quickly extinguished by stationary extinguishing systems if they are detected in time. It is possible, however, for a fire to damage the seal and cause an oil spill if it persists for a prolonged period of time. This situation may result in an extensive fire. A  floating roof may also sink as a result of this damage or excessive use of water, resulting in a full-surface fire. It is important to note that floating-roof tanks are only protected from fires on their rims. Rim seal systems can sometimes be difficult to detect, especially when the floating roof is at its lowest point. In order to reduce the severity of losses, it is imperative to detect them early. Floating-roof tanks are equipped with rim seal fire protection systems designed to detect and extinguish fires in the rim seal area as soon as they occur. Moreover, strategically placed fixed monitors are advantageous as a complement to rim seals. Foam packages with linear fire detection tubes integrated into them would be an example of a rim seal fire suppression system. With its low expansion directional nozzles, the unit is designed to deliver foam directly to the rim seal zone for rapid suppression and release. Fire/radiating heat from fire will cause the pressurized fire detection tube to rupture at specific temperatures throughout its length when impinging by flame. As a result, the pressure is released, the suppressant is released from the connected valve, and any pressure-operated signaling device attached to this system is activated. The use of a heat detector can be substituted for the use of a fire detection tube. A nitrogen-pressurized unit is mounted above the floating roof. If a fire breaks out in the rim seal zone, the tubes melt and the actuator detects a pressure drop, releasing the extinguishing agent immediately. The low expansion nozzles discharge the foam into the fire zone after the foam solution has been directed into the distribution circuit. The purpose of fire suppression systems is to extinguish fires within a short period of time, usually between 30 and 40 seconds, in order to prevent the spread of fire. 7.3.5.12.10 Fire Alarms It is essential for the safety of all tank farms to have a means of transmitting alarms quickly to the plant fire brigade or public fire brigade, at least through organizational/manual means (manual alarm button, telephone). Several devices are used in the fire alarm system to provide warning when smoke, fire, carbon monoxide, or other emergencies are present. In order to alert operators to equipment malfunctions, deviations from process specifications, or abnormal conditions that require attention, alarm systems provide an audible and/or visual signal. By monitoring changes in the environment associated with combustion, fire alarm systems can detect the occurrence of fires. Fire alarm systems can be classified according to whether they are automatically activated, manually activated, or both. Oil and gas storage tanks must have fire alarms, as do all process facilities. According to NFPA 72, there are a number of aspects of fire alarm systems that are covered, including their application, installation, location, performance, inspection, testing, and maintenance. In order to ensure compliance with

Storage Tanks

269

FIGURE 7.19  Fire alarm control system. (Courtesy: Shutterstock)

NFPA or other relevant fire standards, fire alarms should be regularly inspected. Ultimately, the effectiveness and reliability of a fire alarm system are determined by its selection of detection devices, their sensitivity, and their placement, as well as the materials and methods used in its installation. Besides providing safety to the building’s occupants, fire alarm systems also provide early warning of fires; reduce damage to facilities, including tanks, buildings, and plants; and minimize human and economic losses. Fire alarm control panels or fire alarm control systems serve as the system’s brain. The control panel provides status indications to users in addition to serving as the central hub for all detectors. Various types of detectors are connected to it, such as fire and gas detectors. The control panel unit (see Figure 7.19) is also designed to simulate an alarm. A control panel is a device that receives signals from initiating devices, such as detectors or manual call points, and processes these signals to determine the output functions of the system, such as the activation of fire alarms. Call points for fire alarms and break glass alarms (see Figure 7.20) provide personnel with the capability of manually raising the alarm. A fire alarm consists of a small box mounted on the wall containing a button or lever that can be operated manually. 7.3.5.12.11 Emergency Exits and Evacuation During an emergency, an emergency exit route should be continuous and unobstructed from any point within the place of employment to a place of safety.

270

Equipment and Components in the Oil and Gas Industry

FIGURE 7.20  Fire alarm call point. (Courtesy: Shutterstock)

Generally, an emergency exit is a part of an exit route that is separated from other areas in order to provide a safe discharge route. Workplaces must have permanent exit routes. When preparing a plan for an emergency exit, the route should not go through hazardous areas. It is also important to keep exit doors clear of decorations or signs that obscure their visibility. If the direction of travel to the nearest exit or exit discharge is not immediately apparent, signs should be posted along the exit access. The EXIT signs must also have readable letters. It is imperative that the emergency escape system at work or in the plant remain in good working order in order to ensure effective evacuation in the event of a fire. 7.3.5.12.12 Bund/Dike Protection When a tank overflows or fails structurally, dikes are used to prevent the contents from spreading. Additionally, dikes are used to classify the contents of tanks and separate them according to their classification. Dikes may be constructed from a variety of materials, including compacted dirt (earthen dikes) and concrete. The volume of the tanks enclosed within a dike determines its height and radius. To provide a margin of safety, dikes are typically designed to contain the total contents of a tank plus a certain percentage above it. It is common for bund (dike) walls (see Figure 7.21) to be overlooked, as tanks occupy the majority of the attention. There will, however, be no fewer casualties if the bund walls are damaged. There may be leaking valves, ruptured pipes, or ruptured tanks in the tank farm area that can cause a fire. There is also the possibility that these factors may result

Storage Tanks

271

FIGURE 7.21  During construction, the walls of a dike or bund surround a storage tank. (Courtesy: Shutterstock)

in serious accidents. Medium-expansion foam protects walls from fire and vapor damage. 7.3.5.12.13 Grounding Systems It is common for storage tanks to be located outside in areas subject to extreme weather conditions, such as lightning, hail, and storms. In addition to lightning, other factors (such as unintentional contact with high voltage lines) can accumulate static or electrical energy within the tank, which can lead to a fire or fatal accident. Grounding is an effective method of preventing such damage. As a result of grounding or earthing, static charges are drained away, preventing sparks from forming. The grounding of a substance allows electricity to flow to the ground. When tanks contain products that may generate hazardous atmospheres at any time, grounding is essential. Grounding non-inflammable tanks located in hazardous areas and containing non-flammable materials is also necessary.

7.4 FIRE WATER STORAGE TANKS Water storage is essential in the event of an emergency, such as a fire. Water from the municipal supply may not be sufficient for fire suppression in some cases, so firefighting water storage tanks are crucial for the safety and protection of structures. A fire sprinkler system and other firefighting measures will use this water to combat the fire. These tanks are intended to store a sufficient amount of water. It is important to note that, although tanks can be used for a variety of purposes, they are most commonly used in situations where there is a lack of reliable and adequate water supplies. As illustrated in Figure 7.22, a storage tank provides fire water through red-colored piping and valves located in front of the tank. There

272

Equipment and Components in the Oil and Gas Industry

FIGURE 7.22  Fire water storage tanks and fire protection piping and valves. (Courtesy: Shutterstock)

are two types of water storage tanks: aboveground and belowground. A mild steel storage tank with an open top is generally installed at grade level in accordance with the NFPA22 standard for fire water tanks. The only materials permitted are steel, wood, concrete, and coated fabric. In order to prevent internal corrosion, especially in the case of seawater, the tank will need to be lined. The level should be checked at the beginning and end of each shift using a float.  A number of requirements are outlined in NFPA22 for water tanks used in firefighting. Fire tanks and accessories are designed, constructed, installed, and maintained in accordance with NFPA22 standard for private fire protection. A fire water supply is provided by storage tanks and transported through pipes and fittings that are typically red in color to indicate that they are used to transport fire water to the fire site.

QUESTIONS AND ANSWERS

1. In the oil and natural gas industries, which of the following statements is true regarding the storage of hydrocarbon products? A. Petroleum tanks should only be installed above ground. B. The only substance that can be stored in storage tanks is gas. C. The most common shape of storage tanks in the oil and gas industry is the vertical cylinder.

Storage Tanks

273



D. Following their production and prior to their transportation to the end user, hydrocarbon products are generally not required to be stored.



Answer) Option C is correct. It is possible for petroleum tanks to be aboveground or underground, so option A is not appropriate. It is important to note that storage tanks are not limited to storing gases and they are also capable of storing liquids. Therefore, choice B is incorrect. Option D is incorrect since it is often necessary to store hydrocarbon products after their production and before they are transported.



2. For storage tanks, what is the most commonly used and constructed type of foundation? A. Earth foundation B. Earth foundation with crushed stone or gravel ringwall C. Earth foundation with a concrete ringwall D. Reinforced concrete slab foundation





Answer) Option C is correct. 3. Determine the correct statement regarding the components of the storage tank. A. In storage tanks, the use of heaters results in the homogenization of crude based on the sediment and water composition and density of the crude oil. B. The use of drains is only applicable to floating-roof storage tanks. C. There is always one function of the breather valve, which is to prevent vacuum in the tanks. D. The purpose of heating coils or heaters in storage tanks is to increase the flow rate of products with a high pour point (i.e. viscous products at ambient temperatures). Answer) There is an error in option A, as mixers are used in the storage tanks in order to homogenize the crude oil based on sediment, water, and density. Option B is incorrect because drains are used for both fixed-roof storage tanks and floating storage tanks. In addition, option C is incorrect, as it is possible to have a breather valve with a double function, which is to prevent overpressure in the tank as well as to ensure that there is no vacuum in the tank. The correct answer is option D.

4. Which standard or regulation specifies the requirements for ladders, stairs and platforms for storage tanks? A. Occupational Safety and Health Administration (OSHA) B. American Society of Mechanical Engineers (ASME) C. American National Standards Institute (ANSI) D. American Petroleum Institute (API)

Answer) Option A is correct.

274

Equipment and Components in the Oil and Gas Industry



5. What component or accessory can reduce evaporation losses and fugitive emissions in a storage tank? A. Manhole B. Breather valve C. Gauge hatch D. Sample point

Answer) Option B is the correct answer. By opening the tank for the purpose of entering, measuring, and sampling, some production may be lost. As a result, evaporation loss can occur when the manhole is opened to enter the tank, the gauge hatch is used for measurements, and the sample point is used to obtain samples from the tank. A breather valve can, however, be installed at the top of the tanks in order to control the pressure inside. Therefore, there are fewer instances of emergency overpressure scenarios resulting in production loss due to a safety valve or vent. As long as this valve is in place, vapors will not be released from a fixed-roof tank even if temperature, barometric pressure, or liquid level are only slightly changed.



6. Considering both normal operation and emergency use, why is it beneficial to have vents on top of tanks? A. Ensuring the safety of the storage tank during normal operation and in case of emergency overpressure situations, which may result in a fire B. Maintaining compliance with legal and environmental requirements and regulations C. Preventing the loss of stored products D. The three choices are all correct



Answer) Option D is the correct answer.



7. An internal floating storage tank has been selected by the end user. In the course of operation, fugitive emissions are a major concern of the end user. What component’s design is most important for preventing fugitive emissions during operation? A. Sealing B. Manhole C. Support legs D. Tank foundation

Answer) The correct answer is A. It is not common practice to use the manhole during operation, although it may result in emissions from the tank. As they are primarily used to facilitate the movement of the roof, the support legs do not contribute to the production of fugitive emissions. In addition, option D is incorrect with regard to the tank foundation.

Storage Tanks

275

8. Regarding rim seal fire protection systems, what is the correct statement? A. An open-top storage tank or a tank with a fixed roof may be protected by a fire protection system of this type. B. Rim seal fire protection systems use water as a fluid for extinguishing fires. C. Fire detection is only possible with tube detectors for rim seal fire protection systems. D. It is expected that rim seal fire protection systems can be operated very quickly in less than a minute.

Answer) Considering that floating-roof storage tanks are equipped with rim seals and fire protection systems, Option A is not an appropriate option. Moreover, option B is incorrect due to the fact that foam is typically used to extinguish fires in rim seal fire protection systems. It is incorrect to choose option C because tube detectors are not the only method of detecting heat and fire in this system. As an alternative, heat detectors may also be used. Option D is the correct answer.

9. As a result of a vacuum condition inside the tank, a storage tank collapsed during drainage. What type of accessory malfunctioned to cause the failure of the tank in the image? A. Breather valve B. Pressure safety valve C. Vents D. Level gauge

Answer) A vacuum condition in the tank causes the storage tank to collapse or implode during drainage. A malfunction of the breather valve is primarily responsible for the problem, since the breather valve is responsible for maintaining the pressure inside the valve while draining the storage tank. It is therefore appropriate to choose option A. PSVs and vents are necessary in order to prevent overpressure scenarios in a storage tank. Since the storage tank is underpressurized, this is not the case here. The selection of either option B or C is therefore incorrect. Additionally, option D, a level gauge, is not suitable.

10. Which storage tank accessory is necessary based on the strict requirements of the Occupational Safety and Health Administration? A. Breather valve B. Safety valve C. Ladders, stairs, platforms, and walkways D. Hatches

Answer) Option C is the correct answer.

276

Equipment and Components in the Oil and Gas Industry

FURTHER READING

1. Bryan, A., Smith, E., & Mitchel, K. (2013). Fire and gas systems engineering handbook. Columbus, OH, USA: Kenexis Consulting Cooperation. 2. Brumbi, D. (1995, May). Measuring process and storage tank level with radar technology. In Proceedings international radar conference (pp. 256–260). Alexandria, VA: IEEE. 3. Chakrabarty, A., Mannan, S., & Cagin, T. (2016). Multiscale modeling for process safety applications. 1st ed. Oxford: Butterworth-Heinemann. ISBN: 978-012-396975-0 4. Emerson. (2021). The engineer’s guide to tank gauging. [online] available at: www.emerson.com/documents/automation/-engineer-s-guide-to-tank-gauging-en-175314.pdf [access date: 13th January, 2023] 5. Iranian Petroleum Standard (IPS)-E-SF-140. (1993). Engineering standard for foam generating and proportioning systems. 1st ed. Tehran: IPS. 6. Iranian Petroleum Standard (IPS)-G-ME-100. (2004). General standard for atmospheric above ground welded steel tanks for oil storage. 1st ed. Tehran: IPS. 7. Ismail, K. A., Leal, J. F., & Zanardi, M. A. (1997). Models of liquid storage tanks. Energy, 22(8), 805–815. 8. Kletz, T. A. (1990). Critical aspects of safety and loss prevention. 1st ed. Oxford: Butterworth-Heinemann. ISBN: 978-0-408-04429-5 9. Loizou, K., Koutroulis, E., Zalikas, D., & Liontas, G. (2015, March). A low-cost capacitive sensor for water level monitoring in large-scale storage tanks. In 2015 IEEE international conference on industrial technology (ICIT) (pp. 1416–1421). Seville: IEEE. 10. Long, B., & Gardner, B. (2004). Guide to storage tanks and equipment. 1st ed. New York: Wiley. ISBN: 978-1-860-58431-2 11. National Association of Fire Protection (NFPA) 22. (2022). Standard for water tanks for private fire protection. Boston, MA: NFPA. 12. National Association of Fire Protection (NFPA) 72. (2013). National fire alarm and signalling code. Boston, MA: NFPA. 13. OSHA Academy. (2014). Offshore oil and gas safety. Beaverton, OR: OSHA Academy. 14. Saudi Aramco Desktop Standards. (2012). Storage tanks types and features. Mechanical Chapter. File Reference: MEX-203.01. 15. Shafiq, I., Shafique, S., Mudassir, M., Hamayun, M. H., & Hussain, M. (2022). Recommendations on firefighting system design, erection, and safe operation. Journal of Pipeline Systems Engineering and Practice, 13(1), 05021009. 16. Shelley, C. H. (2007). Storage tank fires, is your department prepared? Texas, USA: Fire Engineering University. 17. Sotoodeh, K. (2024). Storage tank selection, design, testing, inspection, and maintenance: Emission management and environmental protection. 1st ed. Texas, USA: Elsevier. ISBN: 9780443239090

Index A accelerator, 51 access hatch, 247, 257 accumulator, 31, 34, 50, 52, 63 additional mud pit, 34 adjustable choke, 54 after cooler, 140, 146 air cooler, 193 – 194, 196 – 199, 202 – 206 air cooler design, 194 American National Standards Institute (ANSI), 80, 273 American Petroleum Institute (API), 54, 57, 64, 80, 103, 273 American Society of Mechanical Engineers (ASME), 80, 103, 273 Boiler and Pressure Vessel Code (BPVC), 80 annular, 51 – 52, 57, 218, 247 annulus, 17 – 18, 33, 44 – 45, 57, 172 artificial lift, 62 asphalt base, 23 asphaltic compounds, 24

B baffle, 166 bearing, 147 blowout, 31, 34 blowout preventer, 31, 34 blowout preventer stack, 63 boiler, 181 – 192 boiler mounting, 188 boiler pressure, 184 – 185, 188 boiler selection, 188 bolt, 54, 167 bottom hole assembly (BHA), 47 break horsepower, 141 British Thermal Units (MMBTU), 22 bulk mud component storage tank, 34 bund protection, 270 burner, 183, 191

C carbon dioxide, 3, 19 – 22, 77, 183, 265 casing, 16 – 18, 26 – 27, 31, 55 – 56, 60 conductor casing, 55 intermediate casing, 55 – 56 production casing, 56

surface casing, 55 – 56 casing string, 60 catalyst, 23 cavitation, 119 – 121, 150 cellulose, 96 cementing, 55, 57 – 59 cement slurry, 17, 57 – 58 chemical processing, 23, 66, 85, 109 choke line, 50, 52 choke manifold, 53 – 55 choke valve, 53 – 54 Christmas tree, 60 – 62, 64 coalescer, 66 – 98 – 99 column, 81 – 92, 102, 115 batch, 88 continuous, 88 completion tubing, 17 composite, 96 compressibility, 125 – 141 compression efficiency, 141 compression ratio, 141 – 142 compressor parts, 146 balance drum, 147, 152 bearing, 147 casing, 147 connecting rod, 148 after cooler, 140, 146 coupling, 148 crank case, 148 crank shaft, 148 delivery valve, 149 impeller, 149 intake valve, 149 intercooling, 149 piston, 149 rotor, 149 shaft, 149 shaft seal, 149 suction filter, 149 suction valve, 149 compressor selection, 138 compressor terms, 140 compressor types, 138 axial, 128 centrifugal, 126 – 128, 138 – 139, 143, 145 dynamic, 125 – 126, 128 positive displacement, 125, 129, 135, 137, 139, 142 rotary screw, 129, 133 – 134

277

278 rotary vane, scroll, 129, 133, 137 – 138 controlling system, 29, 31 conversion, 23 – 24, 88 coring, 12 – 14 cracking, 23 crane, 15 crown block, 30 – 31

D degasser, 41 deluge system, 264 – 265 derrick, 30 – 31, 33 desander, 41 – 42 desilter, 41 – 42 diaphragm pump, 106 – 110 diesel fuel, 23, 30, 87 diffuser, 106, 125 – 126 distillation column, 81, 89 distillation column internals, 89 bubble cap tray, 89 – 90 packing, 92 – 94 plate, 89 sieve tray, 89 tray, 89 valve tray, 89 distillation process, 81 – 89 distillation tower, 84 dog house, 33 double-pipe heat exchanger, 172 – 173 drawwork, 30, 34 – 35 drill bit, 13 – 14, 31 fixed cutter bit, 47 rolling cutter bit, 45 – 46 drill collar, 46 – 48 drilling hook, 36 drilling line, 30 – 31, 35 drilling mud, 34, 40, 44, 55 drilling rig, 15 – 16, 29 – 41 drill pipe, 47 – 52 drill stem, 35,37 drill string, 14, 29, 31, 33, 41, 44 drive bushing, 37

E economizer, 183, 190 – 191 electrical control house, 34 electrical log, 12 electric cable tray, 34 electromagnetic survey, 9 elevator, 35 – 36 emergency exist, 269 – 270 emulsion, 67 – 68, 71 – 73, 76

Index energy sector, 1, 25 engine generator, 34 exploration, 4, 7, 11 exploration drilling, 11 exploration techniques, 7 electromagnetic survey, 9 gravity survey, 8 magnetic survey, 8 seismic survey, 9 exploratory well, 11 – 12 extended surface heat exchanger, 163 extender, 57 extra or reserve pit, 34

F fiberglass, 96 filter, 96 coalescer, 98 – 99 duplex, 97 multibag, 101 simplex, 96 single bag, 100 vacuum dehydrator, 101 filtration media, 95 fire alarm, 268 – 270 fire and gas detection system (FGS), 262 fire extinguisher, 265 firefighting system, 267 fire water storage tank, 271 – 272 floater, 15 Floating Production Storage and Offloading (FPSO), 25 flowline, 42 flue gas, 183, 191 fluid loss additive, 58 foam, 68, 77 fossil fuels, 2 foundations, 248 fractional distillation, 81 – 85 fractions, 23 – 24 fracturing, 17 fuel oils, 23 fuel tank, 34 furnace, 86 – 87

G gas dehydration, 67, 95 gas lifting, 27 gas–oil interface, 68 gasoline (petrol), 23 gas sweetening, 19 gas treatment, 19, 71

279

Index gas turbine, 211, 217 – 218, 221 gas turbine performance, 218 gas turbine types, 221 gauging device, 262 geology, 4 – 5 geophysical logs, 12 governor, 232 – 233 grate, 184 gravel packing, 16 gravitational force, 69, 74, 78 gravity survey, 8

L

H

M

heater, 261 heat exchanger, 155 – 163 heat exchanger type, 210 extended surface, 176 plate, 176 regenerator, 176 tubular, 176 heating oil, 3, 23 heat transfer mechanism, 157 heat transfer process, 169 direct, 169 indirect, 169 helipad, 15 heliport, 15 hoisting system, 29 – 30 hoist line, 31 hook, 35 – 36 hose, 44 hydrant, 265 hydrate, 19, 27, 75 hydraulic fluid, 34, 50 hydrocarbon industry, 15 hydrocarbon molecules, 23 hydrocarbon storage, 21 hydrocarbon transportation, 22 hydrocyclone, 41 hydrogen sulfide, 20

magnetic survey, 8 – 9 maintenance, 53, 89 – 90 manhole, 255 mast, 30 – 32 master valve, 61 mercaptans, 20 migration, 5 – 6, 25 mixer, 255, 260 monitoring system, 29, 31, 63 monkeyboard, 31 mousehole, 41 mud cleaner, 41 mud gas separator, 34, 41, 43 mud pit, 34 mud pump, 29, 34, 44 mud return line, 42

laboratory distillation, 82 ladder, 255, 261 links, 35 – 36 liquefied natural gas (LNG), 22, 262 liquefied natural gas (LNG) tankers, 22 liquefied petroleum gas (LPG), 24, 75, 267 liquid accumulation section, 74, 78 living quarters, 15 lubrication system, 95, 148, 229

N natural gas, 61 – 62 net positive suction head (NPSH), 120 nitrogen, 3, 24, 34, 184 nut, 54, 167

O

ideal gas, 125 impeller, 122, 126 intercooling, 126

Occupational Safety and Health Administration (OSHA), 261, 273 oil and gas metering, 22 oil industry, 1, 57, 66 oil refinery, 23 oil well, 57 oxygen, 3, 24

K

P

kelly, 31, 35 kelly bushing, 37 kelly hose, 44 kerosene, 3, 23, 87 kill line, 50, 52

packer, 17 – 18, 27, 59 – 60 packing, 92 – 94 perforating, 16 – 17, 58 petroleum geology, 4 – 5 petroleum naphtha, 23

I

280 petroleum refinery, 23 pipeline, 22 – 23 pipe rack, 34 pipe ramp, 34 piping, 19, 23 plate-fin heat exchanger, 177 plate heat exchanger, 174, 176, 207 platform, 15 – 16 Portland cement, 57 – 58 positive choke, 54 power system, 29 – 30 pressure drop, 53, 55, 90, 121 pressure vessel, 66, 78 – 81 primary separation section, 78 prime mover, 211 processing, 66 – 67 produced water, 76, 95 pump, 105 – 124 centrifugal, 106 – 107 dynamic, 106 gear pump, 113 – 115 positive displacement, 106, 108 – 112 reciprocating, 108 – 110 rotary, 109 – 111 rotary lobe, 114 screw, 110 – 112 special effect, 106 – 107 pump capacity, 117 pump efficiency, 115, 117 pumping characteristic, 115 discharge head, 116 friction loss, 115 – 116 head loss, 115 – 116 total head, 116 – 117 pumping head, 115 pump part, 121 bearing, 124 casing, 122 check valve, 124 coupling, 124 discharge nozzle, 122 impeller, 122 sealing, 123 shaft, 122 suction nozzle, 122 pump performance curve, 119 – 120 pump power, 115, 117 pump specific speed, 118 – 119

R ram, 51 ram preventor, 51 Rate of Penetration (ROP), 47 real gas, 125

Index rectification, 81, 86 refinery, 23 refining, 23, 87 reservoir rock, 5 – 6 retarder, 57 retention time, 70,72 rig, 15 barge, 15 jack-up, 15 – 16 ringwall, 248 – 252 rotary drilling, 14, 29, 31 – 32 rotary drilling sub-systems, 29 controlling system, 31 hoisting system, 30 monitoring system, 31 power system, 29 – 30 rotating or rotary system, 31 rotary hose, 31, 44 – 45 rotary pump, 109 – 111 rotary table, 31, 35, 37, 39, 42 rotating or rotary system, 31

S scrubbers, 66, 71 secondary separation section, 78 seismic survey, 9 – 10, 26 semi submersibles, 15 – 16 sensitive vacuum distillation, 81 separation mechanism, 69 chemical action, 71 electrical separation, 71 – 72 gravity, 69 – 70 pressure change, 70 retention time, 72 scrubbing action, 71 temperature change, 71 separation process, 78 separator, 67 – 101 gravity, 69 – 70 horizontal, 68 – 69 three-phase, 20, 67 – 68 two-phase, 67, 72, 75 vertical, 69, 101 separator components, 72 defoaming plate, 77 feed pipe, 72 gas gravity separation section, 72 inlet device, 72 – 74 liquid gravity separation section, 75 mist extractor, 75, 78 sand removal (jetting) system, 75 vortex breaker, 76 wave breaker, 76 wire plate, 77

281

Index set retardant, 57 shale shaker, 34, 41 shell and tube heat exchanger, 209 shell side, 164 – 165, 169 short path distillation, 81 source rock, 4 – 5 speed regulator, 229 spiral tube heat exchanger, 163, 173 – 174 sprinkler, 264 stairway, 261 standpipe, 44 standpipe manifold, 44 steam distillation, 82 steam turbine, 222 – 233 storage tank, 242 – 276 storage tank types, 242 atmospheric tanks, 242 fixed-roof, 243 floating-roof, 244 internal floating roof, 246 low-pressure, 247 – 248 stripping section, 87 – 88, 102 sulfur, 3, 20, 22, 24 sulfur compounds, 20 sulfuric acid, 24 surface safety valve, 61 surge, 145 – 146 surge limit, 145 – 146 swab valve, 61 – 62 swivel, 40

T tank farm, 24, 256, 262, 265 thermal expansion, 142, 165, 167, 172, 174, 181 thousands of cubic feet (MCF), 22 tool joint, 46 – 47 top drive, 33 toxic, 20, 172, 182, 217 transportation, 1, 15, 19, 22, 76 trap, 5 – 8 travelling block, 30, 33 treatment, 23 – 24 trip valve, 233 tube insert, 167

tube pitch, 167, 207 tube sheet, 166 – 169 fixed, 167 floating, 167 tube side, 164, 169, 172 tubing, 17 – 18, 27, 35, 44 – 46, 52, 59 – 62 Tubular Exchanger Manufacturers Association (TEMA), 165 turbine bearing, 230 turbine blades, 235 turbine seal, 232

U unsaturated hydrocarbons, 24 U-tube heat exchanger, 169, 171

V vacuum distillation, 81 vapor-liquid equilibrium (VLE), 88

W water injection, 19 water tank, 34, 272 weight transfer to the bit (WOB), 47 wellbore, 16 – 17 well completion, 16 – 18 well coring, 12 wellhead, 17 – 19, 60 – 61 wellhead installation, 60 well intervention, 17, 62 well log, 12 – 13 well logging, 12 well stimulation, 17, 26 well testing, 13 wildcat, 11 – 12, 26 wing valve, 61 kill wing valve, 61 production wing valve, 61 – 62

Z zone distillation, 81 – 82