Petroleum Refining Design and Applications Handbook: Rules of Thumb, Process Planning, Scheduling, and Flowsheet Design, Process Piping Design, Pumps, Compressors, and Process Safety Incidents [2, Volume 2 ed.] 1119476410, 9781119476412

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Petroleum Refining Design and Applications Handbook Volume 2

Scrivener Publishing 100 Cummings Center, Suite 541J Beverly, MA 01915-6106

Publishers at Scrivener Martin Scrivener ([email protected]) Phillip Carmical ([email protected])

THE COMPANION WEBSITE FOR THIS BOOK, WHICH CONTAINS DOWNLOADABLE PROGRAMS, SPREADSHEETS, AND OTHER MATERIALS RELATING TO THIS VOLUME, CAN BE FOUND AT THE LINK BELOW: http://www.scrivenerpublishing.com/coker_volume_two/ PASSWORD: Refining

Petroleum Refining Design and Applications Handbook Volume 2 • Rules of Thumb • Pumps

• Process Planning, Scheduling and Flowsheet Design • Compressors

A. Kayode Coker

• Process Piping Design • Process safety Incidents

This edition first published 2021 by John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, USA and Scrivener Publishing LLC, 100 Cummings Center, Suite 541J, Beverly, MA 01915, USA © 2021 Scrivener Publishing LLC For more information about Scrivener publications please visit www.scrivenerpublishing.com. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, except as permitted by law. Advice on how to obtain permission to reuse material from this title is available at http://www.wiley.com/go/permissions.

Wiley Global Headquarters 111 River Street, Hoboken, NJ 07030, USA For details of our global editorial offices, customer services, and more information about Wiley products visit us at www.wiley.com. Limit of Liability/Disclaimer of Warranty While the publisher and authors have used their best efforts in preparing this work, they make no rep­resentations or warranties with respect to the accuracy or completeness of the contents of this work and specifically disclaim all warranties, including without limitation any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representa­tives, written sales materials, or promotional statements for this work. The fact that an organization, website, or product is referred to in this work as a citation and/or potential source of further informa­ tion does not mean that the publisher and authors endorse the information or services the organiza­tion, website, or product may provide or recommendations it may make. This work is sold with the understanding that the publisher is not engaged in rendering professional services. The advice and strategies contained herein may not be suitable for your situation. You should consult with a specialist where appropriate. Neither the publisher nor authors shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages. Further, readers should be aware that websites listed in this work may have changed or disappeared between when this work was written and when it is read. Library of Congress Cataloging-in-Publication Data ISBN 9781119476412

Cover image: Refining Plant - Photobeps Cover design by Kris Hackerott Set in size of 11pt and Minion Pro by Manila Typesetting Company, Makati, Philippines Printed in the USA 10 9 8 7 6 5 4 3 2 1

In Loving Memory of Phillip Ekundayo Jacobs Medellis Delucia Seeta Onslow The most beautiful spiritual beings ever encountered and a privilege to have known. Wishing both the Almighty Father’s grace and blessing, the most wonderful and beautiful journeys in the Luminous Realm of joyful activities in the beyond. Gratitude to the Elemental and Created beings in higher realms, faithfully fulfilling the Will of the Almighty Father. “God wills that His Laws working in Creation should be quite familiar to man, so that he can adjust himself accordingly, and with their help can complete and fulfill his course through the world more easily and without ignorantly going astray.” Abd-ru-shin (In the Light of Truth) The Laws of Creation The Law of Motion The Law of the Attraction of Homogeneous Species The Law of Gravitation The Law of Reciprocal Action

“What is Truth?” “Only the truth is simple.”

Pilate (John 18, 38) Sebastian Haffner

“Woe to the people to whom the truth is no longer sacred!” Friedrich Christoph Schlosser “Truth does not conform to us, dear son but we have to conform with it.” Matthias Claudius “Nothing will give safety except truth. Nothing will give peace except the serious search for truth.” Blaise Pascal

“Truth is the summit of being; justice is the application of it to affairs.” Ralph Waldo Emerson “The ideals which have lighted my way, and time after time have given me new courage to face life cheerfully, have been Kindness, Beauty and Truth.” Albert Einstein “It irritates people that the truth is so simple.”

Johann Wolfgang von Goethe

“Aglow with the Light of the Divine, I surrender my whole attention to the Presence of Truth that guides my path.” Michael Bernard Beckwith “Truth means the congruence of a concept with its reality.” “Truth is the revealing gloss of reality.”

G.W. Friedrich Hegel Simone Well

“We are the Multi-dimensional Universe becoming aware of Itself. Live in this One Truth – That God is Real As your very Life!” Michael Bernard Beckwith “Truth is a torch, but a tremendous one. That is why we hurry past it, shielding our eyes, even terrified of getting burnt.” Johann Wolfgang von Goethe “Truth is the spirit’s sun.” You will recognise the Truth, and the truth will set you free

Marquis de Vauvenargues John, 8:32

“Truth is the Eternal – Unchangeable! Which never changes in its form, but is as it has been eternally and will ever remain, as it is now. Which can therefore never be subjected to any development either, because it has been perfect from the very beginning. Truth is real, it is ‘being’! Only being is true life. The entire Universe is “supported” by this Truth!” Abd-ru-shin

Truth To honour God in all things and to perform everything solely to the glory of God Abd-ru-shin (In the Light of Truth) Awake! Keep the heart of your thoughts pure, by so doing you will bring peace and be happy. Love thy neighbour, which means honour him as such! Therein lies the adamantine command: You must never consciously harm him, either in his body or in his soul, either in his earthly possessions or in his reputation! He who does not keep this commandment and acts otherwise, serves not God but the darkness, to which he gives himself as a tool! Honour be to God Who only sows Love! Love also in the The Law of the destruction of the darkness! Abd-ru-shin (In the Light of Truth)

Love & Gratitude Crystal Images © Office Masaru Emoto, LLC

Contents Prefacexv Acknowledgementsxvii 13 Rules of Thumb—Summary 13.0 Introduction

1 1

14 Process Planning, Scheduling, and Flowsheet Design  19 14.1 Introduction 19 14.2 Organizational Structure 20    14.2.1 Process Design Scope 21 14.3 Role of the Process Design Engineer 23 14.4 Computer-Aided Flowsheeting 24 14.5 Flowsheets—Types 26   14.5.1 Block Diagram 26    14.5.2 Process Flowsheet or Flow Diagram 26    14.5.3 Piping Flowsheet or Mechanical Flow Diagram, or Piping and Instrumentation Diagram (P&ID)27    14.5.4 Combined Process and Piping Flowsheet or Diagram 32    14.5.5 Utility Flowsheets or Diagrams (ULDs) 32    14.5.6 Special Flowsheets or Diagrams 36    14.5.7 Special or Supplemental Aids 36 14.6 Flowsheet Presentation 36 14.7 General Arrangements Guide 36 14.8 Computer-Aided Flowsheet Design/Drafting 38 14.9 Flowsheet Symbols 40 14.10 Line Symbols and Designations 43 14.11 Materials of Construction for Lines 46 14.12 Test Pressure for Lines 47 14.13 Working Schedules 56 14.14 Information Checklists 61 14.15 Basic Engineering and Front End Engineering Design (FEED) 63 References64 15 Fluid Flow   15.1 Introduction   15.2 Flow of Fluids in Pipes  15.3 Scope  15.4 Basis   15.5 Incompressible Flow   15.6 Compressible Flow: Vapors and Gases   15.7 Important Pressure Level References   15.8 Factors of “Safety” for Design Basis   15.9 Pipe, Fittings, and Valves  15.10 Pipe

65 65 65 70 72 72 73 75 75 75 75 ix

x  Contents

15.11 Total Line Pressure Drop 78 15.11.1 Relationship Between the Pipe Diameter and Pressure Drop (ΔP) 80 15.11.2 Economic Balance in Piping and Optimum Pipe Diameter 82 15.12 Reynolds Number, Re (Sometimes Used NRe) 83 15.13 Pipe Relative Roughness 85 15.14 Darcy Friction Factor, f 85 15.15 Friction Head Loss (Resistance) in Pipe, Fittings, and Connections 94 15.15.1 Pressure Drop in Straight Pipe: Incompressible Fluid 94 15.16 Oil System Piping 96 15.16.1 Density and Specific Gravity 97 15.16.2 Specific Gravity of Blended Products 98 15.16.3 Viscosity 98 15.16.4 Viscosity of Blended Products 100 15.16.5 Blending Index, H 101 15.16.6 Vapor Pressure 101 15.16.7 Velocity 101 15.16.8 Frictional Pressure Drop, ft of Liquid Head 104 15.16.9 Hazen–Williams Equation 105 15.16.10 Transmission Factor 107 15.16.11 Miller Equation 112 15.16.12 Shell–MIT Equation 113 15.17 Pressure Drop in Fittings, Valves, and Connections 116 15.17.1 Incompressible Fluid 116 15.17.2 Velocity and Velocity Head 116 15.17.3 Equivalent Lengths of Fittings 117 15.17.4 L/D Values in Laminar Region 120 15.17.5 Validity of K Values 122 15.17.6 Laminar Flow 122 15.17.7 Expressing All Pipe Sizes in Terms of One Diameter 124 15.17.8 Loss Coefficient 128 15.17.9 Sudden Enlargement or Contraction 134 15.17.10 For Sudden Contractions 134 15.17.11 Piping Systems 136 15.18 Resistance of Valves 136 15.19 Flow Coefficients for Valves, Cv 137 15.20 Flow Meters 138 15.20.1 Process Design of Orifice Meter 138 15.20.2 Nozzles and Orifices 142 Conclusion 167 15.21 Estimation of Pressure Loss Across Control Valves 169 15.22 The Direct Design of a Control Valve 173 15.23 Water Hammer 173 15.24 Friction Pressure Drop for Compressible Fluid Flow 175 15.24.1 Compressible Fluid Flow in Pipes 176 15.24.2 Maximum Flow and Pressure Drop 177 15.24.3 Sonic Conditions Limiting Flow of Gases and Vapors 177 15.24.4 The Mach Number, Ma 182 15.24.5 Critical Pressure Ratio 197 15.24.6 Adiabatic Flow 200 15.24.7 The Expansion Factor, Y 201 15.24.8 Misleading Rules of Thumb for Compressible Fluid Flow 203

Contents  xi

15.24.9 Other Simplified Compressible Flow Methods 204 15.24.10 Friction Drop for Flow of Vapors, Gases and Steam 205 15.25 Darcy Rational Relation for Compressible Vapors and Gases 213 15.26 Velocity of Compressible Fluids in Pipe 215 15.27 Procedure 228 15.28 Friction Drop for Compressible Natural Gas in Long Pipe Lines 231 15.29 Panhandle-A Gas Flow Formula 235 15.30 Modified Panhandle Flow Formula 237 15.31 American Gas Association (AGA) Dry Gas Method 237 15.32 Complex Pipe Systems Handling Natural (or Similar) Gas 237 15.33 Two-Phase Liquid and Gas Flow in Process Piping 239 15.33.1 Flow Patterns 239 15.33.2 Flow Regimes 242 15.33.3 Pressure Drop 243 15.33.4 Erosion–Corrosion 248 15.33.5 Total System Pressure Drop 250 15.33.6 Pipe Sizing Rules 257 15.33.7 A Solution for All Two-Phase Problems 261 15.33.8 Gas–Liquid Two-Phase Vertical Down Flow 270 15.33.9 Pressure Drop in Vacuum Systems 277 15.33.10 Low Absolute Pressure Systems for Air 279 15.33.11 Vacuum for Other Gases and Vapors 281 15.33.12 Pressure Drop for Flashing Liquids 284 15.33.13 Sizing Condensate Return Lines 286 15.34 UniSim Design PIPESYS 295 15.35 Pipe Line Safety 300 15.36 Mitigating Pipeline Hazards 301 15.37 Examples of Safety Design Concerns 301 15.38 Safety Incidents Related With Pipeworks and Materials of Construction 303 15.39 Lessons Learned From Piping Designs 319 15.40 Design of Safer Piping 320 15.40.1 Best Practices for Process Piping 320 15.40.2 Designing Liquid Piping 321 15.40.3 Best Practices for Liquid Piping 322 Nomenclature 324 Greek Symbols 326 Subscripts 327 References 327 16 Pumps 331 16.1 Pumping of Liquids 331 16.2 Pump Design Standardization 336 16.3 Basic Parts of a Centrifugal Pump 336 16.4 Centrifugal Pump Selection 341 16.5 Hydraulic Characteristics for Centrifugal Pumps 359 16.6 Suction Head or Suction Lift, hs 367 16.7 Discharge Head, hd 369 16.8 Velocity Head 369 16.9 Friction 370 16.10 Net Positive Suction Head (NPSH) and Pump Suction 370 16.11 General Suction System 378

xii  Contents

16.12 Reductions in NPSHR 384 16.13 Charting NPSHR Values of Pumps 384 16.14 Net Positive Suction Head (NPSH) 386 16.15 NPSH Requirement for Liquids Saturation With Dissolved Gases 388 16.16 Specific Speed 390 16.17 Rotative Speed 394 16.18 Pumping Systems and Performance 395 16.19 Power Requirements for Pumping Through Process Lines 399 16.20 Affinity Laws 405 16.21 Centrifugal Pump Efficiency 417 16.22 Effects of Viscosity 421 16.23 Temperature Rise and Minimum Flow 436 16.24 Centrifugal Pump Specifications 440 16.25 Number of Pumping Units 441 16.26 Rotary Pumps 448 16.27 Reciprocating Pumps 452 16.28 Pump Selection 456 16.29 Selection Rules-of-Thumb 456 16.30 Case Studies 459 16.31 Pump Cavitations 464 16.32 Pump Fundamentals 474 16.33 Operating Philosophy 475 16.34 Piping 485 16.35 Troubleshooting Checklist for Centrifugal Pumps 485 Nomenclature 493 Subscripts 494 Greek Symbols 495 References 495 17 Compression Equipment  497 17.1 Introduction 497 17.2 General Application Guide 498 17.3 Specification Guides 499 17.4 General Considerations for Any Type of Compressor Flow Conditions 501 17.4.1 Fluid Properties 501 17.4.2 Compressibility 502 17.4.3 Corrosive Nature 502 17.4.4 Moisture 502 17.4.5 Special Conditions 502 17.5 Reciprocating Compression 503 17.6 Suction and Discharge Valves 514 17.7 Specification Sheet 523 17.8 Performance Considerations 524 17.9 Compressor Performance Characteristics 557 17.10 Hydrogen Use in the Refinery 594 17.10.1 IsoTherming Technology for Kerosene, Vacuum Gas Oil, and Diesel Hydroprocessing 595 Nomenclature 829 Greek Symbols 832

Contents  xiii

Subscripts 832 References 833 Glossary of Petroleum and Technical Terminology

837

Appendix D

929

Appendix E

1005

Index 1019 About the Author

1025

Preface Petroleum refining is a complex industry that worldwide produces more than $10 billion worth of refined products. Improvements in the design and operation of these facilities can deliver large economic value for refiners. Furthermore, economic, regulatory and environmental concerns impose significant pressure on refiners to provide safe working conditions and at the same time optimize the refining process. Refiners have considered alternative processing units and feedstocks by investing in new technologies. The United States, Europe and countries elsewhere in the world are embarking on full electrification of automobiles within the next couple of decades. Furthermore, the current pandemic of the coronavirus with lock downs in many countries has restricted the movement of people, less use of aviation fuel and motor gasoline. This has resulted in the barrel of crude being sold at $42.0 per barrel presenting problems to oil producers and refiners. The venture of electrification still poses inherent problems of resolving rechargeable batteries and fuel cells and providing charging stations along various highways and routes. Oil and natural-gas will for the foreseeable future form an important part of everyday life. Their availability has changed the whole economy of the world by providing basic needs for mankind in the form of fuel, petrochemicals and feedstocks for fertilizer plants and energy for the power sector. Presently, the world economy runs on oil and natural gas, and the processing of these feedstocks for producing fuels, and value-added products has become an essential activity in modern society. The availability of liquefied natural gas (LNG) has enhanced the environment, and recent development in the technology of natural gas to liquids (GTL) has further improved the availability of fuel to transportation and other sectors. The complex processing of petroleum refining has created a need for environmental, health, and safety management procedures and safe work practices. These

procedures are established to ensure compliance with applicable regulations and standards such as hazard communications (PHA, HAZOP, HAZAN, Inherently Safer Design, MoC, and so on), emissions, Waste Management pollution that includes volatile organic compounds (VOC), carbon monoxide, sulfur oxides (SOx), nitrogen oxides (NOx), particulates, ammonia (NH3), hydrogen sulfide (H2S), and toxic organic compounds) and waste minimization. These pollutants are often discharged as air emissions, wastewater or solid wastes. Furthermore, concern over issues such as the depletion of the ozone layer that results in global warming is increasingly having a significant impact on Earth’s nature and mankind, and carbon dioxide (CO2) is known to be the major culprit of global warming. Other emissions such as H2S, NOx, and SOx from petroleum refining have adversely impacted the environment, and agencies such as Occupational Safety and Health Administration (OSHA), and Environmental Protection Agency (EPA), Health and Safety Executive (U.K. HSE) have imposed limits on the emissions of these compounds upon refiners. Flaring has become more complicated and concerns about its efficiency have been increasing and discussed by experts. The OSHA, EPA and HSE have imposed tighter regulations on both safety and emission control, which have resulted in higher levels of involvement in safety, pollution, emissions and so on. Petroleum refining is one of the important sectors of the world economy, and it’s playing a crucial and pivotal role in industrialization, urbanization, and meeting the basic needs of mankind by supplying energy for industrial and domestic transportation, feedstock for petrochemical products as plastics, polymers, agrochemicals, paints, and so on. Globally, it processes more materials than any other industry, and with a projected increase in population to around 8.1 billion by 2025, increasing demand for fuels, electricity and various consumer products made from the petrochemical route is expected via the petroleum and refining process. xv

xvi  Preface

Petroleum Refining Design and Applications Handbook, Volume Two, is a continuation of volume one; comprising of five chapters, a glossary of petroleum and technical terminology, appendices, Excel spreadsheet programs, computer developed programs, UniSim – Design simulation software excises, cases studies and a Conversion Table, interspersed with Process Safety Incidents. Chapter 13 provides the rules of thumb of process equipment and the heuristics for designers, which can be applied by engineers who are substantially familiar with the topics. However, such rules should be of value for approximate design and cost estimation, and should not provide the inexperienced engineer with a perspective, and a foundation where detailed and computer-aided results can be determined; Chapter 14 provides organization structure and design scope and roles of the process design engineer. The functions of these roles are used in various chapters of volumes 2, 3 and 4 of these volume series. Other pertinent functions in this chapter are flowsheets involving a block diagram, process flow (PFD) diagram and process and instrumentation (P & ID) diagram, computer-aided flowsheet design, symbols and basic engineering and front-end engineering design (FEED). Chapter 15 is on fluid flow in process piping, showing the scope, the basis for incompressible and compressible fluids, oil systems piping, pressure drop in process lines, including fittings, resistance of valves, water hammer, two-phase liquid and gas flows in process piping; application of UniSim design PIPESYS, mitigating pipeline hazards, pipeline safety and safety incidents related with pipework and materials of construction and design for

safer piping. This chapter further provides the root causes, findings and recommendations of these incidents in the refinery and chemical plants ensuring that lessons are learned and thus preventing further deaths; Chapter 16 reviews pumping of liquids, centrifugal pump selection, hydraulic characteristics for centrifugal pumps, net positive suction head and requirement for liquid’s saturation with dissolved gases, pump cavitation, affinity laws, centrifugal pump efficiency, rotary pumps, reciprocating pumps, screw pumps, operating philosophy, troubleshooting and checklist for centrifugal pumps, pumps reliability, root causes of pump failures and their impact, cases studies of pump failures in the refinery, their root causes, findings and recommendations. Process safety management involving mechanical integrity and management of change (MOC). Chapter 17 describes compression equipment with specification guides, general application guide, and performance consideration, hydrogen use in the refinery, and UniSim design case studies. The chapter further describes various compressor types, advantages and disadvantages, probably causes and troubleshooting as well as process safety incidents involving compressors’ malfunctions. Furthermore, the chapter describes integrally geared compressors that have wide application in carbon dioxide (CO2) service for enhanced oil recovery (EOR) with an added benefit to the environment, as nearly all of the injected CO2 is permanently sequestrated in the depleted oil fields long after these fields have ceased operation. Appendix D provides construction commissioning start-up checklists of rotary equipment such as pumps, compressors, and other equipment such as blowers, fans and mixers.

Acknowledgments This project is the culmination of five years of research, collating relevant materials from organizations, institutions, companies and publishers, developing Excel spreadsheet programs and computer programs; using Honeywell’s UniSim steady state simulation programs and providing the majority of the drawings in the text. Sincere gratitude to Honeywell Process Solutions for granting permission to incorporate the use of UniSim Design simulation and many other suites of software programs in the book. I express my thanks to Dr. Jamie Barber of Honeywell Process Solutions for his friendship and help over many years of using the UniSim software. To Mr. Ahmed Mutawa formerly of SASREF Co., Saudi Arabia for developing the Conversion Table program for the book. Many organizations, institutions and companies as Gas Processor Suppliers Association (GPSA), USA, Honeywell Process Solutions, Saudi Aramco Shell Refinery Co., (SASREF), Absoft Corporation, USA., American Institute of Chemical Engineers, The Institution of Chemical Engineers, U.K., Chemical Engineering magazine by Access Intelligence, USA., Hydrocarbon Processing magazine have readily given permission for the use of materials and their release for publication. I greatly acknowledge and express my deepest gratitude to these organizations. I have been privileged to have met with Phil Carmical, Publisher at Scrivener Publishing Co.,

some twenty years ago. Phil initiated the well-known Ludwig’s project at the time during his tenure at Gulf Publishing Co., and Elsevier, respectively. His suggestions in collaborating on these important works some seven years ago were timely to the engineering community, as I hope that these works will be greatly beneficial to this community world-wide. I’m deeply grateful to Phil for agreeing to collaborate with me, his suggestions and assistance since. It is my believe upon completing this aspect of the project that the book will save lives in the refinery industry. I also wish to express my thanks to the WileyScrivener team: Kris Hackerott- Graphics Designer, Bryan Aubrey – Copy editor, Myrna Ting – Typesetter and her colleagues. I am truly grateful for your professionalism, assistance and help in the production of this volume.

Finally, Bow down in humility before the Greatness of God, whose Love is never-ending, and who sends us his help at all times. He alone is Life and the Power and the Glory for ever and ever. A. Kayode Coker

xvii

13 Rules of Thumb—Summary

13.0 Introduction An engineering Rule of Thumb is an outright statement regarding suitable sizes or performance of equipment that avoids all requirements for extended calculations. These are safely applied by engineers who are substantially familiar with the topics. However, such rules should be of value for approximate design and cost estimation, and should not provide the inexperienced engineer with perspective and a foundation where detailed and computer-aided results can be determined. Experienced engineers often know where to find information and how to make accurate calculations; they also retain a minimum body of information in mind, which is made up largely of shortcuts and heuristics. The compilation below may fit into such a minimum body of information that boosts to the memory or extension in some instances into less often encountered areas.

COMPRESSORS, FANS, BLOWERS, AND VACUUM PUMPS 1. F  ans are used to raise the pressure by about 3% [12 in. (30 cm) water], blowers raise to less than 2.75 barg (40 psig), and compressors to higher pressures, although the blower range is commonly included in the compressor range. 2. For vacuum pumps use the following: Reciprocating piston type down to 133.3 Pa (1 torr) Rotary piston type down to 0.133 Pa (0.001 torr) Two lobe rotary type down to 0.0133 Pa (0.0001 torr) Steam jet ejectors 1 stage down to 13.3 k Pa (100 torr) 3 stage down to 133.3 Pa (1 torr) 5 stage down to 6.7 Pa (0.05 torr) 3. A three-stage ejector needs 100 kg steam/kg air to maintain a pressure of 133.3 Pa (1 torr). 4. In-leakage of air to evacuated equipment depends on the absolute pressure (torr) and the volume of the equipment, V in m3 (ft3), according to W = kV2/3 kg/h (lb/h), with k = 0.98 (0.2) when P > 90 torr, k = 0.39 (0.08) when P is between 0.4 and 2.67 kPa (3 and 20 torr), and k = 0.12 (0.025) at p less than 133.3 Pa (1 torr). 5. Theoretical adiabatic horsepower

A. Kayode Coker. Petroleum Refining Design and Applications Handbook Volume 2, (1–18) © 2021 Scrivener Publishing LLC

1

2  Petroleum Refining Design and Applications Handbook Volume 2 a  (SCFM )T1  P2     − 1 THP = 8130a  P1  





where T1 is inlet temperature in Rankine, R = °F + 460 and a = (k − 1)/k, k = Cp/Cv. Theoretical reversible adiabatic power = mɀ1RT1[({P2/P1}a − 1)]/a, where T1 is inlet temperature, R = Gas Constant, ɀ1 = compressibility factor, m = molar flow rate, a = (k − 1)/k and k = Cp/Cv. Values of °R = 8.314 J/mol K = 1.987 Btu/lb mol R = 0.7302 atm ft3/lb mol° R. 6. Outlet temperature for reversible adiabatic process a

P  T2 = T1  2   P1 



7. T  o compress air from 37.8° C (100°F), k = 1.4, compression ratio = 3, theoretical power required = 62 hp/million ft3/day, outlet temperature 152.2°C (306°F). 8. Exit temperature should not exceed 167–204° C (350–400° F); for diatomic gases (Cp/Cv = 1.4), this corresponds to a compression ratio of about 4. 9. Compression ratio should be about the same in each stage of a multistage unit, ratio = (Pn/P1)1/n, with n stages. 10. Efficiencies of reciprocating compressors: 65% at compression ratio of 1.5, 75% at 2.0, and 80–85% at 3–6. 11. Efficiencies of large centrifugal compressors, 2.83–47.2m3/s (6000–100,000 acfm) at suction, are 76–78%. 12. Rotary compressors have efficiencies of 70%, except liquid liner type which have 50%.

CONVEYORS FOR PARTICULATE SOLIDS 1. S crew conveyors are suited to transport of even sticky and abrasive solids up inclines of 20° or so. They are limited to distances of 3.81 m (150 ft) or so because of shaft torque strength. A 304.8 mm (12 in.) diameter conveyor can handle 28.3–84.95 m3/h (1000–3000 ft3/h), at speeds ranging from 40 to 60 rpm. 2. Belt conveyors are for high capacity and long distances (a mile or more, but only several hundred feet in a plant), up inclines of 30° maximum. A 609.6-mm (24 in.) wide belt can carry 84.95 m3/h (3000 ft3/h) at a speed of 0.508 m/s (100 ft/min), but speeds up to 3.048 m/s (600 ft/min) are suited to some materials. Power consumption is relatively low. 3. Bucket elevators are suited to vertical transport of sticky and abrasive materials. With 508 × 508-mm (20 × 20-in.) buckets, capacity can reach 28.3 m3/h (1000 ft3/h) at a speed of 0.508 m/s (100 ft/min), but speeds up to 1.524 m/s (300 ft/min) are used. 4. Drag-type conveyors (Redler) are suited to short distances in any direction and are completely enclosed. Units range in size from 19.4 × 10−4 to 122.6 × 10−4 m2 (3–19 in.2) and may travel from 0.15 m/s (30 ft/ min) (fly ash) to 1.27 m/s (250 ft/min) (grains). Power requirements are high. 5. Pneumatic conveyors are for high capacity, short distance (122 m (400 ft)) transport simultaneously from several sources to several destinations. Either vacuum or low pressure 0.4–0.8 barg (6–12 psig) is used with a range of air velocities from 10.7 to 36.6 m/s (35–120 ft/s); depending on the material and pressure and air requirements, 0.03–0.2 m3/m3 (1–7 ft3/ft3) of solid is transferred.

COOLING TOWERS 1. W  ater in contact with air under adiabatic conditions eventually cools to the wet bulb temperature. 2. In commercial units, 90% of saturation of the air is feasible.

Rules of Thumb—Summary   3 3. Relative cooling tower size is sensitive to the difference between the exit and the wet bulb temperatures:

∆T, °F 5 15 25 Relative volume 2.4 1.0 0.55 4. T  ower fill is of a highly open structure so as to minimize pressure drop, which is in standard practice a maximum of 497.6 Pa (2 in. of water). 5. Water circulation rate is 48.9–195.7 L/min m2 (1–4 gpm/ft2) and air rate is 6344–8784 kg/h m2 (1300– 1800 lb/h ft2) or 1.52–2.03 m/s (300–400 ft/min). 6. Chimney-assisted natural draft towers are hyperboloidally shaped because they have greater strength for a given thickness; a tower 76.2 m (250 ft) high has concrete walls 127–152.4 mm (5–6 in.) thick. The enlarge cross section at the top aids in dispersion of exit humid air into the atmosphere. 7. Countercurrent-induced draft towers are the most common in process industries. They are able to cool water within 2°F of the wet bulb. 8. Evaporation losses are 1% of the circulation for every 10°F of cooling range. Windage or drift losses of mechanical draft towers are 0.1–0.3% Blowdown of 2.5–3.0% of the circulation is necessary to prevent excessive salt buildup.

CRYSTALLIZATION FROM SOLUTION 1. C  omplete recovery of dissolved solids is obtainable by evaporation, but only to the eutectic composition by chilling. Recovery by melt crystallization also is limited by the eutectic composition. 2. Growth rates and ultimate sizes of crystals are controlled by limiting the extent of supersaturation at any time. 3. The ratio S = C/Csat of prevailing concentration to saturation concentration is kept near the range 1.02–1.05. 4. In crystallization by chilling, the temperature of the solution is kept almost 1–2°F below the saturation temperature at the prevailing concentration. 5. Growth rates of crystals under satisfactory conditions are in the range of 0.1–0.8 mm/h. The growth rates are approximately the same in all directions. 6. Growth rates are influenced greatly by the presence of impurities and of certain specific additives, which vary from case to case.

DISINTEGRATION 1. P  ercentages of material greater than 50% of the maximum size are about 50% from rolls, 15% from tumbling mills, and 5% from closed-circuit ball mills. 2. Closed-circuit grinding employs external size classification and return of oversize for regrinding. The rules of pneumatic conveying are applied to the design of air classifiers. Closed circuit is most common with ball and roller mills. 3. Jaw crushers take lumps of several feet in diameter to 102 mm (4 in.). Stroke rates are 100–300/min. The average feed is subjected to 8–10 strokes before it becomes small enough to escape. Gyratory crushers are suited to slabby feeds and makes a more rounded product. 4. Roll crushers are made either smooth or with teeth. A 610-mm (24-in.) toothed roll can accept lumps of 356 mm (14 in.) diameter. Smooth rolls affect reduction ratios up to about 4. Speeds are 50–90 rpm. Capacity is about 25% of the maximum, corresponding to a continuous ribbon of material passing through the rolls. 5. Hammer mills beat the material until it is small enough to pass through the screen at the bottom of the casing. Reduction ratios of 40 are feasible. Large units operate at 900 rpm, smaller ones up to 16,000 rpm. For fibrous materials the screen is provided with cutting edges.

4  Petroleum Refining Design and Applications Handbook Volume 2 6. Rod mills are capable of taking feed as large as 50 mm and reducing it to 300 mesh, but normally the product range is 8–65 mesh. Rods are 25–150 mm in diameter. The ratio of rod length to mill diameter is about 1.5. About 45% of the mill volume is occupied by rods. Rotation is at 50–65% of critical. 7. Ball mills are better suited than rod mills to fine grinding. The charge is of equal weights of 1.5-, 2-, and 3-in. balls for the finest grinding. The volume occupied by the balls is 50% of the mill volume. Rotation speed is 70–80% of critical. Ball mills have a length-to-diameter ratio in the range 1–1.5. Tube mills have a ratio of 4–5 and are capable of very find grinding. Pebble mills have ceramic grinding elements, used when contamination with metal is to be avoided. 8. Roller mills employ cylindrical or tapered surfaces that roll along flatter surfaces and crush nipped particles. Products of 20–200 mesh are made.

TOWERS 1. D  istillation usually is the most economical method of separating liquids, superior to extraction, absorption, crystallization, or others. 2. For ideal mixtures, relative volatility is the ratio of vapor pressure, α12= P2/P1. 3. Tower operating pressure is most often determined by the temperature of the available condensing medium, 38–50°C (100–120°F) if cooling water, or by the maximum allowable reboiler temperature, 10.34 barg (150 psig) steam, 186°C (366° F) to avoid chemical decomposition/degradation. 4. Sequencing of columns for separating multicomponent mixtures: a. Perform the easiest separation first, that is, the one least demanding of trays and reflux, and leave the most difficult to the last. b. When neither relative volatility nor feed concentration vary widely, remove the components one by one as overhead products. c. When the adjacent ordered components in the feed vary widely in relative volatility, sequence the splits in the order of decreasing volatility. d. And when the concentrations in the feed vary widely but the relative volatilities do not, remove the components in the order of decreasing concentration in the feed. 5. The economically optimum reflux ratio is about 1.2–1.5 times the minimum reflux ratio Rm. 6. The economically optimum number of theoretical trays is near twice the minimum value Nm. 7. The minimum number of trays is found with the Fenske–Underwood equation:



Nm =

log{[x /(1 − x )]ovhd /[x /(1 − x )]btms } log α

8. M  inimum reflux for binary or pseudobinary mixtures is given by the following when separation is essentially complete (xD ≌ 1) and D/F is the ratio of overhead products to feed rate:

Rm D 1 = α −1 F ( R + 1)D α = when feed is at the dew point m F α −1 when feed is at the bubble point





9. A safety factor of 10% of the number of trays calculated by the best means is advisable. 10. Reflux pumps are made at least 10% oversize.

Rules of Thumb—Summary   5 11. The optimum value of the Kremser—Brown absorption factor A = (L/VK) is in the range 1.25–2.0. 12. Reflux drums usually are horizontal, with a liquid holdup of 5 min half-full. A takeoff pot for a second liquid phase, such as water in hydrocarbon systems, is sized for a linear velocity of that phase of 0.15 m/s (0.5 ft/s) minimum diameter of 406.4 mm (16 in.). 13. For towers about 914 mm (3 ft) diameter, add 1219 mm (4 ft) at the top for vapor disengagement and 1829 mm (6 ft) at the bottom for liquid level and reboiler return. 14. Limit the tower height to about 53 m (175 ft) maximum because of wind load and foundation considerations. An additional criterion is that L/D be less than 30 (20 < L/D < 30 often will require special design).

TRAY TOWERS 1. F  or reasons of accessibility, tray spacings are made 0.5–0.6 m (20–24 in.). 2. Peak efficiency of trays is at values of the vapor factor Fs = µ (ρv)0.5 in the range of 1.2–1.5 m/s (kg/m3)0.5 [1–1.2 ft/s (lb/ft3)0.5]. This range of Fs establishes the diameter of tower. Roughly, linear velocities are 0.6 m/s (2 ft/s) at moderate pressures and 1.8 m/s (6 ft/s) in vacuum. 3. Pressure drop per tray is of the order of 747 Pa (3 in. water) or 689.5 Pa (0.1 psi). 4. Tray efficiencies for distillation of light hydrocarbons and aqueous solutions are 60–90%; for gas absorption and stripping, 10–20%. 5. Sieve trays have holes of 6–7 mm (0.25–0.50 in.) diameter, hole area being 10% of the active cross section. 6. Valve trays have holes of 38 mm (1.5 in.) diameter, each provided with a liftable cap, with 130–150 caps per square meter (12–14 caps per square feet) of active cross section. Valve trays are usually cheaper than sieve trays. 7. Bubble cap trays are used only when liquid level must be maintained at low turndown ratio; they can be designed for lower pressure drop than either sieve or valve trays. 8. Weir heights are 50 mm (2 in.), weir lengths are about 75% of trays diameter, and liquid rate a maximum of about 1.2 m3/min-m of weir (8 gpm/in. of weir); multi-pass arrangements are used at higher liquid rates.

PACKED TOWERS 1. S tructured and random packings are suitable for packed towers less than 0.9 m (3 ft) when low pressure drop is required. 2. Replacing trays with packing allows greater throughput and separation in existing tower shells. 3. For gas rates of 14.2 m3/min (500 ft3/min), use 25.4-mm (1-in.) packing; for 56.6m3/min (2000 ft3/ min) or more use 50-mm (2-in.) packing. 4. Ratio of tower diameter/packing diameter should be >15/1. 5. Because of deformability, plastic packing is limited to 3–4 m (10–15 ft) and metal packing to 6.0–7.6 m (20–25 ft) unsupported depth. 6. Liquid distributors are required every 5–10 tower diameters with pall rings and at least every 6.5 m (20 ft) for other types of dumped packing. 7. Number of liquid distributions should be >32–55/m2 (3–5/ft2) in towers greater than 0.9 m (3 ft) diameter and more numerous in smaller columns. 8. Packed towers should operate near 70% of the flooding rate (evaluated from Sherwood and Lobo correlation). 9. Height Equivalent to a Theoretical Stage (HETS) for vapor–liquid contacting is 0.4–0.56 m (1.3–1.8 ft) for 25-mm (1-in.) pall rings and 0.76–0.9 m (2.5–3.0 ft) for 50-mm (2-in.) pall rings.

6  Petroleum Refining Design and Applications Handbook Volume 2 10. G  eneralized pressure drops

Design pressure drops (cm of H2O/m of packing)

Design pressure drops (in. of H2O/ft of packing)

Absorbers and Regenerators (non-foaming systems)

2.1–3.3

0.25–0.40

Absorbers and Regenerators

0.8–2.1

0.10–0.25

Atmospheric/Pressure Stills and Fractionators

3.3–6.7

0.40–0.80

Vacuum Stills and Fractionators

0.8–3.3

0.10–0.40

Maximum value

8.33

1.0

DRIVERS AND POWER RECOVERY EQUIPMENT 1. E  fficiency is greater for larger machines. Motors, 85–95%; steam turbines, 42–78%; gas engines and turbines, 28–38%. 2. For under 74.6 kW (100 hp), electric motors are used almost exclusively. They are made for up to 14,900 kW (20,000 hp). 3. Induction motors are most popular. Synchronous motors are made for speeds as low as 150 rpm and are thus suited, for example, for low-speed reciprocating compressors, but are not made smaller than 50 hp. A variety of enclosures are available, from weather-proof to explosion-proof. 4. Steam turbines are competitive above 76.6 kW (100 hp). They are speed-controllable. They are frequency used as spares in case of power failure. 5. Combustion engines and turbines are restricted to mobile and remote locations. 6. Gas expanders for power recovery may be justified at capacities of several hundred hp; otherwise any pressure reduction in a process is done with throttling valves. 7. The following useful definitions are given:



shaft power =

theoretical power to pump fluid (liquid or gas) efficiency of pump or compressor , ε dr

drive power =

shaft power efficiency of drive, ε dr

Overall efficiency, ε ov = ε sh ⋅ ε dr



DRYING OF SOLIDS 1. D  rying times range from a few seconds in spray dryers to 1 h or less in rotary dryers and up to several hours or even several days in tunnel shelf or belt dryers. 2. Continuous tray and belt dryers for granular material of natural size or pelleted to 3–15 mm have drying in the range of 10–200 min. 3. Rotary cylindrical dryers operate with superficial air velocities of 1.52–3.05 m/s (5–10 ft/s), sometimes up to 10.67 m/s (35 ft/s) when the material is coarse. Residence times are 5–90 min. Holdup of solid is 7–8%. An 85% free cross section is taken for design purposes. In countercurrent flow, the exit gas

Rules of Thumb—Summary   7

4.

5.

6.

7.

is 10–20°C above the solid; in parallel flow, the temperature of the exit solid is 100°C. Rotation speeds of about 4 rpm are used, but the product of rpm and diameter in feet is typically between 15 and 25. Drum dryers for pastes and slurries operate with contact times of 3–12 s, and produce flakes 1–3 mm thick with evaporation rates of 15–30 kg/m2-h. Diameters are in the range of 1.5–5.0 ft; and rotation rate is 2–10 rpm. The greatest evaporative capacity is of the order of 1360.7 kg/h (3000 lb/h) in commercial units. Pneumatic conveying dryers normally take particles 1–3 mm diameter but up to 10 mm when the moisture is mostly on the surface. Air velocities are 10–30 m/s. Single-pass residence times are ­0.5–3.0 s, but with normal recycling the average residence time is brought up to 60 s. Units in use range from 0.2 m in diameter by 1 m long to 0.3 m in diameter by 38 m long. Air requirement is several SCFM per lb of dry product/h. Fluidized bed dryers work best on particles of a few tenths of a mm in diameter, but particles of up to 4 mm in diameter have been processed. Gas velocities of twice the minimum fluidization velocity are a safe prescription. In continuous operation, drying times of 1–2 min are enough, but batch drying of some pharmaceutical products employs drying times of 2–3 h. Spay dryers: Surface moisture is removed in about 5 s, and most drying is completed in less than 60 s. Parallel flow of air and stock is most common. Atomizing nozzles have openings 3–3.8 mm ­(0.012–0.15 in.) and operate at pressures of 21–276 bar (300–4000 psi). Atomizing spray wheels rotate at speeds of 20,000 rpm with peripheral speeds of 76.2–183 m/s (250–600 ft/s). With nozzles, the length-todiameter ratio of the dryer is 4–5; with spray wheels, the ratio is 0.5–1.0. For the final design, the experts say, pilot tests in a unit of 2 m diameter should be made.

EVAPORATORS 1. L  ong tube vertical evaporators with either natural or forced circulation are most popular. Tubes are 19–63 mm (0.75–24.8 in.) in diameter and 3.66–9.14 m (12–30 ft) long. 2. In forced circulation, linear velocities in the tubes are in the range of 4.57–6.09 m/s (15–20 ft/s). 3. Elevation of boiling point by dissolved solids results in temperature differences of 3–10°F between solution and saturated vapor. 4. When the boiling point rise is appreciable, the economic number of effects in series with forward feed is 4–6. 5. When the boiling point rise is small, minimum cost is obtained with 8–10 effects in series. 6. In backward feed the more concentrated solution is heated with the highest temperature steam so that heating surface is lessened, but the solution must be pumped between stages. 7. The steam economy of an N-stage battery is approximately 0.8 N-lb evaporation/lb of outside steam. 8. Interstage steam pressures can be boosted with steam jet compressors of 20–30% efficiency or with mechanical compressors of 70–75% efficiency.

EXTRACTION, LIQUID–LIQUID 1. Th  e dispersed phase should be the one that has the higher volumetric rate, except in equipment subject to back-mixing where it should be the one with the smaller volumetric rate. It should be the phase that wets the material of construction less well. Since the holdup of continuous phase is greater, that phase should be made up of the less expensive or less hazardous material. 2. There are no known commercial applications of reflux to extraction processes, although the theory is favorable. 3. Mixer–settler arrangements are limited to at most five stages. Mixing is accomplished with rotating impellers or circulating pumps. Settlers are designed on the assumption that droplet sizes are about 150 µm in diameter. In open vessels, residence times of 30–60 min or superficial velocities of 0.15–0.46

8  Petroleum Refining Design and Applications Handbook Volume 2

4. 5.

6. 7. 8.

9.

m/min (0.5–1.5 ft/min) are provided in settlers. Extraction-stage efficiencies commonly are taken as 80%. Spray towers as tall as 6–12 m (20–40 ft) cannot be depended on to function as more than a single stage. Packed towers are employed when 5–10 stages suffice. Pall rings 25–38 mm (1–1.5 in.) in size are best. Dispersed-phase loadings should not exceed 10.2m3/min-m2 (25 gal./min-ft2), and HETS of 1.5–3.0 m (5–10 ft) may be realized. The dispersed phase must be redistributed every 1.5–2.1 m (5–7 ft). Packed towers are not satisfactory when the surface tension is more than 10 dyne/cm. Sieve tray towers have holes of only 3–8 mm diameter. Velocities through the holes are kept below 0.24 m/s (0.8 ft/s) to avoid formation of small drops. Re-dispersion of either phase at each tray can be designed for. Tray spacings are 152–600 mm (6–24 in). Tray efficiencies are in the range of 20–30%. Pulse packed and sieve tray towers may operate at frequencies of 90 cycles/min and amplitudes of 6–25 mm. In large-diameter tower, HETS of about 1 m has been observed. Surface tensions as high as 30–40 dyn/cm have no adverse effect. Reciprocating tray towers can have holes of 150 mm (9/16 in.) diameter, 50–60% open area, stroke length 190 mm (0.75 in.), 100–150 strokes/min, and plate spacing normally 50 mm (2 in.) but in the range of ­25.0–150 mm (1–6 in.). In a 760-mm (30-in.) diameter tower, HETS is 500–650 mm (20–25 in.) and throughput is 13.7 m3/min-m2 (2000 gal./h-ft2). Power requirements are much less than those of pulsed towers. Rotating disk contractors or other rotary agitated towers realize HETS in the range of 0.1–0.5 m (0.33– 1.64 ft). The especially efficient Kuhni with perforated disks of 40% free cross section has HETS of 0.2 m (0.66 ft) and a capacity of 50 m3 /m2-h (164 ft3/ft2-h).

FILTRATION 1. P  rocess are classified by their rate of cake buildup in a laboratory vacuum leaf filter: rapid, 0.1–10.0 cm/s; medium, 0.1–10.0 cm/min; and slow, 0.1–10.0 cm/h. 2. Continuous filtration should not be attempted if 1/8 in. cake thickness cannot be formed in less than 5 min. 3. Rapid filtering is accomplished with belts, top feed drums, or pusher centrifuges. 4. Medium rate filtering is accomplished with vacuum drums or disks or peeler centrifuges. 5. Slow-filtering slurries are handled in pressure filters or sedimenting centrifuges. 6. Clarification with negligible cake buildup is accomplished with cartridges, precoat drums, or sand filters. 7. Laboratory tests are advisable when the filtering surface is expected to be more than a few square meters, when cake washing is critical, when cake drying may be a problem, and when precoating may be needed. 8. For finely ground ores and minerals, rotary drum filtration rates may be 15,000 lb/day-ft2 at 20 rev/h and 18–25 in. Hg vacuum. 9. Coarse solids and crystals may be filtered at rates of 6000 lb/day-ft2 at 20 rev/h and 2–6 in. Hg vacuum.

FLUIDIZATION OF PARTICLES WITH GASES 1. P  roperties of particles that are conducive to smooth fluidization include rounded or smooth shape, enough toughness to resist attrition, sizes in the range of 50–500 µm diameter, and a spectrum of sizes with ratio of largest to smallest in the range of 10–25. 2. Cracking catalysts are members of a broad class characterized by diameters of 30–150 µm, density of 1.5 g/ml or so, and appreciable expansion of the bed before fluidization sets in, minimum bubbling velocity greater than minimum fluidizing velocity, and rapid disengagement of bubbles. 3. The other extreme of smoothly fluidizing particles are typified by coarse sand and glass beads, both of which have been the subject of much laboratory investigation. Their sizes are in the range of

Rules of Thumb—Summary   9 1­ 50–500 µm, densities 1.5–4.0 g/ml, have small bed expansion and about the same magnitudes of minimum bubbling and minimum fluidizing velocities, and they also have rapidly disengaging bubbles. 4. Cohesive particles and large particles of 1 mm or more do not fluidize well and usually are processed in other ways. 5. Rough correlations have been made of minimum fluidization velocity, minimum bubbling velocity, bed expansion, bed level fluctuation, and disengaging height. Experts recommend, however, that any real design be based on pilot-plant work. 6. Practical operations are conducted at two or more multiples of the minimum fluidizing velocity. In reactors, the entrained material is recovered with cyclones and returned to process. In driers, the fine particles dry most quickly so the entrained material need not be recycled.

HEAT EXCHANGERS 1. F  or conservative estimate set F = 0.9 for shell and tube exchangers with no phase changes, q = UAF∆Tlm. When ∆T at exchanger ends differ greatly then check F, reconfigure if F is less than 0.85. 2. Take true countercurrent flow in a shell-and-tube exchanger as a basis. 3. Standard tubes are 19.0 mm (3/4 in.) outer diameter (OD), 25.4 mm (1 in.) triangular spacing, 4.9 m (16 ft) long.

A shell of 300 mm (1 ft) diameter accommodates 9.3 m2 (100 ft2); 600 mm (2 ft) diameter accommodates 37.2 m2 (400 ft2); 900 mm (3 ft) diameter accommodates 102 m2 (1100 ft2).

4. 5. 6. 7. 8. 9.

 ube side is for corrosive, fouling, scaling, and high-pressure fluids. T Shell side is for viscous and condensing fluids. Pressure drops are 0.1 bar (1.5 psi) for boiling and 0.2–0.62 bar (3–9 psi) for other services. Minimum temperature approach is 10°C (20°F) for fluids and 5°C (10°F) for refrigerants. Cooling water inlet temperature is 30°C (90°F), maximum outlet temperature 49°C (120°F). Heat-transfer coefficients for estimating purposes, W/m2°C (Btu/h-ft2-°F): water to liquid, 850 (150); condensers, 850 (150); liquid to liquid, 280 (50); liquid to gas, 60 (10); gas to gas, 30 (5); and reboiler 1140 (200). Maximum flux in reboiler is 31.5 kW/m2 (10,000 Btu/h-ft2). When phase changes occur, use a zoned analysis with appropriate coefficient for each zone. 10. Double-pipe exchanger is competitive at duties requiring 9.3–18.6 m2 (100–200 ft2). 11. Compact (plate and fin) exchangers have 1150 m2/m3 (350 ft2/ft3), and about four times the heat transfer per cut of shell-and-tube units. 12. Plate and frame exchangers are suited to high sanitation services and are 25–50% cheaper in stainless steel construction than shell-and-tube units. 13. Air coolers: Tubes are 0.75–1.00 in. OD., total finned surface 15–20 ft2/ft2 bare surface, U = 450–570 W/m2°C (80–100 Btu/h-ft2 (bare surface)-°F). Minimum approach temperature = 22°C (40°F). Fan input power = 1.4–3.6 kW/(MJ/h) [2–5 hp/(1000 Btu/h)]. 14. Fired heaters: radiant rate, 37.6 kW/m2 (12,000 Btu/h-ft2), convection rate, 12.5 kW/m2 (4000 Btu/ h-ft2); cold oil tube velocity = 1.8 m/s (6 ft/s); approximately equal heat transfer in the two sections; thermal efficiency, 70–75%; flue gas temperature, 140–195°C (250–350°F) above feed inlet; and stack gas temperature, 345–510°C (650–950°F).

INSULATION 1. U  p to 345°C (650°F), 85% magnesia is used. 2. Up to 870–1040°C (1600–1900°F), a mixture of asbestos and diatomaceous earth is used. 3. Ceramic refractories at higher temperatures.

10  Petroleum Refining Design and Applications Handbook Volume 2 4. C  ryogenic equipment −130°C (−200°F) employs insulations with fine pores of trapped air, for example, PerliteTM. 5. Optimum thickness varies with temperature: 12.7 mm (0.5 in.) at 95°C (200°F), 25.4 mm (1.0 in.) at 200°C (400°F), 32 mm (1.25 in.) at 315°C (600°F). 6. Under windy conditions, 12.1 km/h (7.5 miles/h), 10–20% greater thickness of insulation is justified.

MIXING AND AGITATION 1. M  ild agitation is obtained by circulating the liquid with an impeller at superficial velocities of 30.48– 60.9 mm/s (0.1–0.2 ft/s), and intense agitation at 213.4–304.8 mm/s (0.7–1.0 ft/s). 2. Intensities of agitation with impellers in baffled tanks are measured by power input, hp/1000 gal., and impeller tip speeds: Operation

hp/1000 gal.

Tip speed (ft/min)

Tip speed (m/s)

Blending

0.2–0.5

Homogeneous reaction

0.5–1.5

7.5–10

0.038–0.051

Reaction with heat transfer

1.5–5.0

10–15

0.051–0.076

Liquid–liquid mixtures

5

15–20

0.076–0.10

Liquid–gas mixtures

5–10

15–20

0.076–0.10

Slurries

10

3. P  roportions of a stirred tank relative to the diameter D: liquid level = D; turbine impeller diameter = D/3; impeller level above bottom = D/3; impeller blade width = D/15; four vertical baffles with width = D/10. 4. Propellers are made with a maximum of 457.2-mm (18-in.) turbine impellers to 2.74 m (9 ft). 5. Gas bubbles sparged at the bottom of the vessel will result in mild agitation at a superficial gas velocity of 0.0051 m/s (1 ft/min), severe agitation at 0.02 m/s (4 ft/min). 6. Suspension of solids with a settling velocity of 0.009 m/s (0.03 ft/s) is accomplished with either turbine or propeller impellers, but when the settling velocity is above 0.05 m/s (0.15 ft/s) intense agitation with a propeller is needed. 7. Power to drive a mixture of a gas and a liquid can be 25–50% less than the power to drive the liquid alone. 8. In-line blenders are adequate when a second contact time is sufficient, with power inputs of 0.1–0.2 hp/gal.

PARTICLE SIZE ENLARGEMENT 1. Th  e chief methods of particle size enlargement are compression into a mold, extrusion through a die followed by cutting or breaking to size, globulation of molten material followed by solidification, agglomeration under tumbling or otherwise agitated conditions with or without binding agents. 2. Rotating drum granulators have length-to-diameter ratios of 2–3, speeds 10–20 rpm, pitch as much as 10°. Size is controlled by speed, residence time, and amount of binder; 2–5 mm diameter is common. 3. Rotary disk granulators produce a more nearly uniform product than drum granulators: fertilizer, 1.5–3.5 mm diameter; iron ore 10–25 mm diameter. 4. Roll compacting and briquetting is done with rolls ranging from 130 mm diameter by 50 mm wide to 910 mm diameter by 550 mm wide. Extrudates are made 1–10 mm thick and are broken down to size for any needed processing, such as feed to tableting machines or to dryers.

Rules of Thumb—Summary   11 5. T  ablets are made in rotary compression machines that convert powders and granules into uniform sizes. The usual maximum diameter is about 38.1 mm (1.5 in.), but special sizes up to 101.6 mm (4 in.) diameter are possible. Machines operate at 100 rpm or so and make up to 10,000 tablets/min. 6. Extruders make pellets by forcing powders, pastes, and melts through a die followed by cutting. A 203.2-mm (8-in.) screw has a capacity of 907.2 kg/h (2000 lb/h) of molten plastic and is able to extrude tubing at 0.76–1.52 m/s (150–300 ft/min) and to cut it into sizes as small as washers at 8000/min. Ring pellet extrusion mills have hole diameters of 1.6–32 mm. Production rates are in the range of 30–200 lb/h-hp. 7. Prilling towers convert molten materials into droplets and allow them to solidify in contact with an air stream. Towers as high as 60 m (196.9 ft) are used. Economically the process becomes competitive with other granulation processes when a capacity of 200–400 tons/day is reached. Ammonium nitrate prills, for example, are 1.6–3.5 mm diameter in the 5–95% range. 8. Fluidized bed granulation is conducted in shallow beds 304.8–609.6 mm (12–24 in.) deep at air velocities of 0.1–2.5 m/s or 3–10 times the minimum fluidizing velocity, with evaporation rates of 0.005–1.0 kg/m2s. One product has a size range 0.7–2.4 mm diameter.

PIPING 1. L  ine velocities (υ) and pressure drops (∆P): (a) For a liquid pump discharge, υ = (5 + D/3) ft/s and ∆P = 0.45 bar/100 m (2.0 psi/100 ft); (b) For liquid pump suction, υ = (1.3 + D/6) ft/s, ∆P = 0.09 bar/100 m (0.4 psi/100 ft); (c) for steam or gas flow: υ = 20D ft/s and ∆P = 0.113 bar/100m (0.5 psi/ 100 ft), D = diameter of pipe in inches. 2. Gas/steam line velocities = 61 m/s (200 ft/s) and pressure drop = 0.1 bar/100 m (0.5 psi/100 ft). 3. In preliminary estimates set line pressure drops for an equivalent length of 30.5 m (100 ft) of pipe between each of piece of equipment. 4. Control valves require at least 0.69 bar (10 psi) pressure drop for good control. 5. Globe valves are used for gases, control and wherever tight shut-off is required. Gate valves are for most other services. 6. Screwed fittings are used only on sizes 38 mm (1.5 in) or less, flanges or welding used otherwise. 7. Flanges and fittings are rated for 10, 20, 40, 103, 175 bar (150, 300, 600, 900, 1500, or 2500 psig). 8. Approximate schedule number required = 1000 P/S, where P is the internal pressure psig and S is the allowable working stress [about 690 bar (10,000 psi)] for A120 carbon steel at 260°C (500°F). Schedule (Sch.) 40 is most common.

PUMPS 1. P  ower for pumping liquids: kW = (1.67) [Flow (m3/min)] [∆P(bar)]/ε[hp = Flow (gpm) ∆P (psi)/ (1, 714)(ε)]. (ε = fractional efficiency). 2. Net positive suction head (NPSH) of a pump must be in excess of a certain number, depending upon the kind of pumps and the conditions, if damage is to be avoided. NPSH = (pressure at the eye of the impeller-vapor pressure)/(ρg). Common range is 1.2–6.1 m (4–20 ft) of liquid. 3. Specific speed Ns = (rpm)(gpm)0.5/(head in ft)0.75. Pump may be damaged if certain limits of Ns are exceeded, and efficiency is best in some ranges. 4. Centrifugal pumps: Single stage for 0.057–18.9 m3/min (15–5000 gpm), 152 m (500 ft) maximum head; multistage for 0.076–41.6 m3/min (20–11,000 gpm), 1675 m (5500 ft) maximum head. Efficiency: 45% at 0.378 m3/min (100 gpm), 70% at 1.89 m3/min (500 gpm), and 80% at 37.8 m3/min (10,000 gpm). 5. Axial pumps for 0.076–378 m3/min (20–100,000 gpm), 12 m (40 ft) head, 65–85% efficiency. 6. Rotary pumps for 0.00378–18.9 m3/min (1–5000 gpm), 15,200 m (50,000 ft) head, 50–80% efficiency. 7. Reciprocating pumps for 0.0378–37.8 m3/min (10–10,000 gpm), 300 km (1,000,000 ft) maximum head. Efficiency: 70% at 7.46 kW (10 hp), 85% at 37.3 kW (50 hp), and 90% at 373 kW (500 hp).

12  Petroleum Refining Design and Applications Handbook Volume 2

REACTORS 1. Th  e rate of reaction in every instance must be established in the laboratory, and the residence time or space velocity and product distribution eventually must be found from a pilot plant. 2. Dimensions of catalyst particles are 0.1 mm (0.004 in.) in fluidized beds, 1 mm in slurry beds, and 2–5 mm (0.078–0.197 in.) in fixed beds. 3. The optimum proportions of stirred tank reactors are with liquid level equal to the tank diameter, but at high pressures slimmer proportions are economical. 4. Power input to a homogeneous reaction stirred tank is 0.1–0.3 kw/m3 (0.5–1.5 hp/1000 gal.) but three times this amount when heat is to be transferred. 5. Ideal CSTR (continuous stirred tank reactor) behavior is approached when the mean residence time is 5–10 times the length needed to achieve homogeneity, which is accomplished with 500–2000 revolutions of a properly designed stirrer. 6. Batch reactions are conducted in stirred tanks for small daily production rates or when the reaction times are long or when some condition such as feed rate or temperature must be programed in some way. 7. Relatively slow reactions of liquids and slurries are conducted in continuous stirred tanks. A battery of four or five in series is most economical. 8. Tubular flow reactors are suited to high production rates at short residence times (seconds or minutes) and when substantial heat transfer is needed. Embedded tubes or shell-and-tube constructions then are used. 9. In granular catalyst packed reactors, the residence time distribution is often no better than that of a five-stage CSTR battery. 10. For conversions under about 95% of equilibrium, the performance of a five-stage CSTR battery approaches plug flow. 11. The effect of temperature on chemical reaction rate is to double the rate every 10°C. 12. The rate of reaction in a heterogeneous system is more often controlled by the rate of heat or mass transfer than by the chemical reaction kinetics. 13. The value of a catalyst may be to improve selectivity more than to improve the overall reaction rate.

REFRIGERATION 1. A  ton of refrigeration is the removal of 12,700 kJ/h (12,000 Btu/h) of heat. 2. At various temperature levels: −18°C to −10°C (0–50°F), chilled brine and glycol solutions; −45 to −10°C (−50 to −40°F), ammonia, Freon, and butane; −100 to −45°C (−150 to −50°F), ethane or propane. 3. Compression refrigeration with 38°C (100°F) condenser requires kW/tonne (hp/ton) at various temperature levels; 0.93 (1.24) at −7°C (20°F), 1.31 (1.75) at −18°C (0°F); 2.3 (3.1) at −40°C (−40°F); 3.9 (5.2) at −62°C (−80°F). 4. Below −62°C (−80°F), cascades of two or three refrigerants are used. 5. In single-stage compression, the compression ratio is limited to 4. 6. In multistage compression, economy is improved with interstage flashing and recycling, the so-called “economizer operation.” 7. Absorption refrigeration: ammonia to −34°C (−30°F) and lithium bromide to 7°C (45°F) is economical when waste steam is available at 0.9 barg (12 psig).

SIZE SEPARATION OF PARTICLES 1. G  rizzlies that are constructed of parallel bars at appropriate spacings are used to remove products larger than 50 mm in diameter. 2. Revolving cylindrical screens rotate at 15–20 rpm and below the critical velocity; they are suitable for wet or dry screening in the range of 10–60 mm.

Rules of Thumb—Summary   13 3. F  lat screens are vibrated, shaken, or impacted with bouncing balls. Inclined screens vibrated at 600– 7000 strokes/min and are used for down to 38 µm, although capacity drops off sharply below 200 µm. Reciprocating screens operate in the range of 30–1000 strokes/min and handle sizes to 0.25 mm at the higher speeds. 4. Rotary sifters operate at 500–600 rpm and are suited to a range of 12 mm–50 µm. 5. Air classification is preferred for fine sizes because screens of 150 mesh and finer are fragile and slow. 6. Wet classifiers mostly are used to make two product size ranges, oversize and undersize, with a break commonly in the range between 28 and 200 mesh. A rake classifier operates at about 9 strokes/min when making separation at 200 mesh and 32 strokes/min at 28 mesh. Solids content is not critical, and that of the overflow may be 2–20% or more. 7. Hydrocyclones handle up to 600 ft3/min and can remove particles in the range of 300–5 µm from dilute suspensions. In one case, a 20-in. diameter unit had a capacity of 1000 gpm with a pressure drop of 5 psi and a cutoff between 50 and 150 µm.

UTILITIES, COMMON SPECIFICATIONS 1. S team: 1–2 bar (15–30 psig), 121–135°C (250–275°F); 10 barg (150 psig), 186°C (366°F); 27.6 barg (400 psig), 231°C (448°F); 41.3 barg (600 psig), 252°C (488°F) or with 55–85°C (100–150°F) superheat. 2. Cooling water: For design of cooling tower use, supply at 27–32°C (80–90°F); from cooling tower, return at 45–52°C (115–125°F); return seawater at 43°C (110°F); return tempered water or steam condensate above 52°C (125°F). 3. Cooling air supply at 29–35°C (85–95°F); temperature approach to process, 22°C (40°F). 4. Compressed air at 3.1 (45), 10.3 (150), 20.6 (300), or 30.9 barg (450 psig) levels. 5. Instrument air at 3.1 barg (45 psig), −18°C (0°F) dew point. 6. Fuels: gas of 37,200 kJ/m3 (1000 Btu/SCF) at 0.35–0.69 barg (5–10 psig), or up to 1.73 barg (25 psig) for some types of burners; liquid at 39.8 GJ/m3 (6 million British Thermal unit per barrel). 7. Heat-transfer fluids: petroleum oils below 315°C (600°F) Dowtherms below 400°C (750°F), fused salts below 600°C (1100°F), and direct fire or electricity above 232°C (450°F). 8. Electricity: 0.75–74.7 kW (1–100 hp), 220–550 V; 149–1864 kW (200–2500 hp), 2300–4000 V.

VESSELS (DRUMS) 1. 2. 3. 4. 5.

 rums are relatively small vessels to provide surge capacity or separation of entrained phases. D Liquid drums are usually horizontal. Gas/liquid phase separators are usually vertical. Optimum length/diameter = 3, but the range 2.5–5.0 is common. Holdup time is 5 min half-full for reflux drums and gas/liquid separators, 5–10 min for a product feeding another tower. 6. In drums feeding a furnace, 30 min half-full drum is allowed. 7. Knockout drums placed ahead of compressors should hold no less than 10 times the liquid volume passing through per minute. 8. Liquid/liquid separators are designed for a setting velocity of 0.85–1.27 mm/s (2–3 in./min). 9. Gas velocity in gas/liquid separators, υ = k ρL /ρV − 1 m/s (ft/s), with k = 0.11 (0.35) for systems with a mesh deentrainer and k = 0.0305 (0.1) without a mesh deentrainer. 10. Entrainment removal of 99% is attained with 102–305 mm (4–12 in.) mesh pad thickness; 152.5 mm (6 in.) thickness is popular. 11. For vertical pads, the value of the coefficient in step 9 is reduced by a factor of 2/3. 12. Good performance can be expected at velocities of 30–100% of those calculated with the given k; 75% is popular.

14  Petroleum Refining Design and Applications Handbook Volume 2 13. Disengaging spaces of 152–457 mm (6–18 in.) ahead of the pad and 305 mm (12 in.) above the pad are suitable. 14. Cyclone separators can be designed for 95% collection of 5-µm particles, but usually only droplets greater than 50 µm need be removed.

VESSEL (PRESSURE) 1. D  esign temperature between −30 and 345°C is 25°C (−20° F and 650°F if 50°F) above maximum operating temperature; higher safety margins are used outside the given temperature range. 2. The design pressure is 10% or 0.69–1.7 bar (10–25 psi) over the maximum operating pressure, whichever is greater. The maximum operating pressure, in turn, is taken as 1.7 bar (25 psi) above the normal operation. 3. Design pressures of vessels operating at 0–0.69 barg (0–10 psig) and 95–540°C (200–1000°F) are 2.76 barg (40 psig). 4. For vacuum operation, design pressures are 1 barg (15 psig) and full vacuum. 5. Minimum wall thickness for rigidity: 6.4 mm (0.25 in.) for 1.07 m (42 in.) diameter and under, 8.1 mm (0.32 in.) for 1.07–1.52 m (42–60 in.) diameter, and 9.7 mm (0.38 in.) for over 1.52 m (60 in.) diameter. 6. Corrosion allowance 8.9 mm (0.35 in.) for known corrosive conditions, 3.8 mm (0.15 in.) for noncorrosive streams, and 1.5 mm (0.06 in.) for steam drums and air receivers. 7. Allowable working stresses are one-fourth the ultimate strength of the material. 8. Maximum allowable stress depends sharply on temperature Temperature (°F)

−20–650

750

850

1000

(°C)

−30–345

400

455

540

Low-alloy steel, SA 203 (psi)

18,759

15,650

9550

2500

(bar)

1290

1,070

686

273

Type 302 stainless (spi)

18,750

18,750

15,950

6250

(bar)

1290

1290

1100

431

VESSELS (STORAGE TANKS) 1. 2. 3. 4.

 or less than 3.8 m3 (1000 gal.), use vertical tanks on legs. F For 3.8–38 m3 (1000–10,000 gal.), use horizontal tanks on concrete supports. Beyond 38 m3 (10,000 gal.) use vertical tanks on concrete foundations. Liquids subject to breathing losses may be stored in tanks with floating or expansion roofs for conservation. 5. Freeboard is 15% below 1.9 m3 (500 gal.) and 10% above 1.9 m3 (500 gal.) capacity. 6. A 30-day capacity often is specified for raw materials and products but depends on connecting transportation equipment schedules. 7. Capacities of storage tanks are at least 1.5 times the size of connecting transportation equipment; for instance, 28.4-m3 (7500 gal.) tanker trucks, 130-m3 (34,500 gal.) rail cars, and virtually unlimited barge and tanker capacities.



Source: The above mentioned rules of thumb have been adapted from Walas, S.M., Chemical Process Equipment: Selection and Design, copyright 1988 with permission from Elsevier, all rights reserved.

Rules of Thumb—Summary   15 Physical Properties Heuristics. Units

Liquids

Liquids

Gases

Gases

Gases

Water

Organic material

Steam

Air

Organic material

2.0

1.0

2.0–4.0

Heat capacity

kJ/kg °C

4.2

1.0–2.5

Density

kg/m3

1000

700–1500

Latent heat

kJ/kg

1200–2100

200–1000

Thermal conductivity

W/m °C

0.55–0.70

0.10–0.20

0.025–0.07

0.025–0.05

0.02–0.06

Viscosity

kg/ms

0°C 1.8 × 10−3

Wide Range

10–30 × 10−6

20–50 × 10−6

10–30 × 10−6

10–1000

1.0

0.7

0.7–0.8

1.29 at STP

50°C 5.7 × 10−4 100°C 2.8 × 10−4 200°C 1.4 × 10−4 Prandtl no.

1–15

Source: Turton, R. et al., Analysis, Synthesis, and Design of Chemical Process, Prentice Hall International Series, 2001.

Typical Physical Property Variations with Temperature and Pressure. Liquids

Liquids

Gases

Gases

Property

Temperature

Pressure

Temperature

Pressure

Density

ρl  (Tc − T)0.3

Negligible

ρg = MW P/ZRT

ρg = MW P/ZRT

Viscosity

µl = AeB/T

Negligible

Vapor pressure

P* = aeb/(T+c)

–

µgα

T 1.5 (T + 1.47Tb )

–

Significant only for >10 bar –

Note: T is temperature (K), Tc is the critical Temperature (K), Tb is the normal boiling point (K), MV is molecular weight, P is pressure, Z is compressibility, R is the gas constant, and P* is the vapor pressure. Source: Turton, R. et al., Analysis, Synthesis, and Design of Chemical Processes, Prentice Hall International Series, 2001.

Capacities of Process Units in Common Usagea. Process unit

Capacity unit

Maximum value

Minimum value

Comment

Horizontal vessel

Pressure (bar)

400

Vacuum

L/D typically 2–5

Temperature (°C)

400b

−200

Height (m)

10

2

Diameter (m)

2

0.3

L/D

5

2 (Continued)

16  Petroleum Refining Design and Applications Handbook Volume 2 Capacities of Process Units in Common Usagea. (Continued) Process unit

Capacity unit

Maximum value

Minimum value

Comment

Vertical vessel

Pressure (bar)

400

400

L/D typically 2–5

Temperature (°C)

400b

−200

Height (m)

10

2

Diameter (m)

2

0.3

L/D

5

2

Pressure (bar)

400

Vacuum

Normal Limits Diameter

L/D

Temperature (°C)

400b

−200

0.5

3.0–40c

Height (m)

50

2

1.0

2.5–30c

Diameter (m)

4

0.3

2.0

1.6–23c

L/D

30

2

4.0

1.8–13c

Powerd (kW)

250

2500

Square reduction

2

All

D1 D2 NRe

Flow

q

K based on inlet velocity head 4   160   D1   K = 1.2 + − 1    NRe   D2    2   D   D  K = [0.6 + 0.48f D ] 1   1  − 1  D2   D2  

Multiply K from Type 1 by  θ sin   for 45° < θ < 180°  2

Tapered reduction

  θ  Or 1.6 sin    for 0° < θ < 45°  2   3

D1

NRe ≤ 2500

D2 Flow

NRe

NRe > 2500

Thin, sharp orifice

4

NRe ≤ 4000

D2 D1

Flow

NRe

Square expansion

5

All

D2 D1 q

NRe

NRe > 4000

D1

Rounded D2

Re1

Flow

2 4 2    D   4000     D1    D1      K =  2.7 +  1   − − 1 1       D2   NRe     D2    D2   

 D  K = 2 1 −  1    D2 

4

  

2  2   D1      K = [1 + 0.8f D ]  1 −     D2   

If θ >45o, use K from Type 4, otherwise multiply K from Type 4 by

Flow

  θ   2.6 sin    2  

Tapered expansion

6

2 4 2    D   120     D1    D1    K =  2.7 +  1   − 1 − 1  1 −      D2   NRe     D2    D2   

All

4    50   D1   K = 0.1 + 1 − Re1   D2   

Pipe reducer

(Continued)

136  Petroleum Refining Design and Applications Handbook Volume 2 Table 15.12  Excess head loss K correlation for changes in pipe size. (Continued) Type 7

Fitting D1

D2 L

Inlet NRe

K based on inlet velocity head

All

If L/D2 > 5, use Case A and Case F; otherwise multiply K from Case D by:

Flow

    0.0936 0.584 +   1.5   (L/D) + 0.225  

Thick orifice

8

All

D2

Use the K for Case F

D1 Flow

Pipe reducer

Source: (W.B. Hooper [Chem. Eng. Nov. 7, 1988, pp 89–92]).

Then

 v2  h f = K1  1  , ft (m)  2g 



(15.146)

Table 15.12 shows how K varies with changes in pipe size.

15.17.11 Piping Systems The K coefficient values for each of the items of pipe, bends, valves, fittings, contractions, enlargements, entrance/ exits into/from vessels are additive as long as they are on the same size (velocity) basis. Thus the resistance equation is applicable to calculate the head or pressure loss through the specific system when the combined K value is used.



 L   v2  hf = f      D   2g 

(15.117)

 v2  hf = K    2g 

(15.118)

or



where K = summation of all K values in a specific system, when all are on the same size (internal flow) basis. See discussion in “Common Denominator” section (Note: The frictional energy loss, or head loss, is additive even if the velocities change).

15.18 Resistance of Valves Figures 15.9a and 15.9b present several typical valves and connections, screwed and flanged, for a variety of sizes or internal diameters. These do not apply for mixtures of suspended solids in liquids; rather specific data for this situation is required (see [2]). Reference [4] presents data for specific valves.

Fluid Flow  137 Valves such as globes and angles generally are designed with changes in flow direction internally, and thereby, exhibit relatively high flow resistances. These same types of valves exhibit even greater resistances when they are throttled down from the “wide open” position for control of flow to a smaller internal flow path. For design purposes, it is usually best to assume a ½ or ¼ open position, rather than wide open. where K1 = refers to coefficient for smaller diameter K2 = refers to coefficient for larger diameter β = ratio of diameters of smaller to larger pipe size θ = angles of convergence or divergence in enlargements or contractions in pipe systems, degrees. From Reference [4], K values for straight-through valves, such as gate and ball (wide open), can also be calculated. These types of valves are not normally used to throttle flow, but are either open or closed. For sudden and gradual (Note: Sub 1 = smaller pipe; Sub 2 = larger pipe)

K2 = K1/β4

(15.147)

For θ ≤ 45°, as enlargements:

K2 = 2.6[(sin θ/2)(1 − β2)2]/β4

(15.148)

For θ ≤ 45°, as contractions

K2 = [0.8(sin θ/2)(1 − β2)]/β4

(15.149)

For higher resistance valves, such as globes and angles, the losses are less than sudden enlargements or contractions situations. For these reduced seat valves the resistance or loss coefficient K, can be calculated as [4]: At θ ≤ 180°, for sudden and gradual enlargements:

K2 = [(1 − β2)2]/β4

(15.150)

At θ ≤ 180°, for gradual contraction:

K2 = [{0.5(sin θ/2)1/2}(1 − β2)]/β4

(15.151)

The use of these equations requires some assumptions or judgment regarding the degree of opening for fluid flow. Even so, this is better than assuming a wide open or full flow condition, which would result in too low a resistance to flow for the design situation.

15.19 Flow Coefficients for Valves, Cv Flow coefficients (not resistance) for valves are generally available from the manufacturer. The Cv coefficient of a valve is defined as the flow of water at 60°F, in gallons per minute, at a pressure drop of one pound per square inch across the valve [4], regardless of whether the valve ultimately will be flowing liquid or gases/vapors in the plant process (Manufacturers give values of Cg or C1, the coefficient for gas flow, for valves flowing gas or vapor). It is expressed as:

Cv = 29.9 d2/(K)1/2

(15.152)

Cv = Q[ρ/(ΔPc)(62.4)]1/2

(15.153)



Q = Cv[ΔPc(62.4/ρ)]1/2

(15.154)



= 7.90 Cv[ΔPc/ρ]1/2

(15.155)

138  Petroleum Refining Design and Applications Handbook Volume 2



ΔP = [Q/Cv]2[ρ/62.4]

(15.156)

where d = internal pipe diameter, in. Cv = flow coefficient for valves; expresses flow rate in gallons per minute of 60°F water with 1.0 psi pressure drop across valve. K = resistance (loss) coefficient Q = flow rate, gpm ΔP = pressure drop across the control valve, psi ρ = fluid density, lb/ft3

15.20 Flow Meters There are many different types of flow meters that are in use in the petroleum and chemical process industries. One type is the traditional differential pressure (DP) type volumetric flow meters. In many applications, the volumetric flow rate is of direct interest to the operators; because of its accuracy, simplicity and relative lower cost, these flow meters are popular in various facilities. By multiplying the flow rate with the actual density, mass flow rate can be obtained. Pitot tube, orifice meter, Venturi meter, and flow nozzle are classified under this category. Among these, orifice meter is by far the most popular in the chemical process industry (CPI). Figure 15.15 shows the schematics of this meter.

15.20.1 Process Design of Orifice Meter The orifice meter is widely used for flow meter in the refinery and petrochemical industries as compared to the Venturi and other flow meter types. Advantages of the orifice meter are: 1. 2. 3. 4.

 ixed cost is less F Easy to fabricate and install Occupies less space as compared to the Venturi meter Provides more flexibility. Orifice plate can be easily replaced.

Vena Contracta Taps 1 D and − D (Radius) Taps 2

Flange Taps Corner Taps

1”

25.4 mm −12 D

D Direction of flow Orifice plate

Figure 15.15a  Various tap locations for orifice meter.

d

Distance to the mean location of Vena Contracta [Fig. (c)]

D

Fluid Flow  139 0.9 0.8 0.7

β

0.6 0.5 0.4 0.3 0.2 0.1

0.3

0.4

0.5

0.6

0.7

0.8

Figure 15.15b  Pipe diameter from the inlet face of the orifice plate. Extracted from the ASME Meter Computation Handbook, 1961.

1

2 Sharp edged orifice

Flow

Vena contracta

zm

Figure 15.15c  Orifice meter with vena contracta formation.

Flow

D 1

Figure 15.15d  Flow nozzle with differential gauge.

d 2

140  Petroleum Refining Design and Applications Handbook Volume 2 Inlet 1

Throat 2

V1 p1

d

V2

p2

D

Figure 15.15e  Venturi meter.

Drive Coil

Flow of Fluid

Tube Oscillation

RTD for Temperature

Electromagnetic Velocity Detector

Figure 15.15f  Coriolis mass flow meter (source: Micro Motion, Inc. USA).

Disadvantage Power consumption and hence operating cost of orifice meter is higher than the same of Venturi meter and rotameter. In orifice flow meter, as shown in Figure 15.15c, a square edged or sharp-edged orifice plate is mounted between two flanges at the flanged joint. When fluid flows through the orifice, it forms free flowing jet. This free flowing jet first contracts and then expands. The minimum flow area achieved by the free flowing jet is referred to as the vena contracta. The energy balance equation between two points 1 and 2 (Eq. 15.4) is modified Bernoulli equation for steady flow in a pipe with no pump in the section.



P1 α v 12 g P αv 2 g + + z1 = 2 + 2 + z 2 + e f ρ 2g c g c ρ 2g c g c

(15.157)

Consider points 1 and 2 in Figure 15.15c. At point 1 in the pipe, the fluid flow is undisturbed by the orifice plate. The fluid at this point has a mean velocity v1 and a cross-sectional flow area A1. At point 2 in the pipe, the fluid attains its maximum mean velocity v2 and its smallest cross-sectional flow area A2. This point is known as the vena contracta. It occurs at about one half to two pipe diameters downstream from the orifice plate. The location is a function of the flow rate and the size of the orifice relative the size of the pipe. Let the mean velocity in the orifice be vo and let the diameter and cross sectional area of the orifice be do and Ao, respectively. For the steady state of an incompressible fluid of density ρ between points 1 and 2 in a pipe with no pump and friction, and α = 1. Applying the principle of continuity,



Q = ρ v1A1 = ρ v2A2 = ρ voAo Q=

π 2 π π d1 v 1 = d 22 v 2 = d o2 v o 4 4 4

(15.158) (15.159)

Fluid Flow  141

v1 = v 2



A2 A1

(15.160)

Assuming that ef, the frictional energy loss is negligible (i.e., ef = 0), and Rearranging Eq. 15.157 and substituting Eq. 15.160 gives: 2 v 22   A 2   P1 − P2 g 1− = + (z1 − z 2 ) 2g c   A1   ρ gc



(15.161)

Using Eq. 15.159 to substitute for v1 and v2 in Eq. 15.161 gives the velocity vo at the orifice

P − P g  2g c  1 2 + (z1 − z 2 ) gc  ρ  v2 = 2  A   1 −  2     A1  



(15.162)

Or

v2 = where β =

2g{∆h + (z1 − z 2 )}   A 2 1 −  2     A1  

(15.162a)

do diameter of orifice = d1 Inside diameter of pipe

Provided that location 1 is always the upstream pressure tap and location 2 the downstream tap, Eq. 15.162 is applicable for both upward and downward flow, but note that the sign of (z1–z2) will change. The value of ∆P, and consequently ∆h, will be negative for downward flow if the pressures drop due to flow is smaller than the static pressure difference. For horizontal pipe, z1 = z2, the volumetric flow rate Q, through the orifice from Eq. 15.162 is:

Q = Cd v o Ao P − P  2g c  1 2   πd   ρ  = Cd    4  [1 − β 4 ] 2 o





(15.163)

 πd 2  2g c ρ(P1 − P2 ) G = ρQ = Cd  o   4  [1 − β 4 ]

(15.164)

The mass flow rate, G is



where Cd = dimensionless discharge coefficient, which accounts for geometry and friction;

142  Petroleum Refining Design and Applications Handbook Volume 2

1.18

0.725

1.16 d2

d1

Flow

1.14

0.70

1.12

0.675

1.10

0.65

1.08

0.625

1.06

0.60 0.575 0.55

1.04 C=

Cd

0.50 0.45 0.40 0.30 0.20

1.02

1—β4

1.00

Example: The flow coefficient C for a diameter ratio β of 0.60 at a Reynolds number of 20,000 (2 × 104) equals 1.03.

0.98 0.96

Ratio of Nozzle Diameter to Pipe Diameter

d2

d1/d2=β 0.75

C 1.20

d2 2

0.94 0.92

2

4

6 8 104 2 4 6 8 105 2 Re - Reynolds Number based on d2

4

6 8 106

2

Figure 15.16  Flow coefficients “C” for nozzles. C based on the internal diameter of the upstream pipe (source: from Crane [4]).

The flow coefficient C is defined by

C=

Cd 1− β

4



(15.165)

The values of C for orifices and nozzles are shown in Figures 15.16 and 15.17.

15.20.2 Nozzles and Orifices These piping items shown in Figures 15.16 and 15.17 are important pressure drop or head loss items in a system and must be accounted for to obtain the total system pressure loss [4]. For liquids (Note: The ΔP in these equations is NOT a “loss” pressure).



q = C′ A 2g c (144 )(∆P)/ρ = C′ A[2g c h L ]1/ 2

(15.166)

SI units



q = C′ A

2 ∆P = C′ A[2gh L ]1/ 2 ρ

(15.167)

where q = cubic ft/s (m3/s) of fluid at flowing conditions C = flow coefficient for nozzles and orifices



C′ = C d / 1 − β 4 , corrected for velocity of approach

(15.168)

Fluid Flow  143 C 1.3 1.2 d1 β=—=.80 d2 = .75 = .70 = .65 = .60 = .50

1.1 1.0 0.9 0.8 0.7

d2 2

d2

0.6

d1 β=—=.40 d2 = .30 =0 to .20

0.5 0.4 d2

d1

0.3

3 4

6 8 10

20

40 60 80 102

2

4

6 8 103

2

4

6 8 104

Re - Reynolds Number based on d1 Flow

d1/d2=β

0.78

C=

Cd 1—β4

0.74

0.75

0.72

0.725

0.70

0.70

0.68

0.85

0.66

0.60

0.64

0.55 0.50 0.45 0.40 0.30 0.20

0.62 0.60 0.58

2

4

2 6 8 104 2 4 6 8 105 Re - Reynolds Number based on d2

4

Ratio of Orifice Diameter to Pipe Diameter

0.76

6 8 106

Figure 15.17  Flow coefficients “C” for squared-edged orifices (source: Crane [4]).

Note: C = Cd for Figures 15.16 and 15.17, corrected for velocity of approach. Cd = discharge coefficient for nozzles and orifices hL = differential static head or pressure loss across flange taps when C or C values come from Figures 15.16 and 15.17, ft of fluid. Taps are located one diameter upstream and 0.5 diameter down from the device. A = cross-section area of orifice, nozzle, or pipe, ft2 (m2) h = static head loss, ft (m) of fluid flowing   ΔP = differential static loss, lbs/in2. (N/m2) of fluid flowing, under conditions of hL above β = ratio of small to large diameter orifices and nozzles and contractions or enlargements in pipes For discharging incompressible fluids to atmosphere, take Cd values from Figures 15.16 or 15.17 if hL or ΔP is taken as upstream head or gauge pressure. For flow of compressible fluids use the net expansion factor Y (see later discussion) [4]:



q = Y C A[2gc(144)(ΔP)/ρ]1/2

(15.169)

144  Petroleum Refining Design and Applications Handbook Volume 2 SI units,

q = YC′ A



2∆P ρ

(15.170)

where Y = net expansion factor for compressible flow through orifices, nozzles, and pipe. The expansion factor Y is a function of: 1. Th  e specific heat ratio, k 2. The ratio (β) of orifice or throat diameter to inlet diameter of pipe 3. Ratio of downstream to upstream absolute pressures. Y = 1 for liquids = 1 – [((1 – r)/k)(0.41 + 0.35β4)] for gases C P2 , ratio of downstream to upstream pressure k = p , specific heat ratio P1 Cv C = flow coefficient from Figure 15.16 or 15.17. P = inlet gauge pressure (also see critical flow discussion).

where, r =

Standard Location of Pressure Taps The five locations of pressure taps are: (i) Corner taps: Static holes made in upstream and downstream flange. They are very close to the orifice plate. With corner taps, it is possible to drill both static holes in the orifice plate itself. Then entire orifice meter can be easily inserted in any flanged joint without drilling the holes in pipe or flanges. (ii) Flange taps: Static holes made at a distance of 1 in. (25.4 mm) on upstream and 1 in. (25.4 mm) on downstream side. (iii) Radius taps: Static holes located at a distance one pipe diameter on upstream side and ½ pipe diameter on downstream side. Radius taps are best from practical stand point of view as it gives reasonably good pressure difference means more accurate measurement of flow rate. (iv) Vena contracta taps: Upstream static hole is ½ to 2 times pipe diameter from the plate. Downstream tap is located at the position of minimum pressure. Vena contractra taps give the maximum pressure difference for a given flow rate. But it is not suitable, if the orifice size is changed from time to time. (v) Pipe taps: Static holes are located at 2.5 times pipe diameter upstream side and 8 times pipe diameter on downstream side. This means fluid is flowing normally on both sides without being affected by turbulence, created by the orifice plate. For Re > 30,000. Cd = between 0.595 to 0.62 for vena contracta taps. Cd = between 0.595 to 0.8 for radius taps. Cd = 0.62 for corner taps. Stolz has provided relation between discharge coefficient, Cd, β, and ReD by:

C d = 0.5959 + 0.0312β 2.1 − 0.184β8 + 0.0029 β 2.5 (106 / Re D )0.75



+ 0.09L 1 β 4 (1 − β 4 )−1 − 0.0337L 2 β3



(15.170)

Fluid Flow  145 where ReD = Reynolds number based on internal diameter of pipe D

l   l  L1 =  1  , L 2 =  2   D  do 





where β = do/D do = diameter of orifice D = internal pipe diameter l1 = distance of the upstream tapping from the upstream face of all orifice plate, mm l2 = distance of the downstream tapping from the downstream face of the orifice plate, mm. Orifice Problems The classes of problems involving orifices or other obstruction meters that process designers might encounter are similar to the types of problems encountered in pipe flows. These are: 1. U  nknown pressure drop. 2. Unknown orifice diameter. 3. Unknown flow rate. Each involves relationship between the same five basic dimensionless variables, namely: Cd, ReD, β, ∆P/P1, and Y, where Cd represents the discharge coefficient of the meter. For liquids, the variables result to four as Y = 1 by definition. The basic orifice equation relates these variables:

π D2 β 2 YC d  P1 ρ1  G=  1 − β 4  4



Re D =



1/ 2

1/ 2

  P2   2 1 −     P1  

(15.171)

4G d , β= π Dµ D

(15.172)

and Y = f(β, ΔP/P1) Cd = f(β, ReD)

A. Unknown Pressure Drop The pressure drop is determined for a given fluid flow at a given rate through a given orifice. Given: G, µ, ρ, D, d (β = d/D), P1

Find: ∆P

The procedure is as follows: 1.

Calculate ReD, and β = d/D from Eq. 15.172

2.

Get Cd = Co from Figure 15.18 (Continued)

146  Petroleum Refining Design and Applications Handbook Volume 2 (Continued)

3.

Assume Y = 1 and solve Eq. 15.171 for (∆P)1: 2

 4G   1 − β 4  (∆P)1 =     πD2 β 2 C o   2ρ1  4.

(15.173)

Using (∆P)1/P1 and β, get Y from Figures 15.16 and 15.17 or

∆P (0.41 + 0.35β 4 ) for radius taps kP 1 ∆P Y = 1− [0.333 + 1.145(β 2 + 0.7β5 + 12β13 )] for pipe taps kP 1 Calculate ΔP = (ΔP)1/Y2 Y = 1−

5. 6.

(15.174) (15.175) (15.176)

Use the value of ∆P from step 5 in step 4 and repeat steps 4–6 until there is no change. 1.00

β=0.8

0.90

0.75 0.70

Discharge coefficient Co

0.80

β=0.5

0.65 0.60

0.70 β=0.2

0.60

0.30

0.40

0.50 0.40

0.30

0.20 1

2

4 6 8 10 2 4 6 8 102 2 4 6 8103 2 4 6 8 104 2 Bore Reynolds number NRed= NRe /β

4 6 8105

D

Figure 15.18  Orifice discharge coefficient for square-edged orifice and flange, corner, or radius type (From Miller, 1983).

B. Unknown Diameter For design purposes, the proper size orifice (d or β) must be determined for a specified (maximum) flow rate of a given fluid in a given pipe with a ∆P device that has a given maximum range. Given: ∆P, P1, ρ, µ, D, G 1.

2.

Find: d (i.e., β)

Solve Eq. 15.171 for β, i.e.,

 X  β=  1 + X 

14

2

8  G  , X=  ρ1 ∆P  πD2 YC o 

(15.177)

Assume Y = 1, and Co = 0.61 (Continued)

Fluid Flow  147 3.

Calculate Red = ReD/β, and get Co from Figure 15.18 and Y from Figure 15.16 or 15.17 or Eq. 15.174 or 15.175.

4.

Use the results of step 3 in step 1 and repeat steps 1–4 until there is no change. The required orifice diameter d = β D

C. Unknown Flow Rate For an unknown flow rate, the pressure drop across a given orifice is measured for a fluid with known properties, and the flow rate is to be determined. Given: ∆P, P1, D, d (β = d/D), ρ1, µ

Find: G

1.

Using ∆P/P1 and β, get Y from Eq. 15.174 or 15.175 or Figure 15.16 or 15.17

2.

Assume Co = 0.61

3.

Calculate G from Eq. 15.171

4.

Calculate ReD from Eq. 15.172

5.

Using ReD and β, get Co from Figure 15.18

6.

If Co ≠ 0.61, use the value from step 5 in step 3, and repeat steps 3–6 until there is no change.

Example 15.6: Flow measurement by office meter in a vertical pipe Oil of density 850 kg/m3 flows up a vertical pipe section of diameter 230 mm. A manometer filled with fluid density of 1080 kg/m3 is used to measure the pressure drop across an orifice plate with a throat diameter of 80 mm. Determine the flow rate of oil if the deflection of the manometer fluid is 0.5 m. Assume a discharge coefficient, Cd of 0.65 for the orifice.

2 z2 Orifice

1 z1 h

Flow Datum

148  Petroleum Refining Design and Applications Handbook Volume 2 Solution Applying the Bernoulli equation between points 1 and 2

P1 α v 12 g P αv 2 g + + z1 = 2 + 2 + z 2 ρ 2g c g c ρ 2g c g c

or

P1 − P2 g v2 − v2 = (z 2 − z1 ) + 2 1 ρ 2g c gc



For the steady state of an incompressible fluid of density ρ between points 1 and 2 and α = 1. Applying the principle of continuity,



Q = ρ v1A1 = ρ v2A2 = ρ voAo



v1 = v 2

A2 A1

Substituting for v2 and rearranging gives:

P1 − P2 = ρ



g ρ (z 2 − z1 ) + 2g c gc

  A2   1 −      A1  

where gc = 1 (SI units). For the manometer, the pressure balance is:

P1 – P2 = ρg(z2 – z1) + (ρm – ρ)g h The theoretical velocity through the orifice is:



2 ρv o2   A o   1−  = (ρm − ρ)gh 2   A1  

vo = where



β=

d o 80 = = 0.348 d1 230

2gh(ρm − ρ)   A 2 ρ 1 −  o     A1  

Fluid Flow  149

2gh(ρm − ρ) ρ[1 − β 4 ]

vo =

2 × 9.81 × 0.5 × (1080 − 850) 850[1 − 0.3484 ]

=

= 1.641 m/s.





Note: that this expression does not contain the terms in z. The velocity and therefore flow rate are independent of the orientation of the pipe. The actual flow rate is:

Q = Cd Ao v o π 0.082 × 1.641 4 = 5.3 × 10−3 m3 /s. = 0.65 ×



Example 15.7: Design an orifice for a compressible flow on the following data Name of fluid:

Chlorine gas

Flow rate, G:

2000 Nm3/h

Operating pressure, P:

1.5 atm a

Operating temperature, T:

30°C

Viscosity of Cl2 at 30oC, µ:

0.0145 mPa.s or cP

Inside diameter of pipe, ID:

154.0 mm (6 in. Sch. 40)

Specific heat ratio of Cl2 gas, k:

1.33

Molecular weight, Mw

71

Solution Let β = 0.5

β=



do or d o = 77 mm D

Density of chlorine gas at normal condition at 25°C (298K):

ρ=

m P • M w 101.325(71) = = v RT (8.314 )(298)

= 2.904 kg /m3 Mass flow rate, G = 2000 × 2.904 = 5808 kg/h



150  Petroleum Refining Design and Applications Handbook Volume 2 Reynolds number, ReD is:

 kg 4G 4 × (5808/3600) 1 1 h = × ×   × −3 kg π (ID)µ π × 0.154 × 0.0145 × 10 m s h   ms   = 919, 910 (Turbulent flow )

Re D =





If corner taps are made, then l1 = l2 = 0 Coefficient of orifice meter can be determined by Stolz’s equation as:

C d = 0.5959 + 0.0312β 2.1 − 0.184β8 + 0.0029 β 2.5 (106 / Re D )0.75 + 0.09L1 β 4 (1 − β 4 )−1 − 0.0337L 2 β3  106  = 0.5959 + (0.0312 × 0.5 ) − (0.184 × 0.5 ) + (0.0029 × 0.5 )  919910  2.1



8

= 0.6030



Expansion factor Y: Y = 1 for liquids = 1 − [((1 – r) / k)(0.41 + 0.35β4)] for gases For the first trial calculation, let r = 0.8, Y = 0.9362 The mass flow rate G, of chlorine gas:

π 2g c ∆p ρ G = C d Y d o2 4 (1 − β 4 )





Density of chlorine gas at operating condition:

ρ=



151.95 × 71 (8.314 )(303)

= 4.283 kg /m3



5808 π 2 × 1 × ∆p × 4.283 = 0.6030 × 0.9362 × (0.077 )2 3600 4 (1 − 0.54 )



Δp = 41.22 kPa Δp = p1 – p2 or p2 = p1 –Δp = (1.5 × 101.325) – 41.22 p2 = 110.77 kPa

0.75

2.5

r=

=

P2 , ratio of downstream to upstream pressure P1

110.77 = 0.7288 151.99

(15.170)

Fluid Flow  151 25'

T-1 90psig 4" pipe

V-1 80 psig

100 '

3' 10'

10'

5'

20'

6" pipe

5'

3' 20'

25' Pump

2 1

Figure 15.19  Piping layout for Example 15.8.

Y = 1 − [((1 − r )/ k )(0.41 + 0.35β 4 )]



 1 − 0.7288   (0.4319) = 1 −    1.355   = 0.9136 ∆p ∝

1 or ∆p1 Y12 = ∆p2 Y22 2 Y

Y  ∆p2 = ∆p1  1   Y2 

2

 0.9362  = 41.22   0.9136 



= 43.28 kPa

2



Δp2 = 43.28 kPa = 173.75 in. H2O (4.4 m H2O) For the different variations in the flow rate, Δp can be determined and a differential pressure (DP) transmitter having a range of 4500 mm WC range can be selected. Example 15.8: Calculation of Pressure at Points in System Figure 15.19 shows the layout of a system in which light naphtha is pumped from tank V-1 to tower T-1 by pump P-1. The suction pressure and discharge pressure at the pump, points 1 and 2, respectively, are required. If the pump efficiency is 70%, calculate the hydraulic and brake horsepower for the pump.

152  Petroleum Refining Design and Applications Handbook Volume 2 The following data apply: Fluid: light naphtha, 86.2oAPI at 60°F, Kw = 11.8*. Flow rate 500 gpm measured at 60°F Pumping temperature: 106°F Piping: Schedule 40. Fittings are standard welding-type. Valves are flanged type. *

Specific gravity at 60/60°F = 0.650 Specific gravity at 106/60°F = 0.625 Density at 106°F: (0.625) (62.4) = 39.0 lb/ft3 Viscosity at 106°F = 0.17cSt = (0.17) (0.625) = 0.106cP Flow at 106°F = (500) (0.65/0.625) = 520 gpm Pipe and fittings

Suction side (6 in.)

Discharge side (4 in.)

Straight length of Pipe, ft

10 + 20 + 20 + 25 = 75

25 + 5 + 3 + 10 + 3 + 5 + 100 + 25 = 176

Gate valves

2

2

90° elbows

3

7

Check valves (swing)

–

1

Exit from tank

1

–

Entrance to tank

–

1

Solution Applying the first law of thermodynamics (conservation of energy) between upstream point V and downstream point 1 gives

Pv g v2 P g v + z v + v = 1 + z1 + 1 + e f + w − q ρ gc 2g c ρ g c 2g c

Assuming w = q = 0

(

)

v2 − v2 lb − ft P1 Pv g = + (z 2 − z1 ) + v 1 − e f , f lbm ρ ρ gc 2g c



Applying the changes in pressure head using Table 15.1 gives the following. 1. Pressure head at starting point V-1.

lbf • ft lbm

Pv = 80 + 14.7 = 94.7 psia ρ (Continued)

*Kw is the characterization factor for the naphtha. It is used in evaluating properties of naphtha.

Fluid Flow  153  in 2 lb Pv 94.7 1 = × 144  2 • f2 • ρ 39  ft in lbm  ft 3  2. Velocity head term,

    

349.66

v 2v − v 12 2g c

For 6 in. Schedule 40 pipe, ID = 6.065 in. Large tank, V-1, therefore velocity at V-1 is negligible, vv = 0 Q 6.065 , ID, ft = = 0.5054 ft. A 12 π(ID)2 π(0.5045)2 A= = = 0.2006 ft 2 4 4 v1 =

v1 =

 gal 1 520 1 min  • 2• •   = 5.78 ft./s 0.2006 × 7.48 × 60  min ft gal s    ft 3  

2 2 2  2  Velocity head, v V − v 1 = 0 − (5.78)  ft • 1 • 1  = −0.519 2 2g c 2 × 32.174  s lbm ft   lbf s 2  

−0.519

Since the velocity head is higher at point 1 than at starting point V-1, therefore the pressure head is decreased g  lb ft  3. Static head term (z v − z1 ) ,  f  g c  lbm  g ≈1.0 gc zv = 3 + 10 + 25 = 38

38

Downstream point 1, is lower than starting point V- 1; therefore, the pressure head is increased

lbf • ft lbm

4. Frictional loss term, ef Reynolds number, Re 50.6 Q ρ Re = dµ =

50.6(520)(39) = 1596180 (6.065)(0.106)

= 1.6 × 106 (Turbulent flow ) Pipe roughness, ε = 0.0018 in. Relative pipe roughness, ε = 0.0018 = 0.000296 d 6.065 From Moody chart (Figure 15.5), fD = 0.0152

 L Resistance coefficient due to friction, Kf: K f = f D    d Total pipe length at suction side L = 10 + 20 + 20 + 25 = 75ft. (Continued)

154  Petroleum Refining Design and Applications Handbook Volume 2 (Continued)  75 × 12  K f = 0.0152  = 2.26  6.065  Total KTotal = 3.74 K Total

−1.94

 lb ft  (5.78)2 v 12 = 3.74 = 1.94  f  2g c 2(32.174 )  lbm 

Frictional loss term, ef is in the direction of flow, therefore the pressure head is decreased. P1 , pressure head at point 1 = ρ 385.181

 lb ft  = 349.66 − 0.519 + 38 − 1.94 = 385.181  f   lbm  P1 =

385.181 × 39  lbf ft lbm ft 2  • 3 • 2  144  lbm ft in 

= 104.319 psia (89.62 psig )

Pipe Fittings at the Suction side The loss coefficient K for a straight pipe

 L K = fD    D



(15.106)

Using Darby’s 3-K method (Eq. 15.139)

 K1 K  + K i  1 + 0 ,d3  Re  Dn ,in . 

Kf =





Outside diameter of a 6” pipe Sch. 40, Dn = 6.0 in.



Re = 1.6 × 106 Using Darby’s 3-K Method (from Table 15.11b) Fittings

N

K1

nK1

Ki

nKi

Kd

Kf

Gate valve

2

300

600

0.037

0.074

3.9

0.243

90° Elbows(r/D = 1.5)

3

800

2400

0.071

0.213

4.2

0.737

Exit from tank

1

Kf = (160/Re + K∞)

Total

K∞ = 0.5

0.5 1.48

Fluid Flow  155 Applying the first law of thermodynamics (conservation of energy) between upstream point 2 and downstream point T gives

P2 g v2 P g v + z 2 + 2 = T + z T + T + ef ρ g c 2g c ρ g c 2g c



(

)

v T2 − v 22 P2 PT g lb • ft = + (z T − z 2 ) + + ef , f ρ ρ gc 2g c lbm

5. Pressure head at starting point T-1.

lbf • ft lbm

PT = 90 + 14.7 = 104.7 psia ρ  in 2 lb PT 104.7 1 = × 144  2 • f2 • ρ 39  ft in lbm  ft 3 

    

386.58

2 2 6. Velocity head term, v T − v 2 2g c

For 4 in. Schedule 40 pipe, ID = 4.026 in. Large tank, T-1, therefore velocity at T-1 is negligible, vT = 0

lbf • ft lbm

Q 4.026 , ID, ft = = 0.3355 ft. A 12 π(ID)2 π(0.3355)2 A= = = 0.0884 ft 2 4 4 v2 =

 gal 1 520 1 min  • 2• •   gal 0.0884 × 7.48 × 60  min ft s    ft 3   = 13.106 ft./s

v2 =

Velocity head ,

v 2T − v 22 0 − (13.106)2  ft 2 1 1  = •  2•  2g c 2 × 32.174  s lbm ft   lbf s 2   = −2.67

−2.67

Since the velocity head is higher at point 2 than at starting point T-1, therefore the pressure head is decreased. g  lb ft  7. Static head term (z T − z 2 ) ,  f  g c  lbm  g ≈1.0 gc (Continued)

156  Petroleum Refining Design and Applications Handbook Volume 2 (Continued)

zv = 25 + 100 = 125

125

Downstream point 2, is lower than starting point T- 1; therefore, pressure head is increased 8. Frictional loss term, ef Reynolds number, Re Re = =

50.6 Q ρ dµ 50.6(520)(39) = 2404578 (4.026)(0.106)

= 2.4 × 106 (Turbulent flow ) Pipe roughness, ε = 0.0018 in. Relative pipe roughness,

ε 0.0018 = = 0.00045 d 4.026

lbf • ft lbm

From Moody chart (Figure 15.5), fD = 0.0164 Resistance coefficient due to friction, Kf:  L K f = fD    d Total pipe length at discharge side L = 25 + 5 + 3 + 10 + 3 + 5 + 100 + 25 = 176 ft.  176 × 12  K f = 0.0164  = 8.603  4.026  Total KTotal = 13.419

K Total

 lb ft  v 22 (13.106)2 = 13.419 = 35.820  f  2g c 2(32.174 )  lbm 

35.82

Frictional loss term, ef is counter to the direction of flow, therefore, pressure head is increased P2 , pressure head at point 2 = ρ  lb • ft  = 386.58 − 2.67 + 125 + 35.82 = 544.73  f   lbm  P2 =

544.73 × 39  lbf ft lbm ft 2  • 3 • 2  144  lbm ft in 

= 147.53 psia (132.83 psig )

544.73

Fluid Flow  157 Pipe Fittings at the discharge side The loss coefficient K for a straight pipe (Eq. 15.105)

 L K = fD    D

Using Darby’s 3-K method (Eq. 15.139)

 K1 K  + K i  1 + 0 ,d3  Re  Dn ,in . 

Kf =





Pipe Fittings at the Discharge side Outside diameter of 4” pipe Sch. 40, Dn = 4.0 in.



Re = 2.4 × 106 Using Darby’s 3-K Method (from Table 15.11b) Fittings

n

K1

nK1

Ki

nKi

Kd

Kf

Gate valve

2

300

600

0.037

0.074

3.9

0.265

90° Elbows (r/D = 1.5)

7

800

5600

0.071

0.497

4.2

1.876

Check valve

1

1500

1500

0.46

0.46

4

1.675

Entrance to tower

1

1.0

Total

4.816

Pressure drop across the pump

ΔPpump = P2 – P1 = 132.83 – 89.62 = 43.21 psi The hydraulic horse power, hp =

Brakehorse power, Bhp

Q ∆Ppump (520)(43.21) = = 13.11 hp 1714 1714

Hydraulic horsepower , hp 13.11 = = 18.7 Bhp Pump efficiency , η 0.7

Excel program (Example 15.8.xlsx gives the solution of Example 15.8). Example 15.9: Case Study Figure 15.20a shows the piping and instrumentation diagram (P&ID) of a crude distillation unit, debutanizer section, and Figure 15.20b further illustrates the debutanizer column C-1007, overhead gas line 8”-P10170-3101C-P to an air cooler condenser E-1031, accumulator V-1008, reflux pump P1017A/B, suction line 8”-P10174-3101C, and discharge line 6”-P10176-3101C, respectively. The operating pressure of the debutanizer C-1007 is 16.59 barg. The condensates from E-1031 are collected in the debutanizer accumulator V-1008 and separated from sour water, which is returned to vessel V-1002. The liquefied petroleum gas (LPG) from the accumulator V-1008 operating at 12.69 barg is refluxed to the top of the debutanizer, C-1007 via a centrifugal pump P1017A/B. Determine the frictional losses (ΔPf ) of both the suction and discharge of pump P-1017 A/B carrying liquefied petroleum gas (LPG) at 1432.2 tons/day from the accumulator vessel V-1008 to the suction of pump P1017 A/B,

3”

LO

SPL 10 FH.1

6”

10 TI 248

V

10 FT 85

10 FRCS 95

8”

6”

8”

D

D

10 PdIC 8

4”

10 HX 75

10 TI 267

1”

10 TW 34

10 TW 33

¾“

FROM 12-LRC-5 ON LP SEPARATOR V-1202 IN HDS UNIT 1200 DRG. T.1.487.144

10 X 113

8”-P10150-3101

6”

4”

3”

3101 3123 4”

8“-P10150-3101

E-1028A

10 TW 30

E-1028B

E-1028C

8“

V

10 TI 266

RATIO

10 TW 29

D

10 FH 80

2”

UL

10 P1 141

DRG. T.1.487.144 VIA. T.1487.793

V

10 TW 32

10 TI 253

10 P1 153

10 HX 71

UC 2”

M

I ST

1 atmosphere)

0.5

Leads to exhaust header 4. Relief valve discharge Relief valve, entry point at silencer

1.5 0.5 vs vs

180  Petroleum Refining Design and Applications Handbook Volume 2 are much different from the velocities below the speed of sound. The ratio of the actual fluid velocity to its speed of sound is called the Mach number [27]. The velocity of sound at 68°F in air is 1126 ft/s. For any gas, the speed of sound is:

v s = kgp′′/ρ , ft /s



(15.184)

where k = ratio of specific heat of gas, at constant pressure to that at constant volume, = Cp/Cv (See Table 15.14) g = 32.2. ft/s2 p = pressure, pounds per sq ft, abs (Psfa) (note units) ρ = the specific weight, lb/ft3 at T and p Table 15.14  Approximate k values for some common gases (68°F, 14.7psia). Gas

Chemical formula or symbol

Approximate molecular weight

k(Cp/Cv)

Acetylene (ethyne)

C2H2

26.0

1.30

Air

–

29.0

1.40

Ammonia

NH3

17.0

1.32

Argon

A

39.9

1.67

Butane

C4H10

58.1

1.11

Carbon dioxide

CO2

44.0

1.30

Carbon monoxide

CO

28.0

1.40

Chlorine

Cl2

70.9

1.33

Ethane

C2H6

30.0

1.22

Ethylene

C2H4

28.0

1.22

Helium

He

4.0

1.66

Hydrogen chloride

HCl

36.5

1.41

Hydrogen

H2

2.0

1.41

Methane

CH4

16.0

1.32

Methyl chloride

CH3Cl

50.5

1.20

Natural gas

–

19.5

1.27

Nitric oxide

NO

30.0

1.40

Nitrogen

N2

28.0

1.41

Nitrous oxide

N 2O

44.0

1.31

Oxygen

O2

32.0

1.40

Propane

C3H8

44.1

1.15

Propylene (propene)

C3H6

42.1

1.14

Sulfur dioxide

SO2

64.1

1.26

Fluid Flow  181 In SI units

v s = γ P′ /ρ



(15.185)

This sonic velocity occurs in a pipe system in a restricted area (for example, valve, orifice, venturi) or at the outlet end of the pipe (open-ended), as long as the upstream pressure is high enough. The physical properties in the above equations are at the point of maximum velocity. With a high velocity vapor flow, the possibility of attaining critical or sonic flow conditions in a process pipe should be investigated. These occur whenever the resulting pressure drop approaches the following values of ΔP as a percentage of the upstream pressure [6] where the properties are evaluated at the condition of sonic flow. This applies regardless of the downstream pressure for a fixed upstream pressure. This limitation must be evaluated separately from pressure drop relations, as it is not included as a built in limitation. Sonic velocity will be established at a restricted point in the pipe, or at the outlet, if the pressure drop is great enough to establish the required velocity. Once the sonic velocity has been reached, the flow rate in the system will not increase, as the velocity will remain at this value even though the fluid may be discharging into a vessel at a lower pressure than that existing at the point where sonic velocity is established. ΔP can be increased by continuing to lower the discharge pressure. But no additional flow rate will result. The usual pressure drop equations do not hold at the sonic velocity, as in an orifice. Conditions or systems exhausting to atmosphere (or vacuum) from medium to high pressures should be examined for critical flow, otherwise the calculated pressure drop may be in error. All flowing gases and vapors (compressible fluids) including steam (which is a vapor) are limited or approach a maximum in mass flow velocity or rate, i.e., lb/s or lb/h (kg/s or kg/h) through a pipe depending upon the specific upstream or starting pressure. This maximum rate of flow cannot be exceeded regardless of how much the downstream pressure is further reduced. The mean velocity of fluid flow in a pipe by continuity equation is [4]:



v=

0.0509 WV 0.0509 W or , ft /s d2 ρd 2

(15.186)

v=

354 W V 354 W , m/s or v = 2 d ρd 2

(15.187)

In SI units



where d = internal pipe diameter, in. (mm) W = rate of flow, lb/h (kg/h) V = specific volume of fluid, ft3/lb (m3/kg) ρ = fluid density, lb/ft3 (kg/m3) This maximum velocity of a compressible fluid in a pipe is limited by the velocity of propagation of a pressure wave that travels at the speed of sound in the fluid [4]. This speed of sound is specific for each individual gas or vapor and is a function of the ratio of specific heats of the fluid. The pressure reduces and the velocity increases as the fluid flows downstream through the pipe, with the maximum velocity occurring at the downstream end of the pipe. When or if the pressure drop is great enough, the discharge or exit or outlet velocity will reach the velocity of sound for that fluid. If the outlet or discharge pressure is lowered further, the pressure upstream at the origin will not detect it because the pressure wave can only travel at sonic velocity. Therefore, the change in pressure downstream will not be detected upstream. The excess pressure drop obtained by lowering the outlet pressure after the maximum discharge has been reached takes place beyond the end of the pipe [4]. This pressure is lost in shock waves and turbulence of the jetting fluid. See References [26], [28], and [29] for further expansion of shock waves and detonation waves through compressible fluids. In the case of a high pressure header, the flow may be sonic at the exit. Therefore, it is often necessary to check that the outlet pressure of each pipe segment is not critical. If Pc is less than terminal P2, the flow is subcritical. If however,

182  Petroleum Refining Design and Applications Handbook Volume 2 Pc is greater than P2, then the flow is critical. Although, it may be impractical to keep the flow in high pressure subheaders below sonic, Mak [30] suggests that the main flare header should not be sized for critical flow at the outlet of the flare stack. This would obviate the undesirable noise and vibration resulting from sonic flow. The equation for critical pressure can be expressed as:

 RT  Pc =   2 11400d  k[k + 1] G



1/2

, psia

(15.188)

or

 ZG  T  Pc = 2.45 × 10−3  2    d   k M w 



0.5



(15.189)

 1544  R= , molar gas constant  29 Sp. Gr 

(15.190)

where





Sp. Gr . =

Molecular weight of gas Molecular weight of air

Z = compressibility factor d = internal pipe diameter, in. Mw = fluid molecular weight. G = fluid flow rate, lb/h. T = fluid temperature, °R ρ = fluid density, lb/ft3

15.24.4 The Mach Number, Ma The Mach number, Ma is the velocity of the gas divided by the velocity of the sound in the gas and can be expressed as:



Ma = v/vs

(15.191)

The exit Mach number for compressible isothermal fluid has been shown to be Ma ≠ 1, but 1/ k , where k, is the ratio of the fluid specific heat capacities at constant pressure to that at constant volume. Table 15.14 shows the k values for some common gases. The following cases are such: 1. Ma 1/ k , the flow is supersonic

(15.191C)

Case 3 is produced under certain operating conditions in the throttling processes (e.g., a reduction in the flow cross-sectional area). Kirkpatrick [33] indicates that there is a maximum length for which continuous flow is applied for an isothermal condition, and this corresponds to Ma = 1/ k . The limitation for isothermal flow, however, is the heat transfer required to maintain a constant temperature. Therefore, when Ma 1/ k , heat must be rejected from the stream. Depending on the ratio of specific heats, either condition could occur with subsonic flow. Therefore, to maintain isothermal flow during heat transfer, high temperatures require high Mach numbers and low temperatures require low Mach numbers.

Flow Rate of Compressible Isothermal Flow The flow rate of compressible fluids and pressure drop of compressible isothermal flow are based on the following assumptions [31]: 1. 2. 3. 4. 5.

I sothermal compressible fluid. No mechanical work done on or by the system. The gas obeys the perfect gas laws. A constant friction factor along the pipe. Steady state flow or discharge unchanged with time.

The derivation is provided elsewhere [6, 30], and the maximum flow rate through the pipe is: 0.5

   P12 − P22   A 2ρ1 g c G =     P1    P1    K + 2 ln     Total   P2    



(15.192)

where KTotal is the total resistance (loss) coefficient due to friction, fittings and valves:



K Total = f D

L + ∑ K f ( pipe fittings + valves) D

(15.193)

∑ K f ( pipe fittings + valves) is the sum of the pressure loss coefficient for all the fittings and valves in the line. Expressing the maximum fluid rate in pounds per hour, Eq. 15.192 becomes

   P12 − P22   ρ1 G = 1335.6 d    P1    P1    K + 2 ln     Total   P2   2



0.5 , lb/h

(15.194)

In SI units 0.5



2 2    ( p1′ ) − ( p′2 )   ρ1 −4 2   G = 2.484 × 10 d     , kg /s p1′  p1′       K Total + 2 ln  p′    2  

where d = pipe internal diameter, mm ρ1 = upstream gas density, kg/m3 p1′ = upstream gas pressure, bara p′2 = downstream gas pressure, bara

(15.195)

184  Petroleum Refining Design and Applications Handbook Volume 2

Pipeline Pressure Drop (ΔP)

P  If ΔP due to velocity acceleration is relatively small compared with the frictional drop, then ln  1  may be neglected.  P2  Therefore Eq. 15.194 becomes 0.5

 ρ1  P12 − P22   G = 1335.6 d   P   K 1  Total 



2



(15.196)

Putting C = 1335.6d2

(15.197)

G2 ρ1 P12 − P22 = C 2 K Total P1



(15.198)

That is,



P12 − P22 =

P1 G 2 K Total ρ1 C 2

(15.199) 0.5

 2 P1G 2K Total  P2 = P1 −  2 C ρ 1  



(15.200)

Therefore, the pressure drop

ΔP ≅ P1 – P2

(15.201)

i.e. 0.5

 P G 2K Total  ∆P ≅ P1 − P12 − 1  ρ1C 2  



(15.202)

In SI units 0.5





2 2    ( p1′ ) − ( p′2 )   ρ1 −4 2   G = 2.484 × 10 d    p1′  p1′       K Total + 2 ln  p′    2  

Putting C1 = 2.484 × 10−4 d2

(15.203)

(15.204)

G2 ρ1 P12 − P22 = C12 K Total P1

(15.205)

That is,



P12 − P22 =

P1 G 2 K Total ρ1 C12

(15.206) 0.5



 P G 2K Total  P2 = P12 − 1  ρ1C12  

(15.207)

Fluid Flow  185 Therefore, the pressure drop

ΔP ≅ P1 – P2

(15.208)

That is 0.5

 2 P1G 2K Total  ∆P ≅ P1 − P1 −  2 ρ C 1 1  



(15.209)

Janettt [32] shows how the back pressure in vent lines are calculated for compressible fluids. Table 15.15 shows the conditions at the pipe exit as a function of the Mach number. Ma1

Ma2

Ma = 1

d

L2

L1

The hypothetical Pipe length, L2 is such that its inlet Ma2 is the same as the exit from the actual pipe



Table 15.15  Conditions at the pipe exit as a function of the Mach number. Isothermal flow

Adiabatic flow

P = ρ × constant

1 G2 k P + = constant 2 ρ2 ( k − 1) ρ

Subsonic flow P2

P1 × Ma1/Ma2

T2

T1

ρ2

ρ1 × Ma1/Ma2

v2

v1 × Ma2/Ma1

2 + ( k − 1)Ma12 2 + ( k − 1)Ma 22

P1

Ma1 Ma 2

T1

2 + ( k − 1) Ma12 2 + ( k − 1) Ma 22

ρ1

Ma1 Ma 2

2 + ( k − 1) Ma 22 2 + ( k − 1) Ma12

v1 × ρ1/ρ2

Critical or sonic flow P2

P1 × Ma1 × k

T2

T1

ρ2

ρ1 × Ma1 × k

v2

v s/ k

P1 Ma1 T1

2 + ( k − 1) Ma12 ( k − 1)

ρ1 Ma1 vs

2 + ( k − 1)Ma12 k +1

( k + 1) 2 + ( k − 1) Ma12

186  Petroleum Refining Design and Applications Handbook Volume 2 Example 15.13 Case Study The vapor (C3, C4, and C5) from the debutanizer unit C1007 in Figure 15.20 is cooled via an air cooler E-1031 to the accumulator V1008. The overhead gas line 8”—P10170-3101C-P is 84.7 m long, and the debutanizer boil-up rate is 17 kg/s (1738 m3/h), which operates at 17.6 bara at the top. Calculate the pressure drop along the 8-in. pipe to the air cooler condenser E-1031. Other data obtained from the piping isometrics, piping data sheets and fluid characteristics are: Operating temperature = 86°C Fluid density = 35.2 kg/m3 Ratio of specific heats γ = (Cp/Cv) = 1.11 Kinematic viscosity = 0.2 cSt. = 0.2 × 10−6 m/s2 Fittings

Number

90° Ell (r/R = 1.5)

5

Ball valve

2

Tee (straight Thru)

3

Solution Dynamic viscosity = Density × Kinematic viscosity = 35.2 × 0.2 × 10−6 = 0.00704 × 10−3 kg/m.s = 0.00704 cP. The average molecular weight of the overhead vapor is: Composition

Molecular weight kg/kmol

Percentage in the vapor phase, %

Average molecular weight

C3H8

44

18.00

7.92

C4H10

58

80.00

46.4

C5H12

72

2.00

1.44

100.00

55.76

Total

Assume compressibility factor Z = 0.958 An 8 in. pipe size Sch. 40 (ID = 202.7 mm) Friction factor fT for 8 in. Schedule 40 CS material = 0.014. Assuming that the flow condition of the vapor through the 8-in. pipe is isothermal. Area of pipe



A = π(ID)2/4



= π(.2027)2/4



= 0.0323 m2 The velocity of gas in the line is:



G = ρ V A

Fluid Flow  187 where A = pipe area, m2 G = mass flow rate, kg/s v = fluid velocity, m/s ρ = fluid density, kg/m3 or

v = G/(ρA) 17 (35.2 × 0.0323) = 14.95 m/s =





Sonic velocity of vapor in the line is (Eq. 15.183):

v s = ZγRT m/s

  J 1  8314  = (0.958)(1.11) (359.15) ,  kmol − K • kg • K  = m/s   55.76    kmol  = 238.63 m/s



The inlet Mach number Ma1 is (Eq. 15.191)

Ma1 =



v 14.95 = v s 238.63

= 0.0626



Therefore, the flow of gas through the pipe is subsonic, since the inlet Mach number is less than 1. Gas Reynolds number is:

Re = 354

W dµ

(354 )(17 )(3600) (202.7 )(0.00704 ) = 15,181975 (Fully turbulent ) =

(15.28)

= 1.52 × 107

Relative pipe roughness is:



ε 0.046 = = 0.000227 D 202.7  ε  1 5.02 = −4 log  − log A   3.7 D Re  fC

(15.35)

188  Petroleum Refining Design and Applications Handbook Volume 2 where

ε/D  6.7  A= +  3.7  Re 

0.9

 0.000227  6.7 A= +  15,181, 975  3.7



0.9

= 6.3657 × 10−5



 0.000227  5.02 = −4 log  − log(6.3657 × 10−5 ) 15,181, 975  3.7  fC

1

= 16.8884 fC = 0.003506



The Darcy friction factor fD = 4 fC

fD = 4 (0.003506)

= 0.01402 Using Darby’s 3-K method (Eq. 15.140) 0.3   25.4   K1 Kf = + Ki  1 + Kd   Re  Dn ,mm   





Re = 15,181975 (turbulent) Pipe outside diameter of 8”, Dn = 203.2 mm Fittings

n

K1

nK1

Ki

nKi

Kd

Kf

90° Ell (r/D = 1.5)

5

800

4000

0.071

0.355

4.2

1.1543

Ball valve

2

300

600

0.017

0.034

4.0

0.1069

Tee (straight thru)

3

800

2400

0.14

0.42

4.0

1.3204

Total

2.5816

Total loss coefficient KTotal:



K Total = f D

L + ∑Kf : D

Pipe length, L = 84.7 m Diameter, d = 202.7 mm



K Total = 0.0140 × = 8.4316

84.7 + 2.5816 0.2027

Fluid Flow  189 Outlet pressure P2 is (Eq. 15.207): 0.5

 2 P1G 2K Total  P2 = P1 −  ρ1C12  

where



C1 = 2.484 × 10−4 d2



G2 17 2 = = 2.774 C12 (2.484 × 10−4 × 202.7 2 )2  P G 2K Total  P2 = P12 − 1  ρ1C12  

0.5

 (17.6)(2.7774 )(8.4316)  =  17.62 −   35.2

0.5

= 17.265 bara





Therefore, the pressure drop



ΔP = P1 – P2



= 0.34 bar The process is assumed to be isothermal, therefore outlet temperature, T2 is:

T2 = T1 , K T2 = 86 °C



= (273.15 + 86)K = 359.15 K



Density of the vapor at the exit is

105 P2 , kg /m3 ρ2 = (R /M w )T2 (105 )(17.26) ρ2 = (8314 /55.76)(359.15) = 32.23 kg /m3





Flow velocity at pipe exit is

v = G/(ρ A)

17 (32.23 × 0.0323) = 16.33 m / s =



190  Petroleum Refining Design and Applications Handbook Volume 2 The exit Mach number Ma 2 = 1/ k



Ma 2 = 1/ 1.11 = 0.949 Re-arranging Eq. 15.200 gives 0.5

 2 P1G 2K Total  P1 −  − P2 = 0 2 ρ C 1 1  



(15.210)

Eq. 15.210 involves a trial-and-error using a guess value for P2. This is substituted into Eq. 15.210 until the left side gives a value of zero. The Excel spreadsheet with a Goal Seek add in tool is the most convenient computational tool for Eq. 15.210. Eq. 15.210 is set to zero using a guess value of P2. The procedure involves setting the quadratic Eq. 15.210 to zero; with a guess value of the outlet pressure and the Goal Seek determines the outlet pressure after a set of iterations. The Excel spreadsheet (Example 15.13.xls) has been developed to determine the pressure drop of a compressible isothermal flow fluid using Eq. 15.210. Figure 15.24 shows the snap shots of the Excel spreadsheet calculations using the Goal Seek solver to determine the outlet pressure, P2. Example 15.14 Propane vapor at 90°F and an upstream pressure P1 = 20 psig flows at a rate of 24,000 lb/h in an 800 ft long, 6-in. Sch. 40 horizontal carbon steel pipe. Under these conditions, the viscosity (μ1 = 0.0094 cP) and the gas compressibility factor Z1 = 0.958. Calculate the total pressure drop under isothermal flow conditions. Check for critical flow. Solution Since the pipe is long, assume an isothermal condition for the compressible vapor flow. The density of propane at 90°F and pressure of 20 psig is

ρ=



Mw P 10.72 T

 44 × 34.7  = = 0.2589 lb/ft 3  10.72 × 550  Velocity of the gas is: The 6 in. Sch. 40 pipe size (ID = 6.065 in.) Area of pipe



A  = π(ID)2/4



= π(.5054)2/4



= 0.2006 ft.2 The velocity of gas in the line is:

where A = pipe area, ft2 G = mass flow rate, lb/s

G = ρ V A



Fluid Flow  191

Figure 15.24  The Excel spreadsheet snapshot of Example 15.13.

(Continued)

192  Petroleum Refining Design and Applications Handbook Volume 2

Figure 15.24  (Continued) The Excel spreadsheet snapshot of Example 15.13.

(Continued)

Fluid Flow  193

Figure 15.24  (Continued) The Excel spreadsheet snapshot of Example 15.13.

(Continued)

194  Petroleum Refining Design and Applications Handbook Volume 2

Figure 15.24  (Continued) The Excel spreadsheet snapshot of Example 15.13.

v = fluid velocity, ft./s ρ = fluid density, lb/ft.3 or

v = G/(ρ A) 24000 (0.2589 × 0.2006 × 3600) = 128.36 ft /s =



Sonic velocity is:

P v s = Z k g 144 , ft /s ρ

0.958 × 1.15 × 32 × 144 × 34.7 0.2589 = 824.87 ft /s =



(15.174)

Sonic flow would occur at the end of the pipe and not where the pressure is 20 psig. The inlet Mach number Ma1 is:



Ma1 =

v vs

128.36 = = 0.1556 824.87



(15.185)

Fluid Flow  195 Since the Mach number is less than 1, the flow of propane through the pipe is subsonic. Reynolds number Re:

Re =

Dvρ dvρ W = 123.9 = 6.31 µe dµ µ

24000 6.065 × 0.00094 = 2, 656, 329



Re = 6.31

= 2.66 × 106



Friction factor, f:

 ε  5.02 log A  = −4 log  −  3.7D Re  fC

1



(15.35)

where

ε/D  6.7  A= +  3.7  Re 

and

0.9



ε = pipe roughness, ft. D = pipe internal diameter, ft.

ε 0.00015 = = 0.0002968 D 0.5054 0.0002968  6.7  A= +  2656329  3.7

0.9

= 8.9370 × 10−5





 0.0002968  5.02 log(8.937 × 10−5 ) = −4 log  − 2, 656, 329  3.7  fC

1

= 16.2247 fC = 0.00380



The Darcy friction factor fD = 4 fC

fD = 4(0.00380)

= 0.0152 Loss coefficient due to straight pipe:

L D 0.0152 × 800 × 12 = 6.065 = 24.052

K = fD



196  Petroleum Refining Design and Applications Handbook Volume 2 Outlet pressure, P2 is (Eq. 15.200) 0.5

 P G 2K Total  P2 = P12 − 1  ρ1C 2  

Where in Eq. 15.197:

C = 1335.6 d 2 G2 240002 = C 2 (1335.6 × 6.065)2 = 0.2386





 (34.7)(0.2386)(24.052)  P2 =  34.7 2 −   0.2589

0.5

= 20.85 psia ∆P ≅ P1 − P2 = 34.7 − 20.85 = 13.85 psi





The critical pressure, Pc in Eq. 15.188 is:

G  RT  Pc =   11400d 2  k[k + 1] 24000 11400(6.065)2 = 4.752 psia

Pc =

1/ 2

, psia

34.085 × 500 1.15 × 2.15

The outlet temperature, T2 is the same as the inlet temperature, (i.e., isothermal condition)

T2 = T1, °R T2 = 550, °R Vapor density at the exit is:

ρ2 =

M w • P2 , lb/ft 3 10.72 T2

ρ2 =

(44 )(20.85) (10.72)(550)

= 0.1556 lb/ft 3





Flow velocity at pipe exit is:

v = G/(ρ A) 24000 (0.1556 × 0.2006 × 3600) = 213.59 ft /s. =



Fluid Flow  197 The exit Mach number Ma 2 = 1/ k



Ma 2 = 1/ 1.15 = 0.9325 The Excel program (Example 15.14.xlsx) provides calculations of Example 15.14.

15.24.5 Critical Pressure Ratio The maximum attainable mass flux for given supply conditions is when ψ is a maximum, and is represented by: 1/ 2



 2   P  2 /γ  P  ( γ +1)/γ    ψ =    P  −  P  γ − 1     1 1  



(15.210)

Therefore, the pressure Pc causing the maximum flux can be found by differentiating ψ2 with respect to P and equating the result to zero, which gives



 2  P  2 /γ  γ + 1   P  ( γ +1)/γ  1 c   c  −  =0   P  γ γ P      Pc 1 1

(15.211)

The critical pressure ratio Pc/P1 is given by: γ

Pc  2  ( γ −1) = P1  γ + 1 



(15.212)

For γ = 1.4, Pc/P1 = 0.528. For other values of γ, the value of the critical pressure ratio lies in the approximate range 0.5 to 0.6 where P1 = upstream pressure Pc = critical pressure γ = ratio of specific heat at constant pressure to specific heat at constant volume = (Cp/Cv). The maximum flux or maximum mass flow of the gas at sonic conditions is: 0.5



 kgM   2  ( k +1))/k−1   W w    = G max = Po     A max ZRT  o  k +1 

where W = mass flow rate, lb/s A = cross-sectional flow area, ft2 G = mass flux, lb/(s. ft2) Po = pressure at source condition, psia To = temperature at source condition, °R k = specific heat ratio constant

(15.213)

198  Petroleum Refining Design and Applications Handbook Volume 2 Recently, Kumar [34] develops a method using thermodynamic principles to determine the status of flow (i.e., whether choking flow exists or not), (ΔP/Po)cr and the flow rate. His method removes the use of plots as generated in Crane Manual [4], which have few limitations. For an adiabatic compressible fluid flow, he showed that ( γ +1)   2  2  2 2 + ( γ − 1)Ma12  {γ + 1}Ma1  + 1 2 ln +K =0 − 2  + ( γ 1 ) Ma Ma12 ( γ + 1)  2 + {γ − 1}Ma12  1 



P  and r =  2  =  Po  cr



(15.214)

1/ 2

0.5( γ + 1)Ma12 

1 + 0.5( γ − 1)Ma  2 1

γ ( γ +1) 2( γ −1)



(15.215)

The critical expansion factor is:



Ycr =

K(1 + r )   1  2  K + 2 ln     r 

(15.216)

and the mass flow rate at critical condition is:

where D L PA Po P1 P2 Ma1 Ma2 γ K Vo r Ycr W

W = 0.1265 D2 Ycr

Po − P2 KVo

(15.217)

= pipe internal diameter, mm = pipe length, m = ambient pressure, kPaa. = stagnation upstream pressure, kPaa = pressure at inlet tip of the pipe, kPaa = pressure at outlet tip of the pipe, kPaa = Mach number at inlet tip of the pipe = Mach number at outlet tip of the pipe = isentropic ratio of specific heat at constant pressure to specific heat at constant volume = loss coefficient = specific volume at upstream stagnation point, m3/kg = (P2/Po)cr = overall critical pressure ratio, dimensionless = critical expansion factor, dimensionless = mass flow rate, kg/h.

The simultaneous solution of Eqs. 15.214 and 15.215 eliminates Ma and yields a value for r, the critical pressure ratio. Table 15.16 shows a wide variation in the critical values with respect to γ (i.e., ratio of specific heats, Cp/Cv) and the loss coefficient K.

Fluid Flow  199 Table 15.16  Limiting critical values. γ = 1.2

γ = 1.3

γ = 1.4

γ = 1.5

γ = 1.6

K

(ΔP/Po)cr

Ycr

(ΔP/Po)cr

Ycr

(ΔP/Po)cr

Ycr

(ΔP/Po)cr

Ycr

(ΔP/Po)cr

Ycr

1

0.62

0.52

0.64

0.51

0.66

0.50

0.68

0.50

0.70

0.49

2

0.64

0.54

0.67

0.53

0.69

0.53

0.71

0.52

0.73

0.51

3

0.68

0.58

0.70

0.56

0.73

0.55

0.75

0.54

0.78

0.53

4

0.71

0.60

0.74

0.58

0.76

0.57

0.78

0.55

0.80

0.54

5

0.74

0.61

0.76

0.59

0.78

0.58

0.81

0.56

0.82

0.54

6

0.75

0.62

0.78

0.60

0.80

0.58

0.82

0.56

0.84

0.55

7

0.77

0.62

0.79

0.60

0.81

0.58

0.84

0.56

0.85

0.54

8

0.78

0.63

0.80

0.61

0.83

0.59

0.85

0.56

0.86

0.54

9

0.79

0.63

0.81

0.61

0.84

0.59

0.85

0.56

0.88

0.54

10

0.80

0.63

0.82

0.61

0.85

0.59

0.86

0.56

0.88

0.54

20

0.86

0.64

0.88

0.61

0.89

0.58

0.91

0.55

0.93

0.52

30

0.88

0.64

0.90

0.60

0.92

0.56

0.93

0.53

0.94

0.50

40

0.90

0.63

0.92

0.59

0.94

0.55

0.94

0.52

0.96

0.48

50

0.92

0.63

0.93

0.59

0.94

0.55

0.95

0.52

0.96

0.47

60

0.92

0.62

0.94

0.58

0.95

0.54

0.95

0.51

0.97

0.46

70

0.92

0.62

0.94

0.58

0.95

0.54

0.96

0.50

0.97

0.46

80

0.93

0.62

0.94

0.57

0.96

0.53

0.96

0.49

0.97

0.45

90

0.93

0.62

0.94

0.57

0.96

0.53

0.96

0.49

0.97

0.45

100

0.94

0.61

0.95

0.57

0.96

0.52

0.97

0.48

0.98

0.44

(Source: S. Kumar, Chem. Eng. Oct. 2002, p. 62).

Example 15.15 From the table listed below determine the status of flow (i.e., whether choking flow exists or not), (ΔP/Po)cr and the flow rate [34]. Data

Value

Upstream pressure, Po kPaa

6600

Downstream discharge pressure, PA kPaa

200

Upstream specific volume, Vo m3/kg

0.01724

Isentropic coefficient, γ

1.55

Internal pipe diameter, D mm

52.5

Length of pipe m

100

Number of elbows

4

Loss coefficient K

45

200  Petroleum Refining Design and Applications Handbook Volume 2 Solution For known isentropic coefficient γ and loss coefficient K, a guessed value of Ma1 is used in Eq. 15.214 until the left side of the equation approximates to a value of zero. Otherwise, a new guess value of Ma1 is used in Eq. 15.214. Once the required value is known, Eqs. 15.215, 15.216, and 15.217 are subsequently used to determine r, P2, ΔP, Ycr, and W, respectively. This procedure involves the use of the Excel spreadsheet with the Goal Seek or Solver add-in from the Tools menu and is given in Example 15.15.xlsx. Using the Excel spreadsheet Example 15.15.xlsx, the calculated overall critical pressure ratio r is:



r = 0.04804 The critical pressure P2 is

P2 = r × Po

= 0.04804 × 6600



= 317.06 kPa Test for choke flow Since P2 > PA, the pipe will choke The critical expansion factor Ycr from Eq. 15.216 is:

Ycr =

=

K(1 + r ) 2 K + 2 ln 1/r 

(

)

45(1 + 0.04804 ) 2 ( 45 + 2[1/0.04804 ])

= 0.6795



The critical mass flow rate from Eq. 15.217 is:

W = 0.1265 D2 Ycr

Po − P2 KVo

= 0.1265(52.5)2 (0.6795) = 21320.96 kg /h

6600 − 317.06 (45 × 0.01724 )

15.24.6 Adiabatic Flow If there is no heat transfer or energy dissipated in the gas when traversing from state 1 to state 2, the process is adiabatic and reversible, i.e., isentropic. However, the actual flow conditions are somewhere between isothermal and

Fluid Flow  201 adiabatic, and as such, the flow behavior can be described by the isentropic equations, where the isentropic constant k replaced a polytropic constant γ (i.e., 1< γ < k). For isothermal condition, γ = 1, whereas truly isentropic flow corresponds to γ = k. The density and temperature as a function of pressure are:

 P ρ = ρ1    P1 



1k

 P , T = T1    P1 

( k −1) k



(15.218)

The mass flow rate, G by using Eq. 15.218 to eliminate ρ and T and solving for G gives: 1/ 2



  k    P  ( k −1)/k   2  2    1 −     k + 1   P1   G = P1 ρ1    P2  2 4 f L   − ln D k  P1   

(15.219)

where f = Fanning friction factor. If the system contains fittings as well as straight pipe, the term 4 f L/D (= Kf, pipe) can be replaced by ΣK f , i.e., the sum of all loss coefficients in the system.

15.24.7 The Expansion Factor, Y The adiabatic flow Eq. 15.215 can be represented in a form:



 2ρ P  G = Y 1   ΣK f 

12

 2 (1 − P2 P1 )  = Y P1 ρ1   ΣK f   12

(15.220)

where ρ1 = P1Mw/RT1, ΔP = P1 – P2, and Y is the expansion factor. Note that Eq. 15.220 without the Y term is the Bernoulli equation for an incompressible fluid of density ρ1. Therefore, the expansion factor Y = Gadiabatic/Gincompressible, is the ratio of the adiabatic mass flux (Eq. 15.219) to the corresponding incompressible mass flux, and is a unique function of P2/P1, k, and Kf. Figure 15.25a shows values of Y for k = 1.3 and k = 1.4 as a function of ΔP/P1 and ∑K f (which is denoted by simply K on these plots). Figures 15.25b and 15.25c show the expansion factor Y for compressible flow through nozzles and orifices, and plots of the critical pressure ratio for compressible flow through nozzles and Venturi tubes, respectively. The conditions corresponding to the lower ends of the lines on the plots (i.e., the “nought”) represent the sonic (choked flow) state where P2 = P2* . These same conditions are shown in the tables accompanying the plots, thus allowing the relationships for choked flow to be determined more accurately than is possible from reading the plots. Note: It is not possible to extrapolate beyond the “nought” at the end of the lines in Figures 15.25a and 15.25b as this represents the choked flow state, in which P2 = P2* (inside the pipe), and is independent of the external exit pressure. Figures 15.25a and 15.25b provide an alternative method of solving compressible adiabatic flow problems for piping systems. However, this procedure requires some iterations because the value of Kf depends on the Reynolds number, which cannot be determined until G is obtained.

202  Petroleum Refining Design and Applications Handbook Volume 2 k = 1.3

(k = approximately 1.3 for CO2, SO2, H2O, H2S, NH3, N2O, CI2, CH4, C2H2, and C2H4)

1.0

Limiting Factors For Sonic Velocity

0.95

k = 1.3

0.90

K

∆P P’ 1

Y

1.2 1.5 2.0

.525 .550 .593

.612 .631 .635

3 4 6

.642 .678 .722

.658 .670 .685

8 10 15

.750 .773 .807

.698 .705 .718

20 40 100

.831 .877 .920

.718 .718 .718

0.85 0.80 Y 0.75

0 10 K= 40 K= 20 K = 15 K = 10 K = 8.0 K = 6.0 K=

0.70

K=

2.0 K = .5 1 K = 1.2 K=

0.60 0.55

0

0.1

0.2

0.3

0.4

0.5 ∆P

4.0 3.0

K=

0.65

0.6

0.7

0.8

0.9

1.0

P’ 1

k = 1.4 (k = approximately 1.4 for Air , H2, O2, N2, CO, NO, and HCI)

1.0

Limiting Factors For Sonic Velocity

0.95

k = 1.4

0.90

K

∆P P’ 1

Y

1.2 1.5 2.0

.552 .576 .612

.588 .606 .622

3 4 6

.662 .697 .737

.639 .649 .671

8 10 15

.762 .784 .818

.685 .695 .702

20 40 100

.839 .883 .926

.710 .710 .710

0.85 0.80 Y 0.75

0.65

0.2

0.3

0.4

0.5

1.5

0.1

2.0

0

K=

1.2

0.55

K=

K=

0.60

4.0 K = 3.0 K=

0 10 K= 0 4 K= 0 2 K = = 15 K 10 K = 8.0 K = 6.0 = K

0.70

0.6

0.7

0.8

0.9

1.0

∆P P’ 1

Figure 15.25a  Net expansion factor, Y, for compressible flow through pipe to a larger flow area (reprinted/adapted with permission from “Flow of Fluids Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

Fluid Flow  203 Expansion Factor Y

1.00 0.95

Square edge orifice

d0 d1

0.90

0 to 0.2

0.4

0.85

0.6 0.7

0.80

Nozzle or venturi meter d0 = 0 to 0.2 0.75 d1

0.8

= 0.5 = 0.6

0.70

= 0.7 = 0.75

0.65

= 0.8 = 0.85

0.60 0.55 0.50 0.45 0.40 0.35 k = 1.45 k = 1.40 k = 1.35 k = 1.30 k = 1.25

0 0 0 0 0

.2 .2 .2 .2 .2

.4 .4 .4

.6 .6

1.0 1.0

.8 .8 .8

.6

1.0 1.0

.8

.6 .4 .4 .6 Pressure ratio, ∆ P / P’1

.8

1.0

Figure 15.25b  Net expansion factor, Y, for compressible flow through pipe to a larger flow area (reprinted/adapted with permission from “Flow of Fluids Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

15.24.8 Misleading Rules of Thumb for Compressible Fluid Flow In general, compressible fluid flow calculations are much more complicated than incompressible fluid flow. Recently, Walters [35, 36] has shown that rules of thumb that are applied in the design calculations for compressible fluid flow can be grossly misleading and erroneous. These common rules are: 1. Th  at adiabatic and isothermal flow bracket all flow rates. These conditions do not occur. 2. If the pipe pressure drop in a compressible flow system is less than 40% of the inlet pressure, then the incompressible flow calculation methods can be safely employed, with the average density along the pipe used in the equations. He further showed that this rule is invalid unless associated with a particular f L/D ratio. 3. Choked air flow at 50% pressure drop. An equation often used to determine the likelihood of sonic choking is:



p*  2  = po  γ + 1 

γ ( γ −1)



(15.221)

where p* is the critical static pressure at sonic velocity and po is the local stagnation pressure at the orifice/valve. Walters indicated that using Eq. 15.221 with γ = 1.4 results in 47% pressure drop to

204  Petroleum Refining Design and Applications Handbook Volume 2

.64

.62

β 0.85

rc = P’2/P’1

.60

0.80

.58

0.75

0.70

.56

0.65 0.60 .54

0.50 0.40 0.20 0

.52 1.25

1.3

1.35

1.4

1.45

k = Cρ/Cv

Figure 15.25c  Critical pressure ratio, rc, for compressible flow through nozzles and venture tubes (reprinted/adapted with permission from “Flow of Fluids Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved, Note: P = psia, β = ratio of small –to – large diameter in orifice and nozzles and contraction or enlargements in pipes).

obtain choking. Furthermore, He stated that Eq. 15.221 cannot be used with the supply pressure if there is any significant pressure drop from the supply to the orifice/valve. For gases with different specific heat ratios, the pressure drop ratio will differ somewhat, in accordance with Eq. 15.221. In addition, Eq. 15.221 breaks down for pipe-system analysis when pipe friction becomes a factor. This is because the stagnation pressure in the equation is the pressure at the upstream side of the shock wave. However, if there is any pressure drop in the pipe from the supply pressure to the shock wave, then the supply pressure cannot be used in Eq. 15.221. Instead, the local stagnation pressure at the shock wave must be used, which is unknown unless the pressure drop is determined from alternative means. Therefore, Eq. 15.221 cannot be used to predict the supply and discharge pressures necessary for sonic choking unless the piping has negligible friction loss.

15.24.9 Other Simplified Compressible Flow Methods As shown earlier, most gases are not isothermal, and therefore it is impossible to know how much error is introduced by the assumption of constant temperature. Simplified equations typically do not address sonic-choking conditions, and cannot address the delivery temperature. These equations break down at high Mach numbers. The entire pipe is solved in one lumped calculation instead of coupling the governing equations in marching order. It is difficult to extend the equations to pipe networks. Walters developed compressible flow equations for single pipe [35]:

Fluid Flow  205 Adiabatic flow equation and integrated solution are:

∫



L

0

f dx = D

∫

Ma 2

Ma1

1 − Ma 2 dMa 2   − 1 γ Ma 2  γ Ma 4 1 +  2 

(15.222)

 γ −1 2 Ma 2  1+ 2  fL 1  1 1  γ +1 Ma1  2 ln =  − +  γ −1 D γ  Ma12 Ma 22  2 γ  Ma 22   2  1+ Ma1    2



(15.223)

Isothermal flow equation and integrated solution are:

∫



LT

0

f dx = D

∫

Ma 2

Ma1

(1 − γMa 2 ) dMa 2 4 γ Ma

 Ma12  1−   Ma 22   Ma 22  f LT − = ln  Ma 2  D γMa12 1



(15.224)

(15.225)

Computer software has been developed that models pipe systems of compressible fluids and this can be obtained from the website: www.aft.com.

15.24.10 Friction Drop for Flow of Vapors, Gases and Steam See Figures 15.26a and 15.26b A. The Darcy Rational Relation for Compressible Flow for Isothermal Process [4]

∆Ρ 0.000336fW 2 V 0.000336 f W 2 = = 100 ft d5 d5 ρ



0.000001959f ( q ′h ) S g2 ∆Ρ or = 100 ft d5 ρ

(15.122)

2



(15.226)

In SI units



∆P/100 m =

62530 f W 2 V 62530 f W 2 = d5 d 5ρ 93650 f ( q ′h ) S g

(15.123)

2



or ∆P/100 m =

d 5ρ



(15.227)

The general procedures outlined previously for handling fluids involving the friction factor, f, and the Re chart are used with the above relations. This is applicable to compressible flow systems under the following conditions [4].

206  Petroleum Refining Design and Applications Handbook Volume 2

40 .04 .05

Index 2

30 20

− V−Specific Volume of Flowing Fluid, in Cubic Feet per Pound

.03

p −Weight Density, in Pounds per Cubic Foot

15 .1

.2 .3 .4 .5 .6 .7 .8 .9 1.0

1.5 2 3 4 5

3 2

1.5

.6 .7 .8 .9 1.0 1.5

10 9 8 7 6 5 4

1000 800 600 500 400 300

.5

2 3 4

(2) (3)

1.0 .9 .8 .7 .6 .5 .4

5 6 7 8 9 10 15 20

.3

30

.2

40

d

200

30

20

10 9 8 7 6 5 4 3 2

24 20 16 14 12 10 8 6 5 4 3½ 3 2½ 2 1½ 1¼

1 .9 .8 .7 .6 .5 .4 .3

1 ¾ ½ ¾ ¼ ½

.2

50

f .05

(1)

20

.04 .03 .02

100 80 60 50 40 30

.015

10 8 6 5 4 3 2

.01

W− Rate of Flow, in 1000 Pounds per Hour ΔP/100 feet = 0.000336 f W2/d5p

Index 1

f −Friction Factor

− V 50

Nominal Diameter, in Inches (Standard Pipe - Schedule 40)

P .02

W 1600

ΔP100 .4

ΔP100−Pressure Drop per 100 Feet, in Pounds per Square Inch d −Internal Diameter of Pipe, in Inches

∆ P/100 ft = 0.000 336 f W2/d5p

1 .8 .6 .5 .4 .3 .2 .1

Figure 15.26a  Pressure drop in compressible flow lines (reprinted/adapted with permission from “Flow of Fluids, Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

where W = rate of flow, lb/h (kg/h) V = specific volume of fluid, cubic feet per pound (m3/kg) f = friction factor d = internal pipe diameter, in. (mm) ρ = fluid density, lb/ft3 (kg/m3) Sg = specific gravity of gas relative to air = the ratio of molecular weight of the gas to that of air. q ′h = rate of flow, cu ft/hr (m3/h) at standard conditions (14.7 psia and 60oF), SCFH (m3/s at metric standard conditions (MSC)—1.01325 bar absolute and 15°C) Babcock formula for steam flow at isothermal condition is



q ′h = 24 , 700[Yd 2 /Sg ](∆Ρ ρ1 /K )1/2 , CFH at 14.7 psia and 60°F

(15.228)

q ′h = 40, 700 Yd 2 (∆P)( P1′) /(KT1Sg )

(15.229)

or



1/ 2

Fluid Flow  207 Pressure Equivalent: 1bar = 10s Pa

W 103 800 600 500 400 300

= 100 kPa

3

.4

200

Index 2

1.5

.2

1.0

1.0

.3

1.5

.8 .7 .6 .5

600 500

.4

400

4 5

.2

6 7 8

.15

10

.1

15

.08 .07 .06 .05

20 30

.04 .03

40 50 60 70 80

.02

100

.01

.5 .6 .7 .8 .9 1.0 1.5 2

3 4 5 6 7 8 9 10

.015

300

d 24 20 16 12 10

200

8

150

6 5

100

4

80

3

60 50

2½ 2

40

1½ 1¼ 1

Interanl Diameter of Pipe, in millimeter

.3

Pressure Drop per 100 metres, in bar

.4 3

800

Specific Volume of Flowing Fluid, in cubic metres per kilogram

2 Density, in kilogram per cubic metre

.15

2

30 20 15 10 8 6 5

3/4 1/2 3/8 1/4 1/8

100 80 60 50 40 30 f

20 .05 10

.04 .03

.02

Friction Factor

.5 .6 .7 .8

.015 .01

8 6 5 4 3 2

1.0 .8 .6 .5 .4 .3

Rate of Flow, in thousands of kilograms per hour

Index 1

V

Normal Size of Schedule 40 Pipe, in inches

p .3

Δp100 .09 .1

.2 .1 .08 .06 .05 .04

Figure 15.26b  Pressure drop in compressible flow lines (metric units) (reprinted/adapted with permission from “Flow of Fluids, Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

where d = internal pipe diameter, in. Y = net expansion factor for compressible flow through orifices, nozzles, or pipe (see Figures 15.25a–c) K = loss coefficient for all valves, fittings and pipe (resistance coefficient)

 K = f L /D + 

∑

Ki   i = fittings+ valves

q ′h = flow rate, ft3/h at 14.7 psia and 60°F Sg = specific gravity of a gas relative to air = the ratio of the molecular weight of the gas to that of air P = pressure, lbf/in2 absolute ΔP = pressure drop, psi

208  Petroleum Refining Design and Applications Handbook Volume 2 W

C1

1500 2000 1500

ΔP100 − C2V

=

ΔP100ρ C2

C2 =

ΔP100 − C1V

C1 = discharge factor from chart at right. C2 = size factor, from table on next page. The limitations of the Darcy formula for compressible flow, as outlined on page 3-3 appy also to the simplified flow formula.

Example 1 Given: Stream at 345 psig and 500 F flows through 8-inch Schedule 40 pipe at a rate of 240, 000 pounds per hour Find: The pressure drop per 100 feet of pipe. Solution :

.1

10

6

ρ =

C1

5

4

V = 1.45

3 2.5

2

. . . . . . . . page 3-17 or A-16

ΔP100 = 57 × 0.146 × 1.45 = 12

Example 2

1.0

Given: Pressure drop is 5 psi with 100 psig air at 90 F flowing through 100 feet of 4-inch Schedule 40 pipe.

.9

Solution:

.5

.8

.6 .7 .8 .9 1.0

1.5

.005

2

.004

2.5

4

.002

5

.001 .0009 .0008 .0007 .0006

20

25 30

40

50

3

.0025

.0015

600

1000 900 800 700 600 500 400 300

.02

.006

700

15

.3 .4

.003 1.5

Find: The flow rate in standard cubic feet per minute.

.25

.025

.01 .009 .008 .007

800

.2

.04

3.5

C1 = 57 C1 = 0.146

.15

.05

.015

1000 900

.03

ΔP100ρ W - Rate of Flow, in Thousands of Pounds per Hour

C1 =

.1 .09 .08 .07 .06

7

C1C2

−

10

8

The simplified flow formula can then be written: ΔP100 = C1C2V =

C1

9

336 000 f d5

C2 =

C1

6 7 8 9 10

60 70

500

250 200

400

300 250

150

100 90 80 70 60 50

200

40 30

150

80

25 20 15

90 100

100

10

ΔP100 = 5.0 C2 = 5.17 ρ = 0.564

. . . . . . . . . . . page A-10

C1 = (5.0 × 0.564)÷ 5.17 = 0.545 W = 23000

For C2 values and an exmaple on “determining pipe size”, see the opposite page.

q'm = W ÷ (4.58 Sg) . . . . . . . . . . . page B-2 q'm = 23000 ÷ (4.58 × 1.0) = 5000 scfm

Figure 15.27a  Simplified flow formula for compressible fluids (reprinted/adapted with permission from “Flow of Fluids, Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

Values of C1

C1 = W210–9

− V

336 000 f d5

W

Values of C1

− V = (W210–9)

0.00 336 f d5

ΔP100 = W2

W

W - Rate of Flow, in Thousands of Pounds per Hour

The Darcy formula can be written in following from:

Fluid Flow  209

9 8

62 530 × 103 f d5

7

The simplified flow formula can the bed written: Δp100 = C1 C2 V = C1 =

Δp100 C2 V

~

=

6

C1 C2 ρ Δp100ρ C2

C2 =

Δp100 C1 V

=

5

Δp100ρ C1

4

C2 = size factor from tables on pages 3-23 to 3-25

Given: Steam at 24 bar absolute and 250°C flows through an 8-inch Schedule 40 pipe at a rate pf 100 000 kilograms per hour. Find: The pressure drop per 100 metres of pipe. C2 V

= 100 = 0.257 . . . . . . . . . . . . . . . . . . facing page = 0.091 m3/kg . . . . . . .page 3-17 or A-15

Δp100 = 100 × 0.257 × 0.091 Δp100 = 2.34 bar Example 2 Given: Pressure drop is 1 bar with 7 bar guage air at 30°C flowing through 100 metres of 4 inch nominal size ISO steel pipe, 6.3 mm wall thickness. Find: The flow rate in cubic metres per minute at metric standard conditions (1.013 25 bar and 15°C). Solution:

Δp100

Rate of Flow, in thousands of kilograms per hour

Example 1

3 2.5

2.5

2

4

.2

5

.15

.04 .025

1.5

1.0 .9 .8 .7 .6

C2

= 9.42. . . . . . . . . . . . . . . . . . page 3-24

ρ

= 9.21. . . . . . . . . . . . . . . . . . page A-10

C2

= 1 ×09.21 9.42

W

= 9 900

q’m

= W ÷ (73.5 Sg) . . . . . . . . . . page B-2

q’m

= 9 900 ÷ (73.5 × 1) = 134.7 m3/min

= 0.978

.5

2000 25 30

40

20 25

50

30 60

50

70

60 70 80 90 100

80

.01 .009 .008 .007 .006

2500

20

.02

400

300 250

1500

1000 900 800 700 600 500 400 300

150

250 200 150

90 100

100

100

.005 .004

.0025 .002

.4

15

5000

3000

40

.003

=1

6 7 8 9 10

C1 6000

600

.025

.015

700

15

3

.25

.05

W 103 800

2

.4

.1 .09 .08 .07 .06

W 103 10

1.5

.5

3.5

The limitations of the Darcy formula for compressible flow, as outlined on page 3-3 apply also to the simplified flow formula.

C1

1

.3

C1 = discharge factor, from chart at right

Solution:

1 .9 .8 .7 .6

Values of C1

Let C1=

W2 and C = 2 108

~ V

C1

For C2 values see opposite page and pages 3-24, 3-25 For example on determining pipe size see opposite page.

.0015

.35

Figure 15.27b  Simplified flow formula for compressible fluids (metric units) (reprinted/adapted with permission from “Flow of Fluids, Through Valves, Fittings and Pipe”, Technical Paper No. 410, 1999, Crane Co. All rights reserved).

Values of C1

The Darcy formula can be written in the folling form; 62 530 f W2 V W2 62 530 × 103 f Δp100 = = 8 5 10 d d5

C1

Rate of Flow, in thousands of kilograms per hour

W 103 10

210  Petroleum Refining Design and Applications Handbook Volume 2 T1 = inlet temperature, absolute (°R = °F + 460) ρ1 = upstream density of steam, lb/ft3 In SI units



q ′h = 1.0312[Yd 2 /S g ](∆p ρ1 /K )1/2

(15.230)

q ′h = 19.31 Yd 2 (∆p)( p1′ ) /(KT1S g )

(15.231)

or 1/ 2



where d = internal pipe diameter, mm Y = net expansion factor for compressible flow through orifices, nozzles, or pipe K = loss coefficient (resistance coefficient) p = pressure, bara q ′h = flow rate, m3/h at MSC (metric standard conditions—1.01325 bar at 15°C) Sg = specific gravity of a gas relative to air = the ratio of the molecular weight of the gas to that of air Δp = pressure drop, bar T1 = inlet temperature, absolute (K = °C + 273) ρ1 = upstream density of steam, kg/m3 B. Alternate Vapor/Gas Flow Methods Note that all specialized or alternate methods for solving are based on simplified assumptions or empirical procedures presented earlier. They are not presented as better approaches to solving the specific problem. Figures 15.27a and 15.27b (SI) are useful in solving the usual steam or any vapor flow problem for turbulent flow based on the modified Darcy friction factors. At low vapor velocities the results may be low; then use Figures 15.26a or 15.26b (SI). For steel pipe the limitations listed in (A) above apply. 1. D  etermine C1 and C2 from Figures 15.27a or 15.27b (SI units) and Table 15.17 for the steam flow rate and assumed pipe size, respectively. Use Table 15.18 to select steam velocity for line size estimate. 2. Read the specific volume of steam at known temperature and pressure from steam tables. 3. Calculate pressure drop (Figures 15.27a or 15.27b) per 100 ft of pipe from



∆Ρ/100 feet = C1C 2 V 4. 5. 6. 7.

(15.232)

Determine the loss coefficient K of all fittings, valves, etc., and hence the equivalent length (K = f Leq/D).  etermine expansion and contraction losses, fittings, and at vessel connections. D Determine pressure drops through orifices and control valves. Total system pressure drop

ΔPTOTAL = (L + Leq)(ΔP/100) + Item 5 + Item 6

(15.233)

8. I f pressure drop is too large (or greater than a percentage of the inlet system pressure), re-estimate line size and repeat calculations (see paragraph (A) above) and also examine pressure drop assumption for orifices and control valves.

Fluid Flow  211 C. Air For quick estimates for air line pressure drop and through an orifice, see Tables 15.19a and 15.19b [37]. D. Babcock Empirical Formula for Steam Comparison of results between the various empirical steam flow formulas suggests the Babcock equation is a good average for most design purposes at pressure 500 psia and below. For pipe lines smaller than 4 in., this relation may be 0–40% high [38].

p 1 − p2 = ∆Ρ = 0.000131(1 + 3.6 d )



w2 L ρd5

(15.234)

ΔP/100 feet = w2F/ρ

(15.235)

Figure 15.28 is a convenient chart for handling most in-plant steam line problems. For long transmission lines over 200 ft, the line should be calculated in sections is order to re-establish the steam specific density. Normally an estimated average ρ should be selected for each line increment to obtain good results. Table 15.20 is used to obtain the value for “F” in Eq. 15.235.

Table 15.17  Simplified flow formula for compressible fluid pressure drop, rate of flow, and pipe sizes (use with Figure 15.27a). Values of C2 Nominal pipe size Inches

Schedule number

1/8

3/4

3/8

1/2

Value of C2

Nominal pipe size Inches

Schedule number

Value of C2

Nominal Pipe Size Inches

Schedule Number

Value of C2

40 s

7,920,000.00

5

40 s

1.59

16

10

0.00463

80 x

26,200,000.00

80 x

2.04

20

0.00421

120

2.69

30 s

0.00504

40 s

1,590,000.00

160

3.59

40 x

0.00549

80 x

4,290,000.00

… xx

4.93

60

0.00612

40 s

319,000.00

40 s

0.610

80

0.00700

80 x

718,000.00

80 x

0.798

100

0.00804

120

1.015

120

0.00926

6

40 s

93,500.00

160

1.376

140

0.01099

80 x

186,100.00

… xx

1.861

160

0.01244

160

4,300,000.00

… xx

11,180,000.00

20

0.133

30

0.135

10

0.00247

40 s

0.146

20

0.00256

8

18

(Continued)

212  Petroleum Refining Design and Applications Handbook Volume 2 Table 15.17  Simplified flow formula for compressible fluid pressure drop, rate of flow, and pipe sizes (use with Figure 15.27a). (Continued) Values of C2 Nominal Pipe Size Inches

Schedule Number

Value of C2

3/4

40 s

1

Nominal Pipe Size Inches

Schedule Number

Value of C2

21,200.00

60

80 x

36,900.00

80 x

160

100,100.00

… xx

627,000.00

11/2

Value of C2

0.163

…s

0.00266

0.185

30

0.00276

…x

0.00287

40

0.00298

100

0.211

120

0.252

5,950.00

140

0.289

60

0.00335

80 x

9,640.00

… xx

0.317

80

0.00376

160

22,500.00

160

0.333

100

0.00435

…xx

114,100.00

120

0.00504

20

0.0397

140

0.00573

160

0.00669

10

0.00141

20 s

0.00150

40 s

1,408.00

30

0.0421

80 x

2,110.00

40 s

0.0447

160

3,490.00

60 x

0.0514

… xx

13,640.00

80

0.0569

20

100

0.0661

30 x

0.00161

40 s

627.00

120

0.0753

40

0.00169

80 x

904.00

140

0.0905

60

0.00191

160

1,656.00

160

0.1052

…xx

4,630.00

80

0.00217

12 2

Schedule Number

40 s

10 11/4

Nominal Pipe Size Inches

20

0.0157

100

0.00251

40s

169.00

30

0.0168

120

0.00287

80x

236.00

…s

0.0175

140

0.00335

160

488.00

40

0.0180

160

0.00385

… xx

899.00

…x

0.0195

60

0.0206 (Continued)

Fluid Flow  213 Table 15.17  Simplified flow formula for compressible fluid pressure drop, rate of flow, and pipe sizes (use with Figure 15.27a). (Continued) Values of C2 Nominal Pipe Size Inches

Schedule Number

Value of C2

21/2

40 s

66.70

80 x

91.80

80

160

146.30

… xx

380.00

3

31/2

4

Nominal Pipe Size Inches

Nominal Pipe Size Inches

Schedule Number

Value of C2

24

10

0.000534

0.0231

20 s

0.000565

100

0.0267

…x

0.000597

120

0.0310

30

0.000614

140

0.350

40

0.000651

160

0.0423

60

0.000741

10

0.00949

80

0.000835

Schedule Number

Value of C2

40 s

21.40

80 x

28.70

160

48.30

20

0.00996

100

0.000972

… xx

96.60

30 s

0.01046

120

0.001119

40

0.01099

140

0.001274

160

0.001478

14

40 s

10.00

…x

0.01155

80 x

37.70

60

0.01244

40 s

5.17

80

0.01416

80 x

6.75

100

0.01657

120

8.94

120

0.01898

160

11.80

140

0.0218

… xx

18.59

160

0.0252

Note: The letters s, x, and xx in the columns of Schedule Numbers indicate Standard, Extra Strong, and Double Extra Strong pipe respectively.

Table 15.18  Suggested steam pipe velocities in pipe connecting to steam turbines. Service-steam

Typical range, ft/s

Inlet to turbine

100–150

Exhaust, non-condensing

175–200

Exhaust, condensing

500–400

15.25 Darcy Rational Relation for Compressible Vapors and Gases 1. D  etermine first estimate of line size by using suggested velocity from Table 15.13. 2. Calculate the Reynolds number, Re and determine the friction factor, f using Figure 15.5 or from Eqs. 15.33–15.36. 3. Determine the total straight pipe length, L

214  Petroleum Refining Design and Applications Handbook Volume 2 4. D  etermine equivalent pipe length for fittings and valves, Leq. 5. Determine or assume losses through orifice plates, control valves, equipment, contraction and expansion and so on. 6. Calculate pressure drop, ΔP/100 ft (or use Figures 15.26a or 15.26b).

∆P 0.000336 fW 2 0.000000726 f TS g ( q ′h ) = = 100 ft ρd 5 P′ d 5



2



7. Total pressure drop, ΔP total



= (L + Leq)(ΔP/100) + Item 5

(15.236)

8. I f the total line or system pressure drop is excessive (or greater than a percentage of the inlet system pressure), examine the portion of pressure drop due to pipe friction and that due to other factors in Table 15.19a  Flow of air through Sch. 40 pipe (used for estimating for detailed calculations, use friction factors f). For lenghts of pipe other than 100 feet, the pressure drop is proportional to the length. Thus for 50 feet of pipe, the pressure drop is approximately one-half the value given in the table ... for 300 feet, three times the given value, etc. The pressure drop is also inversely proportional to the absolute pressure and directly proportional to the absolute temperature. Therefore, to determine the pressure drop for inlet or average pressures other than 100 psi and at temperature other than 60 F, multiply the values given in the table by the ratio: 100 + 14.7 P + 14.7

460 + 1 520

where: “P” is the inlet or average gauge pressure in pounds per square inch, and, “t” is the temperature in degrees Fahrenheit under consideration. The cubic feet per minute of compressed air at any pressure is inversely proportional to the absolute pressure and directly proportional to the absolute temperature. To tdetermine the cubic feet per minute of compressed air at any temperature and pressure other than standard conditions, multiply the value of cubic feet per minute of free air by the ratio: 14.7 14.7 + P

460 + t 520

Free air q’m cubic ft per min at 60°F and 14.7 psia

Compressed air cubic ft Pressure drop of air in pounds per square inch per 100 feet of per min at 60°F and schedule 40 pipe for air at 100 lbs per square in. gauge pressure and 60°F temperature 100 psig 0.128 0.256 0.384 0.513 0.641

1/8ʺ 0.361 1.31 3.06 4.83 7.45

1/4ʺ 0.083 0.285 0.605 1.04 1.58

3/8ʺ 0.018 0.064 0.133 0.226 0.343

1/2ʺ

1 2 3 4 5

0.020 0.042 0.071 0.106

0.027

6 8 10 15 20

0.769 1.025 1.282 1.922 2.563

10.6 18.6 28.7 … …

2.23 3.89 5.96 13.0 22.8

0.408 0.848 1.26 2.73 4.76

0.148 0.255 0.356 0.834 1.43

0.037 0.062 0.094 0.201 0.345

0.019 0.029 0.062 0.102

0.026

25 30 35 40 45

3.204 3.845 4.486 5.126 5.767

… … … … …

35.6 … … … …

7.34 10.5 14.2 18.4 23.1

2.21 3.15 4.24 5.49 6.90

0.526 0.748 1.00 1.30 1.62

0.156 0.219 0.293 0.379 0.474

0.039 0.055 0.073 0.095 0.116

0.019 0.026 0.035 0.044 0.055

2”

50 60 70 80 90

6.408 7.690 8.971 10.25 11.53

0.019 0.023

28.5 40.7 … … …

8.49 12.2 16.5 21.4 27.0

1.99 2.85 3.83 4.96 6.25

0.578 0.819 1.10 1.43 1.80

0.149 0.200 0.270 0.350 0.437

0.067 0.094 0.126 0.162 0.203

0.019 0.027 0.036 0.046 0.058

100 125 150 175 200

12.82 16.02 19.22 22.43 25.63

0.029 0.044 0.062 0.083 0.107

0.021 0.028 0.036

33.2 … … … …

7.69 11.9 17.0 23.1 30.0

2.21 3.39 4.87 6.60 8.54

0.534 0.825 1.17 1.58 2.05

0.247 0.380 0.537 0.727 0.937

0.070 0.107 0.151 0.205 0.264

225 250 275 300 325

28.84 32.04 35.24 38.45 41.65

0.134 0.164 0.191 0.232 0.270

0.045 0.055 0.066 0.078 0.090

0.022 0.027 0.032 0.037 0.043

37.9 … … … …

10.8 13.3 16.0 19.0 22.3

2.59 3.18 3.83 4.56 5.32

1.19 1.45 1.75 2.07 2.42

0.331 0.404 0.484 0.573 0.673

350 375 400 425 450

44.87 48.06 51.26 54.47 57.67

0.313 0.356 0.402 0.452 0.507

0.104 0.119 0.134 0.151 0.168

0.050 0.057 0.064 0.072 0.081

0.030 0.034 0.038 0.042

… … … … …

25.8 29.6 33.6 37.9 …

6.17 7.05 8.02 9.01 10.2

2.80 3.20 3.64 4.09 4.59

0.776 0.887 1.00 1.13 1.26

475 500 550 600 650

60.88 64.08 70.49 76.90 83.30

0.562 0.623 0.749 0.887 1.04

0.187 0.206 0.248 0.293 0.342

0.089 0.099 0.118 0.139 0.163

0.047 0.052 0.062 0.073 0.086

… … … … …

11.3 12.5 15.1 18.0 21.1

5.09 5.61 6.79 8.04 9.43

1.40 1.55 1.87 2.21 2.60

3/4” 1”

2 1/2”

3”

3 1/2”

1 1/4”

1 1/2”

4”

5”

(Continued)

Fluid Flow  215 Table 15.19a  Flow of air through Sch. 40 pipe (used for estimating for detailed calculations, use friction factors f). (Continued) Free air Compressed q’m cubic ft air cubic ft per min per min Pressure drop of air in pounds per square inch per 100 feet of at 60°F and at 60°F and schedule 40 pip for air at 100 lbs per square in. 14.7 psia 100 psig gauge pressure and 60°F temperature 700 750 800 850 900

Calculations for Pipe Other than Schedule 40 To determine the velocity of water, ot the pressure drop of water or air, through pipe other than Schedule 40, use the following formulas: υa = υ40 ∆Pa = ∆P40

d40 dα d40 dα

2

5

Subscript “α” refers to the Schedule of pipe through which velocity pr pressure drop is desired. Subscript “40” refers to the velocity or pressure drop through Schedule 40 pipe, as given in the tables on these facing pages.

89.71 96.12 102.5 108.9 115.3

1.19 1.36 1.55 1.74 1.95

0.395 0.451 0.513 0.576 0.642

0.188 0.214 0.244 0.274 0.305

0.099 0.113 0.127 0.144 0.160

0.032 0.036 0.041 0.046 0.051

24.3 27.9 31.8 35.9 40.2

10.9 12.6 14.2 16.0 18.0

3.00 3.44 3.90 4.40 4.91

6”

950 1 000 1 100 1 200 1 300

121.8 128.2 141.0 153.8 166.6

2.18 2.40 2.89 3.44 4.01

0.715 0.788 0.948 1.13 1.32

0.340 0.375 0.451 0.533 0.626

0.178 0.197 0.236 0.279 0.327

0.057 0.063 0.075 0.089 0.103

0.023 0.025 0.030 0.035 0.041

… … … … …

20.0 22.1 26.7 31.8 37.3

5.47 6.06 7.29 8.63 10.1

1 400 1 500 1 600 1 800 2 000

179.4 192.2 205.1 230.7 256.3

4.65 5.31 6.04 7.65 9.44

1.52 1.74 1.97 2.50 3.06

0.718 0.824 0.932 1.18 1.45

0.377 0.431 0.490 0.616 0.757

0.113 0.136 0.154 0.193 0.237

0.047 0.054 0.61 0.075 0.094

0.023

2 500 3 000 3 500 4 000 4 500

320.4 384.5 448.6 512.6 576.7

14.7 21.1 28.8 37.6 47.6

4.76 6.82 9.23 12.1 15.3

2.25 3.20 4.33 5.66 7.16

1.17 1.67 2.26 2.94 3.69

0.366 0.524 0.709 0.919 1.16

0.143 0.204 0.276 0.358 0.450

0.035 0.051 0.068 0.088 0.111

0.016 0.022 0.028 0.035

12”

5 000 6 000 7 000 8 000 9 000

640.8 769.0 897.1 1025 1153

… … … … …

18.8 27.1 36.9 … …

8.85 12.7 17.2 22.5 28.5

4.56 6.57 8.94 11.7 14.9

1.42 2.03 2.76 3.59 4.54

0.55 2 0.794 1.07 1.39 1.76

0.136 0.195 0.262 0.339 0.427

0.043 0.061 0.082 0.107 0.134

0.018 0.025 0.034 0.044 0.055

10 000 11 000 12 000 13 000 14 000

1282 1410 1538 1666 1794

… … … … …

… … … … …

35.2 … … … …

18.4 22.2 26.4 31.0 36.0

5.60 6.78 8.07 9.47 11.0

2.16 2.62 3.09 3.63 4.21

0.526 0.633 0.753 0.884 1.02

0.164 0.197 0.234 0.273 0.316

0.067 0.081 0.096 0.112 0.129

15 000 16 000 18 000 20 000 22 000

1922 2051 2307 2563 2820

… … … … …

… … … … …

… … … … …

… … … … …

12.6 14.3 18.2 22.4 27.1

4.84 5.50 6.96 8.60 10.4

1.17 1.33 1.68 2.01 2.50

0.364 0.411 0.520 0.642 0.771

0.148 0.167 0.213 0.260 0.314

24 000 26 000 28 000 30 000

3076 3332 3588 3845

… … … …

… … … …

… … … …

… … … …

32.3 37.9 … …

12.4 14.5 16.9 19.3

2.97 3.49 4.04 4.64

0.918 1.12 1.25 1.42

0.371 0.435 0.505 0.520

11.8 13.5 15.3 19.3 23.9

8”

10” 37.3

the system. If the line pressure drop is a small portion of the total, little will be gained by increasing the pipe size. Consider reducing losses through items in step 5 above. Recheck other pipe sizes as may be indicated.

15.26 Velocity of Compressible Fluids in Pipe See Figures 15.29a and 15.29b.



2.40 W V 3.06 WV 3.06W = = 2 a d2 dρ

(15.237)

16670 W V 21220 WV 21220 W = = a d2 d 2ρ

(15.238)

vm = In SI units



vm =

216  Petroleum Refining Design and Applications Handbook Volume 2 Table 15.19b  Discharge of air through an orifice* in cubic feet of free air per minute at standard atmospheric pressure of 14.7 lb. per sq. in. absolute and 70°F. Diameter of orifice 1 " 64

1 " 32

1 " 16

1 " 8

1 " 4

3 " 8

1 " 2

5 " 8

3 " 4

7 " 8

1

16.2

28.7

45.0

64.7

88.1

115

10.1

22.8

40.5

63.3

91.2

124

162

3.10

12.4

27.8

49.5

77.5

111

152

198

0.892

3.56

14.3

32.1

57.0

89.2

128

175

228

0.248

0.993

3.97

15.9

35.7

63.5

99.3

143

195

254

0.068

0.272

1.09

4.34

17.4

39.1

69.5

109

156

213

278

7

0.073

0.293

1.17

4.68

18.7

42.2

75.0

117

168

230

300

9

0.083

0.331

1.32

5.30

21.2

47.7

84.7

132

191

260

339

12

0.095

0.379

1.52

6.07

24.3

54.6

97.0

152

218

297

388

15

0.105

0.420

1.68

6.72

26.9

60.5

108

168

242

329

430

20

0.123

0.491

1.96

7.86

31.4

70.7

126

196

283

385

503

25

0.140

0.562

2.25

8.98

35.9

80.9

144

225

323

440

575

30

0.158

0.633

2.53

10.1

40.5

91.1

162

253

368

496

648

35

0.176

0.703

2.81

11.3

45.0

101

180

281

405

551

720

40

0.194

0.774

3.10

12.4

49.6

112

198

310

446

607

793

45

0.211

0.845

3.38

13.5

54.1

122

216

338

487

662

865

50

0.229

0.916

3.66

14.7

58.6

132

235

366

528

718

938

60

0.264

1.06

4.23

16.9

67.6

152

271

423

609

828

1082

70

0.300

1.20

4.79

19.2

76.7

173

307

479

690

939

1227

80

0.335

1.34

5.36

21.4

85.7

193

343

536

771

1050

1371

90

0.370

1.48

5.92

23.7

94.8

213

379

592

853

1161

1516

100

0.406

1.62

6.49

26.0

104

234

415

649

934

1272

1661

110

0.441

1.76

7.05

28.2

113

254

452

705

1016

1383

1806

Gauge pressure before orifice in pounds per sq. in.

Discharge in cubic feet of free air per minute

1………….

0.028

0.112

0.450

1.80

7.18

2………….

0.040

0.158

0.633

2.53

3………….

0.048

0.194

0.775

4………….

0.056

0.223

5………….

0.062

6

(Continued)

Fluid Flow  217 Table 15.19b  Discharge of air through an orifice* in cubic feet of free air per minute at standard atmospheric pressure of 14.7 lb. per sq. in. absolute and 70°F. (Continued) Diameter of orifice 1 " 64

1 " 32

1 " 16

1 " 8

1 " 4

3 " 8

1 " 2

5 " 8

3 " 4

7 " 8

1

274

488

762

1097

1494

1951

284

506

790

1138

1549

2023

Gauge pressure before orifice in pounds per sq. in.

Discharge in cubic feet of free air per minute

120

0.476

1.91

7.62

30.5

122

125

0.494

1.98

7.90

31.6

126

Table is based on 100% coefficient of flow. For well rounded entrance multiply values by 0.97. For sharp edged orifices a multiplier of 0.65 may be used for approximate results. Values for pressures from 1 to 15 lbs gauge calculated by standard adiabatic formula. Values for pressures above 15 lb. gauge calculated by approximate formula proposed by S.A. Moss. aCP1 where Wa = 0.5303 T1 W = discharge in lbs. per sed. a C = Coefficient of flow a = area of orifice in sq. in. P1 = Upstream total pressure in lbs per sq. in. absolute T1 = Upstream temperature in °F, abs. Values used in calculating above table were: C = 1.0, P1 = gauge pressure + 14.7 lbs/sq. in. Weights (W) were converted to volume using density factor of 0.07494 lbs/cu. ft. This is correct for dry air at 14.7 lbs per sq. in. absolute pressure and 70°F. Formula cannot be used where P1 is less than two times the barometric pressure. By permission ”Compressed Air Data”, F. W. O’Neil, Editor, Compressed Air Magazine, 5th Edition, New York, 1939 [49].

where vm = mean velocity in pipe, at conditions stated for V, ft/min (m/s) a = cross-sectional area of pipe, in2 (mm2) W = flow rate, lb/h (kg/h) V = fluid specific volume, ft3/lb (m3/kg) d = inside pipe diameter, in. (mm) ρ = fluid density, lb/ft3 (kg/m3) at T and P Note that determining the velocity at the inlet conditions to a pipe may create significant error when results are concerned with the outlet conditions, particularly if the pressure drop is high. Even the average of inlet and outlet conditions is not sufficiently accurate for some systems; therefore conditions influenced by pressure drop can produce more accurate results when calculations are prepared for successive sections of the pipe system (long or high pressure). Example 15.16: Steam Flow Using Babcock Formula Determine the pressure loss in 138 feet of 8-in. Sch, 40 steel pipe, flowing 86,000 pounds per hour of 150 psig steam (saturated). Use Figure 15.28, w = 86,000/60 = 1432 lb/min Reading from top at 150 psig, no superheat, down vertically to intersect the horizontal steam flow of 1432 lb/min, follow diagonal line to the horizontal pipe size of 8 in. and then vertically down to the pressure drop loss of 3.5 psi/100 ft. For 138 ft (no fittings or valves), total ΔP is 138 (3.5/100) = 4.82 psi. For comparison, solve by equation, using value of F = 587.1 × 10−9 from Table 15.20.



ΔP/100 ft = (1432)2(587.1 × 10−9)/0.364

218  Petroleum Refining Design and Applications Handbook Volume 2 AVERAGE PRESSURE – LB. PER SQ. IN. ABSOLUTE

1 0 100 200 300 400 500 600 700 100000

SUPERHEATDEGREES FAHRENHEIT

5 1. 2

3 4 5 6 8 10 15 20 30 40 50 60 80 0 10 0 15 0 20

0 30 0 400 500 60 0 80 00 10 00 15 00 20

400 500 FAHR. Q 600 E 700 RE - D 800 ERATU 900 EMP 1000 EAM T 1100 ST

300

200

60 50

600000 400000

40

20000 10000

30

6000 4000

60 40

3

20 10

2

6 4 2 1.0

1

0.6

COPYRIGHT-WALWORTH COMPANY -1937

.2 01

30 40

.5

20

0.8

4 5 6 8 10

.75

.6 .4

STEAM FLOW IN POUNDS PER MINUTE

4

.01

.5

1

100

5

2

.75

1.5 1.25

200

6

.3 .4 .5 .6 .8 1.0

1

2

8

.2

1.5

1.25

2.5

600 400

.03 .04 .05 .06 .08 0.1

2

5 4.5 4 3.5 3

1000

.02

2.5

12 11 10 9 8 7 6

2000

16 14 12 10 ACTUAL INSIDE DIAMETER OF PIPE - INCHES

12 11 10 9 8 7 6 5 4.5 4 3.5 3

NOMINAL SIZE – STANDARD WEIGHT PIPE

NOMINAL SIZE – EXTRA STRONG PIPE

20

PRESSURE LOSS IN LB. PER SQ. INCH PER 100 FEET w2L 3.6 ) 5 Based on Backcock Formula : – P = 0.00013 (1+ d pd

Figure 15.28  Steam flow chart (by permission from Walworth Co. Note: Used for estimating only (Ludwig [19])).



= 3.31 psi/100 ft

ΔPtotal = (3.31/100)(138) = 4.57 psi These values are within graphical accuracy. For the discharge of compressible fluids from the end of a short piping length into a larger cross-section, such as a larger pipe, vessel, or atmosphere, the flow is considered adiabatic. Corrections are applied to the Darcy equation

Fluid Flow  219 Table 15.20  Factor “F” for Babcock steam formula*. Nominal pipe size in.

*Standard weight pipe

#Extra strong pipe

½

955.1 × 10−3

2.051 × 10−3

¾

184.7 × 10−3

340.8 × 10−3

1

45.7 × 10−3

77.71 × 10−3

1¼

9.432 × 10−3

14.67 × 10−3

1½

3.914 × 10−3

5.865 × 10−3

2

951.9 × 10−6

1.365 × 10−3

2½

351.0 × 10−6

493.8 × 10−6

3

104.7 × 10−6

143.2 × 10−6

3½

46.94 × 10−6

62.95 × 10−6

4

23.46 × 10−6

31.01 × 10−6

5

6.854 × 10−6

8.866 × 10−6

6

2.544 × 10−6

3.354 × 10−6

8

587.1 × 10−9

748.2 × 10−9

10

176.3 × 10−9

225.3 × 10−9

12

70.32 × 10−9

90.52 × 10−9

14 O.D.

42.84 × 10−9

55.29 × 10−9

16 O.D.

21.39 × 10−9

27.28 × 10−9

18 O.D.

11.61 × 10−9

14.69 × 10−9

20 O.D.

6.621 × 10−9

8.469 × 10−9

24 O.D

2.561 × 10−9

3.278 × 10−9

*Factors are based upon I.D. listed as Schedule 40. #Factors are based upon I.D. listed as Schedule 80. By permission, The Walworth Co.

220  Petroleum Refining Design and Applications Handbook Volume 2 to compensate for fluid property changes due to the expansion of the fluid, and these are known as Y net expansion factors [4]. The corrected Darcy equation is: For valves, fittings, and pipe (vapors/gases): English Engineering units



w = 0.525 Yd i2 ∆Ρ ρ1 /K , lb/s

(15.239)



w = 1891Yd i2 ∆Ρ ρ1 /K , lb/h.

(15.240)

In SI units

600 500 400

.06 .08

8 .2

4

3

2–

1.5 1– .8 .6 .5 .4 .3 .2

.15

.10 200 300 400 500 600 700 800 900 1000 1100 1200

1.2

1¼

.3 .4 .5 .6 1.0

2 2.5 3 4 5 6 10

150

2

V 60 40 30 20 10 6 4 3 2 1 .6 .4 .2 .1

100 80 60 50 40 30 20 15 10 8 6 5 4 3

3

3

3.5

”

nal mi No e Size ” 2 Pip ” 2½

200 V – Velocity, in Thousands of Feet per Minute

6 5

1”

1.6 1.8 2

300

.10

.9 1.0

1.4

d - Internal Diameter of Pipe, in Inches

10

8

t - Temperature, in Degrees Fahrenheit

1000 800

.04 .05

W - Rate of Flow, in Thousands of Pounds per Hour

15

.03

ρ – Weight Density, in Pounds per Cubic Foot

Steam

1

20

–V – Specific Volume, in Cubic Feet per Pound

rated

Satu

10 uge 15 h ga - inc 20 e r a squ 25 -per 30 unds o p 40 50 60 70 80 100 120 14600 1 0 1800 2 250 300 350 400 500 600 7000 80 0 90000 1 0 120 0 140 0 16000 18 00 20 0 240 0 280 1.5 319

d

W 1500

Index

3.06 W 3.06 WV = d2 d2 ρ

5

(15.241)

V=

0

– V 30

ρ

∆Ρ , kg /s (KV1 )

–

w = 1.111 × 10−6 Yd i2



3” ” 3½

4”

4 5”

5

6”

6 7

8”

8 9 10

10”

15 20

12” 14” 15” 18” 20” 24”

2 1.5

30

0 160 140 120 10 80 60 40 20

1

25

Schedule Number

Figure 15.29a  Velocity in compressible flow lines (reprinted/adapted with permission from “Flow of Fluids Through Valves, Fittings, and Pipe”, Technical Paper No. 410, 1999, Crane, Co. All rights reserved).

Fluid Flow  221

− V

1.5 1 .8

2

2.5

3 ge r gau a b 4 5 6 7

.6 .5 .4

eam d St rate Satu

8 9 10 12 14 16 18 20 25

.3 .2 .15

30

.10

35

40 45 50 60 0 7 80

.08 .06 .05 .04

100

120

.03

140 160 180 200

.02 .015 .01 .008

100

200

300

400

500

600

700

4 5 6 8 10

20 25 30 40 50 60

100 80 V 103 20 10 6 4 2 1 .6 .4 .2 .1 .06 .04 .02

80 100

60 50 40 30 20 15 10 8 6 5 4

40 45 50

80 90 100

3” 3½”

4” 5”

150 200 250

2

350 400

.6 .5

nal omi 2” Nipe Size P 2½”

70

3

1.0 .8

450 500

6” 8” 10” 12” 14” 16” 18” 20” 24”

600 700 800

20 40 60 80 100 120 140 160

200

60

300

1.5

1¼” 1½”

35

200

.006

Temperature °C

30

150 2 2.5 3

1”

25

Internal Diameter of Pipre, in millimetres

1.5

d 20

300

.8 1.0

Rate of Flow, in thousands of kilograms per hour

1.0

Velocity, in thousands of metres per minutes

0.5

.5 .6

2

Specific Volume, in cubic meters per kilogram

0

Index

ρ

Density, in kilograms per cubic metre

Specific Volume of Steam

W 103 700 600 500 400

Schedule Number

Figure 15.29b  Velocity in compressible flow lines (metric units) (reprinted/adapted with permission from “Flow of Fluids Through Valves, Fittings, and Pipe”, Technical Paper No. 410, 1999, Crane, Co. All rights reserved).



w = 1.265 Yd i2

∆Ρ ρ1 , kg/h K

(15.242)

For nozzles and orifices (vapors/gases): English Engineering units

w = 0.525 Yd i2 C′



∆Ρ , lb/s. V1

(15.243)

In SI units



w = 1.111 × 10−6 Yd i2 C′ For valves, fittings, and pipe (liquids):

∆Ρ , kg /s (KV1 )

(15.244)

222  Petroleum Refining Design and Applications Handbook Volume 2 English Engineering units



w = 0.525 d12

∆Ρ(ρ1 ) , lb/s K

(15.245)

In SI units



w = 1.111 × 10−6 d i2

∆Ρ(ρ1 ) , kg /s K

(15.246)

For nozzles and orifices (liquids): English Engineering units



w = 0.525 d i2 C′ ∆P(ρ1 ), lb/s

(15.247)

w = 1.111 × 10−6 d i2 C′ ∆Ρ(ρ1 ), kg /s

(15.248)

In SI units



where di = pipe inside diameter, in. (mm) ρ1 = upstream fluid density, lb/ft3 (kg/m3) w = rate of flow, lb/s (kg/s) ΔP = pressure drop across the system, psi, (bar) (inlet-discharge) K = total resistance (loss) coefficient of pipe, valves, fittings, and entrance and exist losses in the line Y = net expansion factor for compressible flow through orifices, nozzles, and pipes [3] (see Figures 15.25a, b, or c) ΔP = pressure drop ratio in ΔP/P , used to determine Y from Figures 15.25a and 15.25b. The ΔP is the difference between the inlet pressure and the pressure in the area of larger cross-section. C = flow coefficient for orifices and nozzles (Figures 15.15 and 15.16) For example, for a line discharging a compressible fluid to atmosphere, the ΔP is the inlet gauge pressure or the difference between the absolute inlet pressure and atmospheric pressure absolute. When ΔP/P falls outside the limits of the K curves on the charts, sonic velocity occurs at the point of discharge or at some restriction within the pipe, and the limiting value for Y and ΔP must be determined from the tables on Figures 15.25a, 15.25b and used in the velocity equation, vs, above [4]. Figures 15.25a and 15.25b are based on the perfect gas laws and for sonic conditions at the outlet end of a pipe. For gases/vapors that deviate from these laws, such as steam, the same application will yield about 5% greater flow rate. For improved accuracy, use the charts in Figures 15.25a and 15.25b (SI) to determine the downstream pressure when sonic velocity occurs. Then use the fluid properties at this condition of pressure and temperature in:



v s = kgRT = kg144P′V , ft /s or v s = γRT = γP′V , m/s

(15.249) (15.250)

Fluid Flow  223 to determine the flow rate at this condition from



v = q/A = 183.3 q/d2 = 0.0509 W/(ρ)(d2), ft/s

(15.251)

In SI units

v = q /A = 1.273 × 106 q /d 2 = 21.22



Q W = 354 2 , m/s 2 ρd d

(15.252)

where d = internal diameter of pipe, in. (mm) A = cross-section of pipe, ft2 (m2) q = ft3/s (m3/s) at flowing conditions T = temperature, °R (K =273 + t) t = fluid temperature, °C k = γ = ratio of specific heats (Cp/Cv) P = pressure, psia (N/m2 abs) W = flow, lb/h (kg/h) v = velocity, mean or average, ft/s (m/s) These conditions are similar to flow through orifices, nozzles and venturi tubes. Flow through nozzles and venturi devices is limited by the critical pressure ratio, rc = downstream pressure/upstream pressure at sonic conditions (see Figure 15.25c). For nozzles and venturi meters, the flow is limited by critical pressure ratio and the minimum value of Y to be used. For flow of gases and vapors through nozzles and orifices:

q = YC′A



2g(144 )∆Ρ 3 , ft /s ρ

(15.253)

In SI units



or q = YC′ A

2 ∆Ρ 3 , m /s ρ

(15.254)

where β = ratio of orifice throat diameter to inlet diameter C = flow coefficient for nozzles and orifices (see Figures 15.15 and 15.16), when used as per ASME specification for differential pressure ρ = fluid density, lb/ft3, (kg/m3) A = cross-sectional flow area, ft2 (m2 ) Note: the use of C eliminates the calculation of velocity of approach. The flow coefficient C is C ′ = C d / 1 − β 4 , Cd = discharge coefficient for orifices and nozzles [4]. For compressible fluids flowing through nozzles and orifices use Figures 15.15 and 15.16, using hL or ΔP as differential static head or pressure differential across taps located one diameter upstream, and 0.5 diameters downstream

224  Petroleum Refining Design and Applications Handbook Volume 2 from the inlet face of orifice plate or nozzles, when values of C are taken from Figures 15.15 and 15.16 [4]. For any fluid: 1/ 2

 2g(144 )∆Ρ   3 q = C′A    , ft /s ρ   



(15.255)

In SI units



q = C′ A

2 ∆Ρ 3 , m /s flow ρ

(15.256)

For estimating purposes for liquid flow with viscosity similar to water through orifices and nozzles, the following can be used [7]:



Q = 19.636 C′d12 h

1 d  1−  o   di 

4

, gpm

(15.257)

, l/ min

(15.258)

In SI units

Q = 0.2087 C′d12 h





where



1 d  1−  o   di 

4

do is greater than 0.3 di

Q = 19.636 C′d o2 h where

do is less than 0.3 di

(15.259) (15.260)

In SI units



Q = 0.2087 C′d o2 h , l/ min or [4], W = 157.6 d o2 C′ h Lρ2



= 1891d o2 C′ ∆Ρρ

(15.261) (15.262) (15.263)

In SI units



W = 0.01252 d o2 C h Lρ2 = 1.265 d o2C ∆p ρ

(15.264)

where Q = liquid flow, gpm (l/min) C = fl  ow coefficient for orifices and nozzles = discharge coefficient corrected for velocity of approach = Cd / 1 − β4

Fluid Flow  225 do = diameter of orifice or nozzle opening, in. (mm) di = pipe inside diameter in which orifice or nozzle is installed, in. (mm) h = static pressure head existing at a point, in. (meters) of fluid. hL = loss of static pressure head due to fluid flow, m of fluid. C = flow coefficient (see Figure 15.30 for water and Figures 15.15 and 15.16 for vapors or liquids) q = ft3/s (m3/s) at flowing conditions rc = critical pressure ratio for compressible flow, = P2′ /P1′ ΔP = pressure drop, psi Δp = pressure drop, bar (hL and Δp measured across taps at 1 diameter and 0.5 diameter) W = flow rate, lb/h (kg/h) Flow of gases and vapors (compressible fluids) through nozzles and orifices [40]. (For flow field importance see [41]). From [4]: 1/ 2

 2g(144 )∆Ρ   q = YC′ A    ρ  



, ft 3/s

(15.265)

(at flowing conditions) In SI units



q = YC′A 2∆p/ρ, m3/s

(15.266)

Y = net expansion factor from Figures 15.25A or 15.25B ΔP = differential pressure (equal to inlet gauge pressure when discharging to atmosphere) ρ = weight density of fluid, lb/ft3 (kg/m3) at flowing conditions A = cross-section area of orifice or nozzle, ft2 (m2) C = flow coefficient from Figure 15.15 or 15.16



W = 1891 Yd o2C′



∆Ρ , lb/h. V1

(15.267)

or W = 1.265 d o2 C′ ∆p ρ1 , kg /h

(15.268)

where do = internal diameter of orifice, in. (mm) V1 = specific volume of fluid, ft3/lb (m3/kg) RE-ENRTANT TUBE

SHARPEDGED

LENGTH: 1/2 to 1 DIA

C= .52

C= .61C

SQUAREEDGED

RE-ENTRANT TUBE

STREAM CLEARS SIDES

LENGTH: 2-1/2 DIA.

C= .61

C= .73

SQUAREEDGED

WELL ROUNDED

TUBE FLOWER TUBE

C= .82

C= .98

Figure 15.30  Discharge coefficients for liquid flow (by permission, Cameron Hydraulic data, Ingersol – Rand Co., Washington, NJ, 1979).

226  Petroleum Refining Design and Applications Handbook Volume 2 ρ1 = density of fluid, lb/ft3. (kg/m3) Δp = pressure drop, pis (bar)

q ′ = 11.30 Yd o2 C′



∆Ρ P1′ 3 , ft /s T1S g

(15.269)

at 14.7 psia and 60°F where Sg = Sp Gr gas relative to air, = mol wt. gas/29 T1 = absolute temperature, °R = (460 + °F) P1′ = pressure, psia In SI units



q = 0.005363Yd o2 C′

p p1′ , m3/s T1S g

(15.270)

where T1 = 273.15 + t t = fluid temperature, °C p1′ = pressure, bara Δp = pressure drop, bar Sg = Sp Gr gas relative to air, = mol wt. gas/29 Y = net expansion factor compressibility flow through orifices, nozzles, or pipe. Example 15.17 What is the flow rate of natural gas through a ruptured exchanger tube assuming (1) a complete break near the tube sheet (see Figure 15.23), and (2) isothermal flow? Compare the flow rate to adiabatic condition. The following data are [39]: Pressure in exchanger tubes, P1, psig

1,110

Relief valve set pressure, P2, psig

400

Gas temperature, °F

100

Compressibility factor, Z

0.9

Molecular weight

18.7

Ratio of specific heats k = Cp/Cv

1.3

Gas viscosity, μ, cP

0.1

Exchanger tubes, ¾ in. Schedule 160, ID. in.

0.614

Tube length, ft.

20

Friction factor for complete turbulence, f

0.025

Fluid Flow  227 Solution Internal diameter of ¾ inch Schedule 160 = 0.614 in. = 0.051 ft.

Upstream density is ρ1 =

=

M w P1 10.72 ZT (18.7 )(1110 + 14.77 ) (10.72)(0.9)(100 + 460)

= 3.892 lb/ft 3



Total resistance (loss) coefficient KTotal is:

 L K Total =  f T +  D

∑K + K f

entrance

 + K exit  

  20 + 0.5 + 1.0 =  0.025   0.0051



= 11.30



Pressure in the exchanger, P1 = 1110 + 14.7 = 1124.7 psia Relief valve set pressure, P2 = 400 + 14.7 = 414.7 psia Using Eq. 15.188, the gas flow rate through the ruptured tube is

   P12 − P22   ρ1 G = 1335.6 d    P1    P1    K + 2 ln      Total  P2   2

0.5 , lb/h

   1124.7 2 − 414.7 2   3.892 G = 1335.6(0.614)      1124.7  11.3 + 2 ln (1124.7 / 414.7 )    = 8492.5 lb/h 2



Gas Reynolds number is:

Re = 6.31



G 8492.5 = 6.31 dµ (0.614 )(0.1)

= 8.7 × 105 (fully turbulence)



Gas velocity v is:



v = 0.0509

G 8492.5 = 0.0509 2 d ρ1 (0.614 )2 (3.892)

= 294.61 ft /s.



0.5



(15.153)

228  Petroleum Refining Design and Applications Handbook Volume 2 Sonic velocity vs is:

v s = 68.1 kP1 /ρ1

= 68.1 (1.3)(1124.7)/(3.892) = 1319.9 ft /s.



The Mach number at the inlet Ma1:

Ma1 =



v 294.61 = v s 1319.9

= 0.223



Since the Mach number is less than 1, the flow through the pipe is subsonic. At adiabatic condition, the net expansion factor Y is:

ΔP/P1 = (1124.7 – 414.7)/1124.7 = 0.63 The loss coefficient KTotal = 11.3 From Figure 15.25a, Y at ΔP/P = 0.63 and k = 1.3 by interpolation is Y = 0.77 Using Eq. 15.234, the gas flow rate is:

w s = 1891Yd i2 ∆Ρ ρ1 /K , lb/h. = (1891)(0.77 )(0.614 )2



(710)(3.892) (11.3)

= 8584.1 lb/h



The percentage deviation between the two conditions (isothermal and adiabatic) is 1.07%. As such, there is very little difference in flow rate between the two conditions. However, the adiabatic flow rate is always greater than the isothermal flow rate. Table 15.21 shows the computer result of Example 15.17 at isothermal condition using developed program prog33.for with data file DATA33.DAT. The Excel spreadsheet Example 15.17.xlsx gives calculations for isothermal and adiabatic conditions of the above example.

15.27 Procedure A. How to determine pipe size for given capacity and pressure drop. 1. A  ssume a pipe diameter, and calculate velocity in ft/s using the given flow. 2. Calculate sonic velocity for fluid using Eqs. 15.174–15.179. 3. If sonic velocity of step 2 is greater than calculated velocity of step 1, calculate line pressure drop using usual flow equations. If these velocities are equal, then the pressure drop calculated will be the maximum for the line, using usual flow equations. If sonic velocity is less than the velocity of step 1, reassume line size and repeat calculations.

Fluid Flow  229 Table 15.21  Input data and computer results for maximum compressible fluid in a pipe line. DATA33.DAT 0.614 20.0 0.026 2.026 0.9 100.0 18.7 1124.7 414.7 1.3 0.1 Compressible fluid flow calculations in a pipe line Pipe internal diameter, in:

0.614

Straight length of pipe, ft:

20.000

Maximum fluid flow rate, lb/h:

8222.85

Fluid density, lb/ft^3:

3.893

Pipe friction factor:

0.0260

Fluid compressibility factor:

0.9000

Fluid temperature, °F:

100.000

Fluid molecular weight, Mw:

18.700

Ratio of specific heat capacities, Cp/Cv:

1.300

Fluid viscosity, cP:

0.1000

Resistance coeff. due to frictional loss:

10.163

Resistance coeff. due to fittings + valves:

2.026

Total resistance coefficient:

12.189

Inlet fluid pressure, psia:

1124.700

Outlet fluid pressure, psia:

414.700

Pressure drop, psi:

710.000

Fluid velocity, ft/s:

285.201

Fluid sonic velocity, ft/s:

1391.393

Mach number at inlet:

0.2050

Mach number at critical condition:

0.8771

Reynolds number:

845052.

Critical pressure, psia:

237.926

Fluid flow is:

SUBSONIC

230  Petroleum Refining Design and Applications Handbook Volume 2 B. How to determine flow rate (capacity) for a given line size and fixed pressure drop. This is also a trial and error solution following the pattern of (A), except capacities are assumed and the pressure drops are calculated to find a match for the given conditions of inlet pressure, calculating back from the outlet pressure. C. How to determine pressure at inlet of pipe system for fixed pipe size and flow rate. Determining the sonic flow rate involves knowledge of the local conditions at the exit. However, this is difficult to establish and highly complicated in practice as it requires extensive iterative computations. Example 15.18: Gas Flow Through Sharp-Edged Orifice A 1-in. Sch. 40 pipe is flowing methane at 40 psig and 50°F. The flange taps across the orifice (0.750 in. diameter) show a 3 psi pressure differential. Determine the flow rate through the orifice. Solution CH4; Sp Gr = Sg = 0.553 Gas Constant = R = 96.5 Ratio of specific heat = k = 1.26 Absolute system pressure = P = 40 + 14.7 = 54.7 psia ΔP/P1 = 3.0/54.7 = 0.0549 Pipe ID = 1.049 in. do/d1 = 0.750/1.049 = 0.7149 From Figure 15.25a, Y = 0.97; From Figure 15.16.



C′(assumed turbulent ) =

Cd

12

1 − ( d /d )4  o 1  



where Cd = orifice discharge coefficient, uncorrected for velocity of approach.

C = 0.74 at est. Re ≥ 2000 Temperature = 460 + 50 = 510°F

Density = ρ =



144P 144(54.7 ) = RT (96.5)(510)

= 0.160 lb/ft 3





W = 1891 Yd C (∆Ρ ρ)



W = 1891(0.97)(0.750)2(0.74)[(3)(0.160)]1/2



W = 529 lb/h methane

2 o

1/ 2

Checking: Calculate Re to verify turbulence; if not in reasonable agreement, recalculate C and balance of solution, Viscosity of methane Re

= 0.0123 cP = 6.31 W/d μ = 6.31(529)/(0.750)(0.0123) = 36,1841

Fluid Flow  231 This is turbulent and satisfactory for the assumption. For helpful quick reference for discharge of air through an orifice, see Table 15.19b.

15.28 Friction Drop for Compressible Natural Gas in Long Pipe Lines Tests of the U.S. Department of the Interior, Bureau of Mines, reported in Monograph 6 Flow of Natural Gas Through High-Pressure Transmission Lines [42] indicate that the Weymouth formula gives good results on flow measurements on lines 6 in. in diameter and larger when operating under steady flow conditions of 30–600 psig. Long gas transmission lines of several miles length are not considered the same as process lines inside plant connecting process equipment where the lengths usually are measured in feet (meters) or hundreds of feet (meters). Some plants will transfer a manufactured gas, such as oxygen, carbon dioxide, or hydrogen, from one plant to an adjacent plant. Here the distance can be from 1 to 15 miles (kilometers). In such cases, the previously discussed flow relations for compressible gases can be applied in incremental segments, recalculating each segment, and then the results can be checked using one of the formulas that follow. However, there are many variables to evaluate and understand in the Weymouth, Panhandle, Panhandle-A and modifications as well as other flow relationships. Therefore, they will be presented for reference. However, the engineer should seek out the specialized flow discussions on this type of flow condition. The above mentioned equations are derived somewhat empirically for the flow of a natural gas containing some entrained liquid (perhaps 5–12%), and the results vary accordingly, even though they are not two-phase flow equations. Table 15.22 [26] tabulates the transmission factors of the various equations. Most of these are established as correction factors to the correlation of various test data. Dunning [43] recommends this formula (from [42]) for 4 to 24 in. (102–575 mm) diameter lines with specific gravity of gas near 0.60, and actual mean velocities from 15 to 30 fps (4.6–9.1 m/s) at temperature near 60°F (16°C). The Bureau of Mines report states that minor corrections for bends, tees, and even compressibility are unnecessary due to the greater uncertainties in actual line conditions. Their checks with the Weymouth relation omitted these corrections. The relation with pressure base of 14.4 psia is to be used with the Bureau of Mines multipliers [42]. Table 15.22  Dry-gas flow transmission factors. Title

Transmission Factor ( 1/f ) Ref.*

Weymouth

11.2D0.167

Blasius

3.56Re0.125

Panhandle A

6.87Re0.073

Modified Panhandle

16.5Re0.0196

Smooth pipe law (Nikuradse)

4 log Re f − 0.4

Rough pipe law (Nikuradse) Colebrook

(

)

4 log

( D) + 3.48 ( 2ε )

4 log

 D  ( D) + 3.48 − 4 log 1 + 9.35  ( 2ε ) 2 Re f  

(Source: By permission, Hope, P.M. and Nelson, R.G., “Fluid Flow, Natural Gas,” McKetta, J.J. Ed., Encyclopedia of Chemical Processing and Design, vol. 22, M. Dekker,1985, p. 304 [15].) Note: D = inches *See listing of source references in Reference [15].

232  Petroleum Refining Design and Applications Handbook Volume 2 1/ 2

q h (at 14.4 psia and 60°F) = 36.926 d



2.667

 P12 − P22    , scfh  Lm 

(15.265)

1/ 2

q ′h (at 14.4 psia and 60°F) = 28.0 d



2.667

 P12 − P22  520      T   Sg L m

, scfh

(15.266)

Weymouth’s formula [8] has friction established as a function of diameter and may be solved by using alignment charts. The Weymouth formula is also expressed (at standard condition) as: 1/ 2

q d = 433.9 E d

E d Ts Ps T1 qd P1′ P2′ Z L SCC

2.667

 Ts   P1′ 2 − P2′ 2   P   S T L Z  s  g 1 m 

(15.267)

= transmission factor, usually taken as: 1.10 × 11.2 d0.167 (omit for pipe size smaller than 24 in.) = Pipe, ID, in. = 520 °R = 14.7 psia = flowing temperature of gas, °R = flow rate, cu ft/day (at std conditions, SCC of 14.7 psia and 520°R) = inlet pressure, psia = outlet pressure, psia = compressibility factor = pipe length, miles = Standard condition (14.7 psia and 60°F)

or from [4]: 1/ 2

2 2    520   2.667  ( P1′) − ( P2′ )  q h = 28.0 d     T     S g L m



(15.268)

where d = pipe internal diameter, in. T = flowing temperature of gas, °R Sg = specific gravity of gas qh = gas flow rate ft3/h, at 60 °F and 14.4 psia P1′ = inlet pressure, psia P2′ = outlet pressure, psia Z = compressibility factor Lm = pipe length, miles In SI units 1/ 2



2 2   288   −8 2.667  ( P1′) − ( P2′ ) 3 q ′h = 2.61 × 10 d      , m /h  S g L m  T 

(15.269)

Fluid Flow  233 where d = internal pipe diameter, mm T = flowing temperature of gas, K = (273 + °C) qh = m3/h gas at metric std conditions (MSC) of Ps and Ts P1′ = inlet pressure, N/m2 abs P2′ = outlet pressure, N/m2 abs Z = compressibility factor Lm = pipe length, km MSC = Metric standard conditions (1.01325 bara and 15°C)

Example 15.19: Use of Base Correction Multipliers Tables 15.23–15.26 are set up with base reference conditions. In order to correct or change any base condition, the appropriate multiplier(s) must be used. A flow of 5.6 × 106 ft3/day has been calculated using Weymouth’s formula [8], with these conditions: measuring base of 60°F and 14.4 psia; flowing temperature of 60°F, and specific gravity of 0.60. Suppose for comparison purposes the base conditions must be changed to measuring base of 70°F and 14.7 psia; flowing temperature of 80°F, and specific gravity of 0.74. Multipliers from the tables are: Pressure base:

0.9796

Temperature base:

1.0192

Specific gravity base:

0.9005

Flowing temperature base:

0.9813

Table 15.23  Pressure-base multipliers for quantity. Multiplier =

14.4 New pressure base, lbs/sq . in. abs

New pressure base (lb/in.2 abs)

Multiplier

12.00

1.2000

13.00

1.1077

14.00

1.0286

14.40

1.0000

14.65

0.9829

14.7

0.9796

14.9

0.9664

15.4

0.9351

16.4

0.8780

(Source: By permission, Johnson, T. W. and Berwald, W. B., Flow of Natural Gas Through High Pressure Transmission Lines, Monograph No. 6, U.S. Dept. of Interior, Bureau of Mines, Washington, DC.)

234  Petroleum Refining Design and Applications Handbook Volume 2 Table 15.24  Temperature-base multipliers for quantity. Multiplier =

460 + new temperature base , °F 460 + 60

New pressure base, lbs/sq. in. abs

Multiplier

45

0.9712

50

0.9808

55

0.9904

60

1.0000

65

1.0096

70

1.0192

75

1.0288

80

1.0385

85

1.0481

90

1.0577

95

1.0673

100

1.0769

(Source: By permission, Johnson, T. W. and Berwald, W. B., Flow of Natural Gas Through High Pressure Transmission Lines, Monograph No. 6, U.S. Dept. of Interior, Bureau of Mines, Washington, DC.)

Table 15.25  Specific gravity multipliers for quantity.   0.600 Multiplier =    actual specific gravity 

1

2

Specific gravity

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.5

1.0954

1.0847

1.0742

1.0640

1.0541

1.0445

1.0351

1.0260

1.0171

1.0084

0.6

1.0000

0.9918

0.9837

0.9759

0.9682

0.9608

0.9535

0.9463

0.9393

0.9325

0.7

0.9258

0.9193

0.9129

0.9066

0.9005

0.8944

0.8885

0.8827

0.8771

0.8715

0.8

0.8660

0.8607

0.8554

0.8502

0.8452

0.8402

0.8353

0.8305

0.8257

0.8211

0.9

0.8165

0.8120

0.8076

0.8032

0.7989

0.7947

0.7906

0.7865

0.7825

0.7785

1.0

0.7746

0.7708

0.7670

0.7632

0.7596

0.7559

0.7524

0.7488

0.7454

0.7419

1.1

0.7385

0.7352

0.7319

0.7287

0.7255

0.7223

0.7192

0.7161

0.7131

0.7101

(Source: By permission, Johnson, T. W. and Berwald, W. B., Flow of Natural Gas Through High Pressure Transmission Lines, Monograph No. 6, U.S. Dept. of Interior, Bureau of Mines, Washington, DC.)

Fluid Flow  235 Table 15.26  Flowing-temperature multipliers for quantity.   460 + 60 Multiplier =    460 + actual flowing temperature  Temp. °F

1

2

0

1

2

3

4

5

6

7

8

9

1.0632

1.0621

1.0609

1.0598

1.0586

1.0575

1.0564

1.0552

1.0541

1.0530

10

1.0518

1.0507

1.0496

1.0485

1.0474

1.0463

1.0452

1.0441

1.0430

1.0419

20

1.0408

1.0398

1.0387

1.0376

1.0365

1.0355

1.0344

1.0333

1.0323

1.0312

30

1.0302

1.0291

1.0281

1.0270

1.0260

1.0249

1.0239

1.0229

1.0219

1.0208

40

1.0198

1.0188

1.0178

1.0167

1.0157

1.0147

1.0137

1.0127

1.0117

1.0107

50

1.0098

1.0088

1.0078

1.0068

1.0058

1.0048

1.0039

1.0029

1.0019

1.0010

60

1.0000

0.9990

0.9981

0.9971

0.9962

0.9952

0.9943

0.9933

0.9924

0.9915

70

0.9905

0.9896

0.9887

0.9877

0.9868

0.9859

0.9850

0.9841

0.9831

0.9822

80

0.9813

0.9804

0.9795

0.9786

0.9777

0.9768

0.9759

0.9750

0.9741

0.9732

90

0.9723

0.9715

0.9706

0.9697

0.9688

0.9680

0.9671

0.9662

0.9653

0.9645

(Source: By permission, Johnson, T. W. and Berwald, W. B., Flow of Natural Gas Through High Pressure Transmission Lines, Monograph No. 6, U.S. Dept. of Interior, Bureau of Mines, Washington, DC.)

New base flow = (5,600,000) (0.9796) (1.0192) (0.9005) (0.9813) = 4,940,000 cu ft/day

15.29 Panhandle-A Gas Flow Formula The Panhandle equation assumes that the friction factor can be represented by a straight line of constant negative slope in the moderate Reynolds number region of the Moody diagram (Figure 15.5) [4]. The equation is considered to be slightly better than the ± 10 percent accuracy of the Weymouth formula and is given by

 P2 − P22  q g = 0.028 E  0.9611   S g T L m Z 



0.51

d 2.53

(15.270)

or



1.9607

  qg P −P =  2.53   0.028 Ed 

where d = pipe internal diameter, in. L = pipe length, miles P1 = upstream pressure, psia P2 = downstream pressure, psia Sg = gas specific gravity Z = gas compressibility factor

2 1

2 2

S0g.961TL m Z

(15.271)

236  Petroleum Refining Design and Applications Handbook Volume 2 qg = gas flow rate, MMscfd (at 14.7 psia and 60°F) T = gas flowing temperature, °R = 460oF + t E = efficiency factor for flow, use 1.00 for new pipe without bends, elbows, valves and change of pipe diameter or elevation 0.95 for very good operating conditions 0.92 for average operating conditions 0.85 for poor operating conditions In practice, the Panhandle equation is commonly used for longer pipe with a large pipe size (greater than 10 in.) where the Reynolds number is on the straight line portion of the Moody diagram (Figure 15.5). Neither the Weymouth nor the Panhandle represents a “conservative” assumption. If the Weymouth formula is assumed, and the flow is at moderate Reynolds number, the friction factor will be higher than the horizontal portion of the Moody curve, and the actual pressure drop will be higher than calculated. If the Panhandle formula is used and the flow is in a high Reynolds number, the friction factor will be higher than assumed and the actual pressure drop will be higher than calculated. For bends in pipe add to length [27]: Bend radius

Add*, as pipe diameter, de

1 Pipe dia.

17.5

1.5 Pipe dia.

10.4

2 Pipe dia.

9

3 Pipe dia.

8.2

*These must be converted to the unit of length used in the formula.

In SI units Panhandle formula for natural gas pipe lines 150 to 600 mm diameter and Re = (5 × 106) to (14 × 106) is:



 ( p′ )2 − ( p′ )2  2 −3  q ′h = 5.06 × 10 E  1 Lm  

0.5394

d 2.6182 m3/h

(15.272)

or



( p1′ ) − ( p′2 ) 2

2

1.8539

 103 q ′h  = Lm  2.6182  E  5.06 d



(15.273)

where d = internal pipe diameter, mm L = length of pipe in km p1′ = inlet pressure, bara p′2 = outlet pressure, bara q ′h = rate of flow in m3/h at metric standard conditions (MSC) 1.103 bara and 15°C If a line is made up of several different sizes, these may be resolved to one, and then the equation solved once for this total equivalent length. If these are handled on a per size basis, and totaled on the basis of the longest length of one size of line, then the equivalent length, Le, for any size d referenced to a basic diameter, de is

Le = Lm (de/d)4.854

(15.274)

Fluid Flow  237 where Lm is the length of pipe size d to be used. Le is the equivalent length of pipe size d, length Lm after conversion to basis of reference diameter de. The calculations can be based on diameter de and a length of all the various Le values in the line plus the length of line of size de, giving a total equivalent length for the line system.

15.30 Modified Panhandle Flow Formula

T  q DS = 737.2 E  o   Po 

1.02

  P12 (1 + 0.67 Z P1 ) − P22 (1 + 0.67 ZP2 )     T L m G0.961    

0.51

d 2.53

(15.275)

where [26] Lm = length, mi d = inside diameter, in. T = flowing temperature, °R Z = gas deviation, compressibility factor To = base temperature, (520°R) G = gas specific gravity P = pressure, psia Po = base pressure, (14.73 psi, absolute) E = “Efficiency factor,” which is really an adjustment to fit the data qDS = flow rate, SCF/day

15.31 American Gas Association (AGA) Dry Gas Method See Uhl et al. [44] AGA, Dry Gas Manual. Some tests indicate that this method is one of the most reliable above a fixed Reynolds number.

15.32 Complex Pipe Systems Handling Natural (or Similar) Gas The method suggested in the Bureau of Mines Monograph No. 6 [42] has found wide usage, and is outlined here using the Weymouth Formula as a base. 1. Equivalent lengths of pipe for different diameters

L1 = L2(d1/d2)16/3

(15.276)

where L1 = the equivalent length of any pipe of length L2 and diameter, d2, in terms of diameter, d1.

d1 = d2(L1/L2)3/16

(15.277)

where d1 = the equivalent diameter of any pipe of a given diameter, d2 and length L2, in terms of any other length, L1. 2. Equivalent diameters of pipe for parallel lines



(

d o = d18 / 3 + d 82/ 3 ..... + d 8n/ 3

)

3/ 8



(15.278)

238  Petroleum Refining Design and Applications Handbook Volume 2 where do is the diameter of a single line with the same delivery capacity as that of the individual parallel lines of diameters d1, d2,…… and dn. Lines of same length. This value of do may be used directly in the Weymouth formula. Example 15.20: Series System Determine the equivalent length of a series of lines: 5 mi of 14-in. (13.25-in. ID) connected to 3 mi of 10 in. (10.136in. ID) connected to 12 mi of 8-in. (7.981-in. ID). Select 10-in. as the base reference size. The five-mile section of 14-in. pipe is equivalent to:

L1 = 5(10.136/13.25)5.33 = 1.199 mi of 10 in. The 12 mile section of 8 in. is equivalent to:

L1 = 12(10.136/7.981)5.33 = 42.9 mi of 10 in. Total equivalent length of line to use in calculations is:



1.199 + 3.0 + 42.9 = 47.099 mi of 10-in. (10.136-in. ID).

An alternative procedure is to calculate (1) the pressure drop series-wise one section of the line at a time, or (2) capacity for a fixed inlet pressure, series-wise. Example 15.21: Looped System Determine the equivalent length of 25 mi of 10-in. (10.136-in. ID) which has parallel loop of 6 mi of 8-in. (7.981-in. ID) pipe tied in near the mid section of the 10-in. line. Figure the looped section as parallel lines with 6 mi of 8-in. and 6 mi of 10-in. the equivalent diameter for one line with the same carrying capacity is:

do = [(7.981)8/3 + (10.136)8/3]3/8 = 11.9 in. This simplifies the system to one section 6 mi long of 11.9-in. ID (equivalent) pipe, plus one section of 25 minus 6, or 19 mi of 10-in. (10.136-in. ID) pipe. Now convert the 11.9-in. pipe to a length equivalent to the 10-in. diameter.

L1 = 6(10.136/11.9)5.33 = 2.53 mi Total length of 10-in. pipe to use in calculating capacity is 19+2.53 = 21.53 mi. By the principles outlined in the examples, gas pipe line systems may be analyzed, paralleled, cross-tied, and so on. Example 15.22: Parallel System: Fraction Paralleled Determine the portion of a 30 mi, 18-in. (17.124-in. ID) line which must be paralleled with 20-in. (19.00-in. ID) pipe to raise the total system capacity 1.5 times the existing rate, keeping the system inlet and outlet conditions the same.



x=

(q da /q db )2 − 1

 1  2.667  1 + ( d b /d a ) 

{

}

 1 2   



(15.279)

Fluid Flow  239 For this example, qdb = 1.5 qda



x=

(1/1.5)2 − 1 1

  − 1  2  {1 + (19.00/17.124)2.667 } 

= 0.683

This means 68.3% of the 30 mi must be parallel with the new 19-in. ID pipe. Parallel System: New Capacity After Paralleling Solve this relation, rearranged conveniently to [42]

q db =

q da

1/ 2

    1 − 1 + 1 2 x  2.667     1 + (d b /d a ) 



(15.280)

15.33 Two-Phase Liquid and Gas Flow in Process Piping An understanding of two-phase flow is necessary for sound piping design. This is because, almost refinery and chemical process plants encounter two-phase flow conditions. The concurrent flow of liquid and gas in pipelines has received considerable study [45–48]. However, pressure drop prediction is not extremely reliable except for several gas pipe line conditions. The general determinations of pressure drop for plant process lines can only be approximated. The latest two-phase flow research and design studies have broadened the interpretation of some of the earlier flow patterns and refined some design accuracy for selected situations. The method presented here serves as a fundamental reference source for further studies. It is suggested that the designer compares several design concept results and interprets which best encompasses the design problem under consideration. Some of the latest references are included in the Reference Section. However, no one reference has a solution to all two-phase flow problems. If two-phase flow situations are not recognized, pressure drop problems may develop which can prevent systems from operating. It requires very little percentage of vapor, generally above 7% to 8% (by volume), to establish volumes and flow velocities that must be solved by two-phase flow analysis. The discharge flow through a pressure relief valve or a process reactor is often an important example where two-phase flow exists, and must be recognized for its backpressure impact. Two-phase flow often presents design and operational problems not associated with liquid or gas flow. For example, several different flow patterns may exist along the pipeline. Frictional pressure losses are more difficult to estimate, and in the case of a cross-country pipeline, a terrain profile is necessary to predict pressure drops due to elevation changes. The downstream end of a pipeline often requires a separator to separate the liquid and gas phases, and a slug catcher may be required to remove liquid slugs. Static pressure losses in gas-liquid flow differ from those in single-phase flow because an interface can be either smooth or rough, depending on the flow pattern. Two-phase pressure losses may be up to a factor of 10 higher than those in single-phase flow. In the former, the two phases tend to separate and the liquid lags behind. Most published correlations for two-phase pressure drop are empirical and, therefore limited by the range of data for which they were derived [51, 78–80].

15.33.1 Flow Patterns In determining the (type of flow)phase distribution in a process pipeline, designers refer to a diagram similar to Figure 15.31a, which is known as the Baker map. Figure 15.32 shows the types of flow regimes that can exist in a

240  Petroleum Refining Design and Applications Handbook Volume 2 By 100,000 Dispersed Flow

Wave Flow

Bubble or Froth Flow

Annular Flow

10,000

Stratified Flow

Slug Flow

1,000

Plug Flow

100 0.1

0.2

0.4 0.6 0.8 1.0

2

4

6 8 10

2

4 6 8 100

2

4

6 8 1,000 2

4 6 8 10,000

R

Figure 15.31a  Flow patterns for horizontal two-phase flow (based on data from 1, 2, and 4 in. pipe) (source: Baker, O., Oil & Gas Journal Nov. 10, p 156, 1958). By 100,000 DISPERSED C3

C2

WAVE

4”

BUBBLE OR

6”

ANNULAR

FROTH

10,000 C4 C1

SLUG C5

C6

STRATIFIED 1,000

PLUG 100

.1

1

10

100

1,000

10,000

Bx

Figure 15.31b  Baker parameters for horizontal two-phase flow regimes with modified boundaries (based on data from 1, 2, and 4 in. pipe).

horizontal pipe, and Table 15.27 lists the characteristic linear velocities of the gas and liquid phases in each flow regime. Seven types of flow patterns are considered in evaluating two-phase flow, and only one type can exist in a pipeline at a time. But as conditions change (e.g., velocity, roughness, and elevation), the type of flow pattern may also change. The pressure drop can also vary significantly between the flow regimes. The seven types of flow regimes in order of increasing gas rate at a constant liquid flow rate given below:

Fluid Flow  241 SEGREGATED

Stratified

Wavy

Annular INTERMITTENT

Plug

Slug DISTRIBUTED

Bubble

Mist

Figure 15.32  Representatives forms of horizontal two-phase flow patterns, same as indicated in Figures 15.31a (Source: Hein, H., Oil & Gas J., Aug. 2, p. 132, 1982).

Table 15.27  Characteristics linear velocities of two-phase flow regimes. Regime

Liquid phase (ft/s)

Vapor phase (ft/s)

Bubble or froth

5–15

0.5–2

Plug

2

10



(15.317)

where Wm = Mass flow rate of liquid phase, lb/h ft2 (of total pipe cross section area). v = Flow velocity (mean) or superficial velocity in pipe lines at flowing conditions for entire pipe cross section, ft/s. or as an alternative:

Fe = 1.7156 v G−0.702

vG = gas velocity, ft/s

A. To determine most probable type of two-phase flow using Figure 15.31a. 1. Calculate Bx

(15.318)

Fluid Flow  251 2. C  alculate By 3. Read intersection of ordinate and abscissa to identify probable type of flow. Since this is not an exact, clear-cut position, it is recommended that the adjacent flow types be recorded. B. Calculate the separate liquid and gas flow pressure drops. 1. F  or general process application both PL and PG may be calculated by the general flow equation: PL or PG

=



3.36 f D L W 2 (10−6 ) d 5ρ

(15.319)

where fD is the Darcy friction factor obtained from (Reynolds) Moody-Friction Factor chart (Figure 15.5) for an assumed line size, d or from Chen’s explicit equation for friction factor (fD = 4 fC). 2. For gas transmission, in general form [33]

∆PG =



(q d 14.65 )LS g TZ f 20, 000 d 5 Pavg



(15.320)

where qd 14.65 is the thousands of standard cubic feet of gas per day, measured at 60°F and 14.65 psia, and Pavg is the average absolute pressure(psia) in the pipe system between inlet and outlet. This is an estimated value and may require correction and recalculation of the final pressure drop if it is very far off.

where d = internal pipe diameter, in. f = Friction factor, Moody. L = Pipe length, ft Sg = specific gravity of gas relative to air, ( = ratio of molecular weight gas/29) T = Absolute temperature, °R = 460 + °F Z = compressibility factor For oil flow in natural gas transmission lines [45]



f L Q 2b ρ 181, 916 d 5

(15.321)

X = (ΔPL/ΔPG)1/2

(15.322)

∆PL =

where Qb = Flow rate in bbl/day L = Pipe length, ft ρ = Fluid density, lb/ft3 3. Calculate



4. Calculate Φ for types of flow selected from Figure 15.31a and as summarized below [45].

252  Petroleum Refining Design and Applications Handbook Volume 2 Type flow

Equation for (FGTT)

Froth or bubble

Φ = 14.2X0.75 /(WL/A)0.1

Plug

Φ = 27.315X0.855 /(WL/A)0.17

Stratified

Φ = 15,400X /(WL/A)0.8

Slug

Φ = 1,190X0.185 /(WL/A)0.5

Annular*

Φ = (4.8 – 0.3125d)X0.343−0.021d

*set d = 10 for any pipe larger than 10-in.



X = [ΔPL/ΔPG]1/2 5. C  alculate two-phase pressure drop, horizontal portions of lines. For all types of flow, except wave and fog or spray:



2 ∆PTP = ∆PG ΦGTT , psi /ft

(15.323)

f ( G′ ) ∆PTP = TP G , psi /ft 193.2 d ρG

(15.324)

For wave [54]. 2

where

W µ  f TP = 0.0043  m L   G µG 

where fTP G′G G Wm μL μG

0.214



(15.325)

= Two-phase friction for wave flow = Mass rate, lb/s (ft2. cross section) = Mass flow rate of gas phase, lb/h ft2 = Mass flow rate of liquid phase, lb/h ft2 = Liquid viscosity, cP = Gas viscosity, cP

6. T  otal two-phase pressure drop, including horizontal and vertical sections of line. Use calculated value times 1.1 to 2.0, depending upon critical nature of application.



PTPh = PTPL +

n h FeρL 144

(15.326)

where ρL is the density, lb/ft3, of the liquid flowing in the line, and Fe, elevation factor using gas velocity, vG. Use Figure 15.34 for v less than 10. Most gas transmission lines flow from 1 to 15 ft/s. For fog or spray type flow, Baker [45] suggests using Martinelli’s correlation and multiplying results by two [53]. (a) For gas pipe line flow, the values of ( GTT) may be converted to “efficiency E” values and used to calculate the flow for the horizontal portion using a fixed allowable pressure drop in the general flow

Fluid Flow  253 Liquid head factor, Fe 1.0 0.9 Natural Gas Condensate in 16N Pipeline Natural Gas, Oil and Water in 2N Oil Well Tubing Air and Water in lN Vertical Tubing Air and Lube Oil in 2N Inclined Tubing

0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

0

2

4

6

8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 Superficial Gas Velocity, ft/s

Figure 15.34  Estimating pressure drop in uphill sections of pipeline for two-phase flow (source: O. Flanigan, Oil & Gas J., Mar. 10, p 132, 1958).

equation [33]. The effect of the vertical component must be added to establish the total pressure drop for the pumping system.

(

)

0.5

 38.7744 Ts P12 − P22 d 5   E  0.5 q d 14.65 =     1000 P L S TZ   f g   s m g



(15.327)

where 14.65 refers to reference pressure Ps. d = internal pipe diameter, in. E = Gas transmission “efficiency” factor, varies with line size and surface internal condition of pipe. fg = Moody or “regular” Fanning friction for gas flow Lm = Pipe length, mi P1 = initial pressure, psi P2 = final pressure, psi Ps = standard pressure for gas transmission, psia Sg = specific gravity of gas relative to air, ( = ratio of molecular weight gas/ 29) T = Absolute temperature, °R = 460 + °F Ts = Standard temperature for gas measurement, °R = 460 + °F Z = Gas compressibility factor or

(q d 14.65 )2 LS g TZ  f g  ∆PTP =   20, 000d 5Pavg  E 2 



(15.328)

where E = 1/ΦGTT (b) For the Panhandle equation, Baker [45] summarizes:





T  q d 14.65 = 0.43587  s   Ps 

1.07881

 P12 − P22   Z TL  m

0.5394

 d 2.618   S0.4606  (E )  g 

.077 where E (Panhandle) = 0.9/Φ1GTT

(15.329)

(15.330)

254  Petroleum Refining Design and Applications Handbook Volume 2 Example 15.23: Two-Phase Flow A liquid–gas mixture is to flow in a line having 358 ft of level pipe and three vertical rises of 10 ft each plus one vertical rise of 50 ft. Evaluate the type of flow and expected pressure drop. Liquid

Gas

Flow W, lb/h

1000

3000

Density ρ, lb/ft3

63.0

0.077

Viscosity μ, cP

1.0

0.00127

Surface tension σ, dyn/cm

15

Pipe schedule is 40 stainless steel. Use maximum allowable gas velocity = 15,000 ft/min. Solution 1. Determine probable types of flow:

(

  WL   ρL ρG  B x = 531  WG   ρL2/3

)

  1/3  µ  L    σ L   1000  [(63)(0.077 )]0.5   1  B x = 531    3000   (63)2/3  15 



0.5

= 1.64

W  1 B y = 2.16  G   A  (ρL ρG )0.5



Try 3-in. Sch. 40 pipe, (I.D. =3.068-in.) Pipe cross sectional area, A = π D2/4 = π(0.2556)2/4 = 0.0513 ft2.

(WL/A) = 1000/0.0513 = 19,493 lbs/ft2h (WG/A) = 3000/0.0513 = 58,480 lbs/ft2h W  1 B y = 2.16  G   A  (ρL ρG )0.5 B y = 2.16(58, 480)

1 (63)(0.077 )

= 57 , 352





Reading Figure 15.31a, the flow pattern type is probably annular, but could be wave or dispersed, depending on many undefined and unknown conditions. 2. Liquid pressure drop

ΔPL = 3.36 fD L W2(10−6)/d5ρ

(15.319)

Fluid Flow  255 Determine Re for 3-in. pipe: From Figure 15.8; /d = 0.00058 for steel pipe The liquid velocity, vL is:

W  1000 vL =  L  = = 0.086 ft /ss  ρL A  (63)(3600)(0.0513)



e



= 1 cp/1488 = 0.000672 lbs/ft s

D = 3.068/12 = 0.2557 ft L

= 63.0 lb/ft3



Re = DvL L/



Re = 2061 (this is borderline, and in critical region)

e

= 0.2557 (0.086) (63.0)/0.000672

Relative pipe roughness is:

ε 0.00015 = = 0.000587 D 0.25567

Friction factor

 ε  5.02 log A  = −4 log  −  3.7D Re  fC

1



(15.35)

where

ε/D  6.7  A= +  3.7  Re 

0.9

0.000587  6.7  A= +  2060  3.7



0.9

= 5.926 × 10−3



 0.000587 5.02  = −4 log  − log(5.926 × 10−3 ) 2060  3.7  fC

1

= 9.01154 fC = 0.01231



The Darcy friction factor fD = 4 fC

fD = 4 (0.01231)

= 0.0492 The liquid pressure drop ΔPL is

ΔPL = 3.36(10−6)(0.0492)(1000)2(1 ft)/(3.068)5(63)

= 0.96 (10 5) psi/ft

256  Petroleum Refining Design and Applications Handbook Volume 2 3. Gas pressure drop The gas velocity vG is:





 W  vG =  G   ρG A 



vG = e



3000 = 211 ft/s 0.077(3600)(0.0513)

= 0.00127/1488 = 0.000000854 lbs/ft s

Re = D vG ρG/μe





= (0.2557)(211)(0.077)/(0.000000854)



= 4,900,000



Friction factor, f:

 ε  5.02 log A  s = −4 log  −  3.7D Re  fC

1

where

ε/D  6.7  A= +  3.7  Re 

and





0.9



ε  = pipe roughness, ft. D = pipe internal diameter, ft.

ε 0.00015 = = 0.000587 D 0.25567  ε  5.02 log A  = −4 log  −  3.7D Re  fC

1

0.000587  6.7  A= +  4900000  3.7

0.9

= 1.6392 × 10−4



 0.000587  5.02 = −4 log  − log(1.6392 × 10−4 ) 4900000  3.7  fC

1

= 15.1563 fC = 0.004353



The Darcy friction factor fD = 4 fC

fD = 4(0.004353)

= 0.0174

Fluid Flow  257 The gas pressure drop ΔPG is:

ΔPG = 3.36(10−6)(0.0174)(3000)2(1 ft)/(3.068)5(0.077)

= 0.0251psi/ft 4. Lockhart–Martinelli two-phase flow modulus X:



X = (ΔPL/ΔPG)1/2 = (0.96 × 10−5/2.51 × 10−2)1/2



= 1.95 × 10−2 5. For annular flow:

ΦGTT = (4.8 – 0.3125d)X0.343−0.021d

= [4.8 – (0.3125)(3.068)](1.95 × 10−2)0.343−0.021(3.068)



= 1.28 6. Two-phase flow for horizontal flows:



2 ∆Ρ TP = ∆Ρ G ΦGTT = (0.0251)(1.28)2 = 0.0411 psi/ft

7.

Fe = 0.00967 (WL /A ) /vG0.7 0.5

= 0.00967(19, 494 )0.5 /(211)0.7 = 0.032





Vertical elevation pressure drop component:



= nh Fe ρL/144 = [(3)(10) + (1)(50)](0.032)(63)/144



= 1.12 psi total Total:

ΔPTPh = (0.0411)(358) + 1.12

= 15.8 psi, total for pipe line

Because these calculations are somewhat uncertain due to lack of exact correlations, it is best to calculate pressure drop for other flow patterns, and apply a generous safety factor to the results. Table 15.30 gives calculated results for other flow patterns in several different sizes of lines.

15.33.6 Pipe Sizing Rules All two-phase flow correlations shown have been developed for long, horizontal pipes where uniform flow types are more likely to develop. In general, the application of all two-phase flow correlations to process piping design is arbitrary. These correlations do not take into account the three dimensional reality of process piping. Process piping has varying alternating flow regions because of pipe configurations, elevation changes, offsets, branch connections,

258  Petroleum Refining Design and Applications Handbook Volume 2 manifolds, pipe components, reducers, and other restrictions. Large deviations can occur from friction loss predictions, compared to actual friction losses [56]. In using the correlations and graphs presented for two-phase flow, the following general pipe sizing rules are suggested: Dispersed Flow: Apply ΔPTP (two-phase) throughout three dimensional pipe (horizontal, up and downflow sections). Use dispersed flow correlation for pipe smaller than 2½ in. for all flow regions. Annular and Bubble Flow: Apply ΔPTP (two-phase) for 3 in. and larger pipe throughout the process line. Check the vertical upflow correlations and unit flow loss for long, vertical upflow runs. Use the upflow losses if they are greater than the annular or bubble flow unit losses. Stratified and Wave Flow: Use stratified and wave flow correlations only for long, horizontal runs. Use annular flow correlations for three dimensional, process pipe sizing where stratified and wave flow regions are determined. For stratified flow, use the Eq. 15.296 to determine the two-phase modulus and apply the Huntington correlation to determine the wave flow unit loss calculations. Plug Flow: The process piping designer rarely meets with plug flow conditions. (But slug flow is not uncommon.) Example 15.24 Figure 15.35 shows the piping configuration with a 4 in. control valve and a vessel. The available pressure difference ΔP is 10 psi, including that of the control valve. The two-phase flow data in the line after the control valve are given below [56]. Determine a reasonable pipe size downstream of the control valve. Liquid

Gas

Flow, W, lb/h

59,033

9336

Molecular weight, Mw

79.47

77.2

Density, lb/ft3

31.2

1.85

Viscosity, μ, cP

0.11

0.0105

Surface tension, σ, dyn/cm

5.07

(Source: R. Kern, Piping Design For Two-Phase Flow, Chem. Eng. June 23, 1975).

Table 15.30  Two-phase flow example. Horizontal flow pattern Pipe ID (in.)

Annular (psi/ft)

Stratified (psi/ft)

Wave (psi/ft)

Elevation factor, Fe

Gas velocity (ft/s)

3.068

0.0438

0.000367

0.131

0.032

210.9

4.026

0.0110

0.000243

0.0336

0.0465

122.5

6.065

0.00128

0.000131

0.00434

0.0826

53.9

7.981

0.00027

0.000087

0.00110

0.121

31.1

10.02

0.000062

0.000062

0.00035

0.166

19.7

Fluid Flow  259 Solution Table 15.31 shows a typical computer results of Example 15.24 using a pipe size of 3” and Table 15.32 shows the results of 3, 4, 6, and 8 in. Sch 40, respectively. The results of ΔPTotal exclude the vertical sections of the piping configuration. These results show that the overall pressure drop of the two-phase (ΔPTP) for both the 3 and 4 in. pipe sizes is greater than the available pressure drop of 10 psi (including that for the control valve: see Figure 15.35). The 6 and 8 in. pipe sizes show an overall pressure drop of the two-phase less than 10 psi, however the 8 in. pipe size indicates an undesirable slug flow pattern on the Baker map. The 6 in. pipe size gives a bubble flow on the Baker’s map, and thus this pipeline is the optimum size. Figure 15.35A and B provide alternate locations for the control valve for alternative A. Here, slug flow cannot develop. However, for alternate B, a shortened and self-draining pipe line improves the pipe configuration but at

C El . 14 8 ft

325 °F

165 psig

V-5603

C El . 14 8 ft 4-i n

175 psig

C

2 10 El . t f

de Gra

on ati

t

0f

10

10

ft

4-in Control valve

v

ele

C El . 14 8 ft

C El . ft

14

8

C El. 11 0 ft

C E l. 1 10 ft

Alternative A

Figure 15.35  Configurations of piping for sample problem of Example 15.24 [56].

Alternative B

260  Petroleum Refining Design and Applications Handbook Volume 2 Table 15.31  Computer results of two-phase flow pressure drop calculations of Example 15.24. Two-phase pressure loss calculation in a pipe line Pipe internal diameter, in.:

3.068

Equivalent length of pipe, ft:

152.307

Actual length of pipe, ft:

56.000

Total length of pipe, ft:

208.307

Liquid density, lb/ft^3:

31.200

Liquid viscosity, cP:

0.1100

Liquid surface tension, dyne/cm:

5.0700

Liquid flow rate, lb/h:

59033.000

Liquid Reynolds number:

1103764.

Liquid friction factor:

0.0177

Pressure drop of liquid, psi/100 ft:

2.6660

Gas density, lb/ft^3:

1.850

Gas viscosity, cP:

0.0100

Gas flow rate, lb/h:

9336.000

Gas Reynolds number:

1920149.

Gas friction factor:

0.0176

Pressure drop of gas, psi/100 ft.:

1.1137

Flow regime is:

Bubble

Lockhart–Martinelli two phase flow modulus:

1.5472

Velocity of fluid in pipe, ft./s:

37.521

Baker parameter in the liquid phase:

243.246

Baker parameter in the gas phase:

51702.714

Two-phase flow modulus:

23.8109

Pressure drop of two-phase mixture, psi/100 ft:

26.5171

Overall pressure drop of the two-phase mixture, psi:

55.2369

Index 13,888. is greater than 10,000 pipe erosion is possible

the expense of convenient access to the control valve. In both alternatives, there is considerable turbulence after the control valve, which helps to provide slug free liquid-phase carry over. The following are ways to adjust the pressure loss distribution in a pipe system [56]: 1. 2. 3. 4.

 hange the pipe size. C Design a section of the pipe line with either an increase or a decrease in pipe diameter. Adjust the static head of elevated vessels. Change valve or orifice restrictions to consume more or less pressure drop (differentials).

Fluid Flow  261 Table 15.32  Computer results of two-phase pressure drop calculation of Example 15.24. Pipe internal diameter, in (Sch. 40).

3.068

4.026

6.065

7.981

Equivalent length of pipe, ft

76.445

98.822

145.729

188.042

Actual length of pipe, ft.

56.0

56.0

56.0

56.0

Total length of pipe, ft.

132.445

154.822

201.729

244.042

Liquid density, lb/ft3

31.2

31.2

31.2

31.2

Liquid viscosity, cP.

0.11

0.11

0.11

0.11

Surface tension, dyne/cm.

5.07

5.07

5.07

5.07

Liquid flow rate, lb/hr.

59033.

59033

59033

59033

Liquid Reynolds number

1103764

841120

58343

424301

Liquid friction factor.

0.0177

0.170

0.0162

0.0159

Pressure drop of liquid, psi/100 ft.

2.6685

0.6555

0.0805

0.0201

Gas flow rate, lb/hr.

9336

9336

9336

9336

Gas density, lb/ft3

1.85

1.85

1.85

1.85

Gas viscosity, cP.

0.01

0.01

0.01

0.01

Gas Reynolds number

1828713

1393565

925060

702981

Gas friction factor.

0.0176

0.0167

0.0157

0.0153

Pressure drop of liquid, psi/100 ft.

1.115

0.2723

0.033

0.0082

Flow regime:

Bubble

Bubble

Bubble

Slug

Lockhart-Martinelli two-phase modulus

1.547

1.5514

1.5617

1.5709

Velocity of fluid in pipe, ft/sec.

37.5212

21.7891

9.6012

5.5446

Baker parameter in the liquid phase.

243.246

243.246

243.246

243.246

Baker parameter in the gas phase.

51702.71

30024.55

13230.08

7640.28

Two-phase flow modulus.

23.806

26.652

31.711

17.400

Pressure drop of two-phase mixture, psi/100ft.

26.544

7.258

1.047

0.1418

Overall pressure drop of the two-phase, psi.

35.156

11.238

2.113

0.3461

Index for Pipe erosion.

13888

4684

909

303

15.33.7 A Solution for All Two-Phase Problems Dukler et al. [58] have pointed out that only three flow regimes are apparent in any piping configuration: segregated, intermittent, and distributed. Segregated flow occurs when the gas and liquid are continuous in the axial direction. Stratified flow is easily recognized as belonging to this category, as do the wavy and annular regimes (see Figure 15.32). Intermittent flow results when the phases form alternating pockets. Plug and slug flows therefore fall in this grouping. Flow is considered distributive when one fluid phase is continuous and flows to some degree in the directions which are both perpendicular and parallel to the pipe axis. The other phase may not necessarily be distributed uniformly over the same section of the pipe, but should be locally continuous. Mist flow and bubble flow are included in this type of regime.

262  Petroleum Refining Design and Applications Handbook Volume 2 These regimes, which completely characterize any flow type, simplify the analysis of a physical situation by resolving into three the numerous regimes described earlier. Erwin [59] expressed that in considering Baker’s froth zone flow regime, to have a froth or homogeneous flowing gas–liquid mixture, a high Reynolds number is required (Re ≥ 200,000). Every case of refinery, oil and gas, and chemical plant piping involves higher Reynolds number for economic pipe sizing; even pipelines are sized for higher Reynolds numbers. A pipe flowing at 3 ft/s would qualify for the minimum Reynolds number of 200,000. Dukler’s [60, 61] work resolved two-phase flow pipe sizing and configuration problems. The key to the success is maintaining Re ≥ 200,000, which is accomplished by making the pipe size small enough. Dukler’s work is summarized as follows: 1. F  or pressure loss due to friction, first determine the homogeneous flow liquid ratio λ, volume of liquid per volume of mixed fluid flow.



λ=

where QLPL QGPL WL WG ρL ρG

Q LPL Q GPL + Q LPL

(15.331)

= volume of liquid flow WL/ρL, ft3/h = volume of gas flow, WG/ρG, ft3/h = liquid flow, lb/h = gas flow, lb/h = liquid density at flow pressure and temperature, lb/ft3 = gas density at flow pressure and temperature, lb/ft3

The calculated λ value is valid only over a range in which the pressure loss in the pipe does not exceed 15% of inlet value. For a large pressure loss, the pipe run is divided into several segments with each segment having different pressure inlet and different temperature due to the gas flashing cooling effect. 2. The ratio of two-phase friction factor to gas-phase friction factor in the pipeline is determined as:



S = 1.281 + 0.478(ln λ) + 0.444(ln λ)2 + 0.09399999(ln λ)3 + 0.008430001(ln λ)4



f TP lnλ = 1− fo S



(15.332) (15.333)

where fTP = two-phase flow friction factor in the pipe run fo = gas-phase friction factor in the pipe run ln = natural logarithm of base e, 2.7183 3. Th  e Reynolds number is calculated. Dukler developed experimental data in calculating liquid holdup in two-phase flow systems. Re > 200,000 are free of liquid slugs and holdup. If Re is greater than 200,000 then the flow is in the froth regime, or it is homogeneous flow as a mixture. For homogeneous flow, the average density of the two-phase fluid mixture is:

ρm = ρLλ + ρG(1 − λ)

(15.334)

The average viscosity μm, lb/ft.s:



µm =

µL µ λ + G (1 − λ ) 1488 1488

(15.335)

Fluid Flow  263 where μL = liquid viscosity, cP μG = gas viscosity, cP Calculate the mixture flowing velocity vm, ft/s



vm =

Q GPL + Q LPL

(

3600 πD2 /4

)



(15.336)

where D = pipe internal diameter, ft. The two-phase Reynolds number is:

Re =



Dv m ρm µm

(15.337)

4. C  alculate the two-phase flow friction factor fTP as follows. First define fTP from fo. In charting fTP/fo against λ, Dukler expressed

fo = 0.0014 +



f TP =



0.125 Re0.32

f TP fo fo

(15.338)

(15.339)

Re must be 200,000 or greater before these equations can be applied. Knowing Re and the ratio of fTP/fo, fTP is calculated from Eqs. 15.338 and 15.339. 5. The pipe friction pressure loss of straight pipe, ΔPf is:



∆Pf =

4 f TP  L  ρm v 2m , psi   144 g c  D  2

(15.340)

where D = pipe diameter, ft. L = straight pipe length, ft. lb ft gc = conversion factor, = 32.174 m • 2 lbf s 6. C  alculate the pressure drop due to elevation changes ΔPE, psi. First determine the superficial gas velocity vsg as:



v sg =

Q GPL

(

3600 πD2 /4

)

, ft /s.

(15.341)

vsg is the velocity of the gas alone in the full cross section area of the pipe, ft/s. A factor ϕ is related to the two-phase gas velocity vsg, and its value increases as the gas velocity decreases. A curve fit equation of ϕ vs. vsg is:

264  Petroleum Refining Design and Applications Handbook Volume 2

φ = 0.76844 − 0.085389 v sg + 0.0041264 v sg2



− 0.000087165 v 3sg + 0.00000066422 v 4sg



(15.342)

Eq. 15.342 determines the ϕ value, which is the correction to the static leg rise or fall of the gas phase. As the gas velocity approaches 0, ϕ approaches unity. Eq. 15.342 has a range limit that is: If vsg > 50, then ϕ = 0.04 If vsg < 0.5, then ϕ = 0.85



∆PE =

φρLH T 144

(15.343)

where HT = height of static leg, - for rise and + for fall, ft. Here the liquid density, ρL is used in Eq. 15.343, since ϕ corrects for the gas-phase static leg ΔP. 7. Calculate the pressure drop due to acceleration or pipe fittings and valves ΔPA, psi. The 90° standard elbow ΔPcell is calculated as follows:



∆PA =



∆Pcell =

2 ρGQ GPL ρ Q2 + L LPL 1− λ λ

PA

3.707 × 1010 + ( d/12 )4   

(15.344)



(15.345)

where d = internal pipe diameter, in. If a 15% pressure loss in a pipe segment results, then a new pipe segment is required.

Tee angle

ΔPA = 3.0 ΔPcell

Tee straight ΔPA = 1.0 ΔPcell Check valve ΔPA = 2.5 ΔPcell For two-phase flow pipe entrance and exit,



∆PA = 4 f TP[6.469(ln d ) + 24]

ρm  v 2m    144 g c  2 

(15.346)

ρm  v 2m    144 g c  2 

(15.347)

Pipe sharp-edge exit:



∆PA = 4 f TP[14.403(ln d ) + 42]

Fluid Flow  265 8. The total two-phase pressure loss ΔPT is:

ΔPT = ΔPf + ΔPE + ΔPA

(15.348)

Note: All preceding seven steps are made on the assumption that Re is 200,000 or greater. Table 15.33 shows a glossary of two-phase flow. Example 15.25 Using the data in Example 15.24, determine the total two-phase pressure drop downstream of the control valve. Liquid

Gas

Flow, W, lb/h

59,033

9336

Molecular weight, Mw

79.47

77.2

Density, lb/ft3

31.2

1.85

Viscosity, μ, cP

0.11

0.0105

Surface tension, σ, dyn/cm

5.07

(Source: R. Kern, Piping Design For Two-Phase Flow, Chem. Eng. June 23, 1975).

Table 15.33  A glossary of two-phase flow. Critical Flow: When a point is reached in the system where the increase in specific volume for a small decrease in pressure is so great that the pressure and the enthalpy can no longer be simultaneously lowered across a cross section of pipe, it is called critical flow. It is analogous to sonic flow in a single phase flow. This does not imply, however, that the sonic velocity of a superficially flowing gas phase in a two-phase system is equal to the sonic or critical velocity of the two-phase system. Critical flow occurs in the so-called mist flow regime.

Plug Flow: This is a flow regime where most, but not all aggregates of the liquid phase occupy most of the cross section of the pipe for a given length of conduit. A similar length is occupied by all gas. The regimes alternate down the conduit.

Flow Regimes: A flowing two-phase fluid can exhibit several “patterns” of flow, such as the liquid occupying the bottom of the conduit with the gas phase flowing above, or a liquid phase with bubbles of gas distributed throughout. In essence, flow regimes are the physical geometry exhibited by the two-phase mixture in the conduit. They are influenced by pipe geometry as well as the physical properties of the fluid mixture and flow rate.

Slip: For the majority of the fluid’s history, one of the phases is flowing faster than the other. Thus, one phase seems to slip by the slower phase. Slip velocity is the difference in the phase velocities.

Flowing Volume Holdup: This term is given as the ratio of the superficial liquid velocity to the sum of the superficial gas and liquid velocities. The term arises in computing properties of homogeneous system and results naturally from the assumption of no slip flow.

Slug Flow: A flow regime characterized by each phase alternately occupying the entire cross section for a large length of the conduit: a “slug” of liquid or gas.

Homogeneous Flow: A mathematical model that considers a two-phase system as a single homogeneous fluid with properties representing the volumetric flow averages of the liquid and gas phases. Homogeneous flow does not exist in real physical situations.

Superficial Liquid Velocity: The velocity that the liquid phase would have in the pipe if there were no gas-phase flowing. Thus, it is the volumetric liquid flow rate divided by the cross sectional area of the pipe.

Mist Flow: At high gas flow velocities, the majority of the liquid becomes distributed as droplets in the gas phase. The liquid is said to be entrained and flow is described as mist flow.

Superficial Gas Velocity: Defined in a manner similar to superficial liquid velocity.

Source: (A. E. DeGance and R. W. Atherton, Chem. Eng. Mar. 23, pp. 135, 1970).

266  Petroleum Refining Design and Applications Handbook Volume 2 Data: Assume a 6 in. pipe size, ID = 6.065” Straight pipe length = 56 ft. Elevation (Static leg rise), HT = 0 ft. Fittings: 4 × 90° ells 1 pipe exit to vessel V-5603. Solution Two-phase flow after the control valve pressure drop. Step 1. Calculate the homogeneous flow liquid ratio λ

λ=

where QLPL QGPL WL WG ρL ρG

Q LPL Q GPL + Q LPL

(15.331)

= volume of liquid flow WL/ρL, ft3/h = volume of gas flow, WG/ρG, ft3/h = liquid flow, lb/h = gas flow, lb/h = liquid density at flow pressure and temperature, lb/ft3 = gas density at flow pressure and temperature, lb/ft3

59033 = 1892.1ft 3/h 31.2



Q LPL =



Q GPL =



λ=

9336 = 5046.5ft 3/h 1.85 1892.1 = 0.2727 (5046.5 + 1892.1)

2. Calculate fTP/fo The ratio of two-phase friction factor to gas-phase friction factor in the pipeline is determined as:



S = 1.281 + 0.478(ln 0.2727) + 0.444(ln 0.2727)2 + 0.09399999(ln 0.2727)3 + 0.008430001(ln 0.2727)4



S = 1.2274



f TP lnλ = 1− fo S

(15.332)

(15.333)

Fluid Flow  267 where fTP = two-phase flow friction factor in the pipe run fo = gas-phase friction factor in the pipe run ln = natural logarithm of base e, 2.7183

f TP ln(0.2727 ) = 1− = 2.0587 fo 1.2274

3. Calculate the Reynolds number Re of the mixture density ρm, lb/ft3:

ρm = ρLλ + ρG (1 − λ)

(15.334)

ρm = (31.2)(0.2727) + (1.85)(1 – 0.2727)

= 9.854 lb/ft3 The average viscosity μm, lb/ft.s:

µm =



µL µ λ + G (1 − λ ) 1488 1488

(15.335)

where μL = liquid viscosity, cP μG = gas viscosity, cP

0.11 0.0105 (0.2727 ) + (1 − 0.2727 ) 1488 1488 = 2.529 × 10−5 lb/ft•s

µm =



Calculate the mixture flowing velocity vm, ft/s



vm =

Q GPL + Q LPL

(

3600 πD2 /4

)



(15.336)

where D = pipe internal diameter, ft.

vm =

(5046.5 + 1892.1)

(

3600 π [ 0.5054 2 ] 4

)

= 9.607 ft /s

The two-phase Reynolds number Re is:



Re =

Dv m ρm µm

Re =

(0.5054 )(9.607)(9.854) (2.529 × 10−5 )

= 1.89 × 106 (Re > 200, 000)



(15.337)

268  Petroleum Refining Design and Applications Handbook Volume 2 4. Calculate the two-phase flow friction factor fTP as follows. First define fTP from fo. In charting fTP/fo against λ, Dukler expressed

0.125 Re0.32 0.125 fo = 0.0014 + = 0 . 00263 (1.89 × 106 )0.32 fo = 0.0014 +



f TP =



f TP fo fo

(15.338)



(15.339)

4 f TP  L  ρm v 2m ∆Pf = , psi   144 g c  D  2

(15.340)

f TP = (2.0587 )(0.00263) = 0.0054 5. Calculate the friction pressure loss ΔPf of straight pipe:

where L = straight pipe length, ft. lb ft gc = 32.174 m • 2 lbf s

4(0.0054 )  56  (9.854 )((9.607 2 )   2 (144 )(32.174 )  0.5054  = 0.235 psi

∆Pf =



6. Calculate the pressure drop due to elevation changes ΔPE, psi. First determine the superficial gas velocity vsg as:

v sg =

v sg =

Q GPL

(

3600 πD2 /4

(

)

5046.5 2

3600 π[0.5054] /4

)



(15.341)

= 6.99 ft /s φ = 0.76844 − 0.085389 v sg + 0.0041264 v sg2 − 0.000087165 v 3sg + 0.00000066422 v 4sg

φ = 0.76844 − 0.085389(6.99) + 0.0041264(6.99)2 − 0.000087165(6.99)3 + 0.00000066422(6.99)4 φ = 0.345



(15.342)

Fluid Flow  269



∆PE =

φρLH T 144

(15.343)

where HT = height of static leg, − for rise and + for fall, ft.

(0.345)(31.2)(0) psi 144 = 0 psi

∆PE =



7. Calculate the pressure drop due to acceleration or pipe fittings and valves ΔPA, psi. The 90o standard elbow ΔPell is calculated as follows: 2 ρGQ GPL ρ Q2 + L LPL 1− λ λ (1.85)(5046.5)2 (31.2)(1892.1)2 + ∆PA = (1 − 0.22727 ) 0.2727 = 474377476.2 psi

∆PA =

∆Pell =



∆PA

3.707 × 1010 + ( d/12 )4   



(15.344)



(15.345)

where d = internal pipe diameter, in.

∆Pell =

(474377476.2)

3.707 × 1010 + ( 6.065/12 )4    = 0.0128 psi







4 × 90° standard elbow

ΔPA = 4 × 0.0128

= 0.051 psi. Pipe sharp – edge exit:

∆PA = 4 f TP[14.403(ln d ) + 42]

2  ρm  v m   144 g c 2 

∆PA = 4(0.0054 )[14.403(ln 6.065) + 42] = 0.144 psi

(9.854 )  9.607 2    (144 )(32.174 )  2 



(15.347)

270  Petroleum Refining Design and Applications Handbook Volume 2 8. The total two-phase pressure loss ΔPT is:

ΔPT = ΔPf + ΔPE + ΔPA

(15.348)

ΔPT = 0.235 + 0 + (0.051 + 0.144) ΔPT = 0.43 psi The Excel spreadsheet Example 15.25.xlsx has been developed to determine the two-phase pressure drop of Example 15.25. Figure 15.36 shows snapshots of the calculations.

15.33.8 Gas–Liquid Two-Phase Vertical Down Flow Two-phase vertical downflow presents its own problems as often occurs in horizontal pipe line. In a vertical flow, large gas bubbles are formed in the liquid stream resulting in a flow regime known as slug flow. This flow regime (is associated with) can result in pipe vibration and pressure pulsation. With bubbles greater than 1 in. in diameter and the liquid viscosity less than 100cP, slug flow region can be represented by dimensionless numbers for liquid and gas phases respectively (Froude numbers, (NFr)L and (NFr)G). These are related by the ratio of inertial to gravitational force and are expressed as: 0.5



v L  ρL  (NFr )L = (gD)0.5  ρL − ρG 



v G  ρG  (NFr )G = (gD)0.5  ρL − ρG 

(15.349)

0.5



(15.350)

The velocities vG and vL are superficial velocities based on the total pipe cross-section. These Froude numbers exhibit several features in the range 0 < (NFr)L and (NFr)G < 2. Simpson [65] illustrates the values of (NFr)L and (NFr)G with water flowing at an increased rate from the top of an em pty vertical pipe. As the flow rate further increases to the value (NFr)L = 2, the pipe floods and the total cross-section is filled with water. If the pipe outlet is further submerged in water and the procedure is repeated, long bubbles will be trapped in the pipe below (NFr)L = 0.31. However, above (NFr)L = 0.31, the bubbles will be swept downward and out of the pipe. If large long bubbles are trapped in a pipe (d ≥ 1 inch) in vertically down flowing liquid having a viscosity less than 100cP and the Froude number for liquid phase, (NFr)L ≤ 0.3, the bubbles will rise. At higher Froude numbers, the bubbles will be swept downward and out of the pipe. A continuous supply of gas causes the Froude number in the range 0.31 ≤ (NFr)L < 1 to produce pressure pulsations and vibration. These anomalies are detrimental to the pipe and must be avoided. If the Froude number is greater than 1.0, the frictional force offsets the effect of gravity, and thus requires no pressure gradient in the vertical downflow liquid. This latter condition depends on the Reynolds number and pipe roughness. Figure 15.37 shows the flow patterns in a vertical liquid.gas flow and Figure 15.38 shows a correlation in a cocurrent vertical upflow of air-water mixture in terms of Froude numbers.

Fluid Flow  271

Figure 15.36  Excel spreadsheet calculation of Example 15.25.

(Continued)

272  Petroleum Refining Design and Applications Handbook Volume 2

Figure 15.36 (Continued)  Excel spreadsheet calculation of Example 15.25.

(Continued)

Fluid Flow  273

Figure 15.36 (Continued)  Excel spreadsheet calculation of Example 15.25.

Bubbly

Plug

Churn

Annular

Dispersed

Figure 15.37  Flow patterns in vertical liquid–gas flow (source: S. M. Walas, Chemical Process Equipment—Selection and Design, Butterworth Publishers, 1988).

The Equations The following equations will calculate Froude numbers for both the liquid and gas phases. A developed spreadsheet program will print out a message indicating if the vertical pipe is self-venting, if pulsating flow occurs, or if no pressure gradient is required.

d , ft 12 πD2 2 Area = , ft 4 D=





(15.351)

274  Petroleum Refining Design and Applications Handbook Volume 2 0.5

PG PL– PG

Slug flow eliminated with 24 in line 0.4

(NFr ) G =

VG gD

0.3 FROTH FLOW 0.2

0.1

Slug flow observed in 30 in line SLUG FLOW

0

0

0.1

0.2

0.3 (NFr ) L =

0.4 VL gD

0.5

0.6

0.7

PL PL– PG

Figure 15.38  Slug/forth transition in concurrent vertical upflow of air–water mixtures in terms of Froude numbers (source: L. L. Simpson, Chem. Eng., June 17, pp 192–214, 1968).



vL =

WL , ft /s (3600)(ρL )(Area )

(15.352)



vG =

WG , ft /s (3600)(ρG )(Area )

(15.353)

0.5



v L  ρL  FRNL = (gD)0.5  ρL − ρG 



v G  ρG  FRNG = (gD)0.5  ρL − ρG 

(15.354)

0.5

where Area d D FRNL, (NFr)L FRNG, (NFr)G g vL vG W L WG ρL ρG

= inside cross-sectional area of pipe, ft2. = inside diameter of pipe, in. = inside diameter of pipe, ft = Froude number of liquid phase, dimensionless = Froude number of gas phase, dimensionless = gravitational constant, 32.2ft/2 = liquid velocity, ft/s = gas velocity, ft/s = liquid flow rate, lb/h = gas flow rate, lb/h = liquid density, lb/ft3 = gas density, lb/ft3

(15.355)

Fluid Flow  275 The Algorithms If FRNL < 0.31, Vertical pipe is SELF VENTING ELSE 0.3 ≤ FRNL < 1.0, PULSE FLOW, and may result in pipe vibration. FRNL > 1.0, NO PRESSURE GRADIENT. Example 15.26 Calculate the Froude numbers and flow conditions for the 2, 4, and 6 in. (Schedule 40) vertical pipes having the following liquid and vapor flow rates and densities Liquid

Vapor

Mass flow rate, lb/h

6930

1444

Density, lb/ft3

61.8

0.135

Solution 2 in. pipe diameter (Schedule 40) I.D. = 2.067 in.



D = 2.067/12 = 0.17225 ft. π D2 π(0.17225)2 Area = = 4 4 2 = 0.0233 ft





(15.351)

Liquid velocity, vL is:

vL =

WL (ρL A)

6930 (61.8)(0.0233)(3600) = 1.34 ft /s =





(15.352)

Vapor velocity, vG is:

vG =

WG (ρG A)

1444 (0.135)(0.0233)(3600) = 127.52 ft /s =



(15.353)

276  Petroleum Refining Design and Applications Handbook Volume 2 Froude number for liquid phase is:

v L  ρL  FRNL = (gD)0.5  ρL − ρG 

0.5

  61.8 =   (32.2)(0.17225) 61.8 − 0.135  (1.34)



0.5



(15.354)



(15.355)

= 0.57 The Froude number for vapor phase is:

v G  ρG  FRNG = (gD)0.5  ρL − ρG 

0.5

 0.135  =   (32.2)(0.17225)  61.8 − 0.135  127.5



0.5

= 2.53 Since the Froude number for liquid phase is greater than 0.31 and less than 1.0, the 2 in. pipe can produce a pulse flow, which may result in pipe vibration. The Excel spreadsheet Example 15.26.xlsx calculates the Froude numbers for 4 and 6 in. pipe sizes. Table 15.34 shows typical computed results for 2, 4, and 6 in. pipe sizes.

Table 15.34  Gas–liquid two-phase downflow. Pipe internal diameter, in.

2.067

4.026

6.065

Liquid flow rate, lb/h

6930

6930

6930

Liquid density, lb/ft3

61.80

61.80

61.80

Gas flow rate, lb/h

1444

1444

1444

Gas density, lb/ft3

0.135

0.135

0.135

Pipe area, ft2

0.023

0.088

0.201

Liquid velocity, ft/s

1.337

0.352

0.155

Gas velocity, ft/s

127.504

33.609

14.810

Froude number for liquid phase

0.5682

0.1073

0.0385

Froude number for gas phase

2.5332

0.4784

0.1718

Flow is pulse and this may result in pipe vibration.

Line is self-venting. Therefore, no vibration problems would be expected.

Line is self-venting. Therefore no vibration problems would be expected.

Fluid Flow  277

15.33.9 Pressure Drop in Vacuum Systems Vacuum in process systems refers to an absolute pressure that is less than or below the local barometric pressure at the location. It is a measure of the degree of removal of atmospheric pressure to some level between atmospheric barometer and absolute vacuum (which cannot be attained in an absolute value in the real world), but is used for a reference of measurement. In most situations, a vacuum is created by pumping air out of the container (pipe, vessels) and thereby lowering the pressure. See Figure 15.3 to distinguish between vacuum gauge and vacuum absolute. This method [62] is for applications involving air or steam in cylindrical piping under conditions of (a) turbulent flow, (b) sub-atmosphere pressure, (c) pressure drop is limited to 10% of the final pressure (see comment to follow), and (d) the lower limit for application of the method is



W/d = 20

(15.356)

where W is the flow rate in lbs/h and d is the inside pipe diameter in inches. If the above ratio is less than 20, the flow is “streamlined” and the data do not apply. If the pressure drop is greater than 10% of the final pressure, the pipe length can be divided into sections and the calculations made for each section, maintaining the same criteria of (c) and (d) above. Method [62] The method solves the equation (see Figure 15.39)

∆Pvac =



(F1C D1C T1 ) + (F2C D 2C T 2 ) P1

(15.357)

where

Pvac = pressure drop, in. water/l00 ft of pipe P1 = initial pressure, inches mercury absolute F1 = base friction factor, Figure 15.39 F2 = base friction factor, Figure 15.39 CT1 = temperature correction factor, Figure 15.39 CT2 = temperature correction factor, Figure 15.39 CD1 = diameter correction factor, Figure 15.39 CD2 = diameter correction factor, Figure 15.39

Example 15.27: Line Sizing for Vacuum Conditions Determine the proper line size for a 350 equivalent feet vacuum jet suction line drawing air at 350°F, at a rate of 255 lbs/h with an initial pressure at the source of 0.6 in. Hg. Abs. Assume 10-in. pipe reading Figure 15.39. Note: watch scales carefully. Fl F2 CD1 CD2 CT1 CT2

= 0.0155 = 0.071 = 0.96 = 0.96 = 1.5 = 1.67

Pvac = [(0.0155) (0.96) (1.5) + (0.071) (0.96) (1.67)]/0.6

= (0.02232 + 0.1138)/0.6



= 0.2269 in. water/l00 ft.

(15.357)

278  Petroleum Refining Design and Applications Handbook Volume 2 Total line pressure drop:

 0.2269  ∆Pvac =  (350) = 0.794 in. water (for 350′ ):  100 



= (0.794 /13.6) = 0.0584 in. Hg



Final calculated pressure = 0.6 + 0.0584 = 0.6584: in. Hg



10% of 0.658 = 0.0658 in. Hg STANDARDS OF THE HEAT EXCHANGE INSTITUTE, INC 1000 800 600

C r2

TEAM

FOR S

400 C r1

60

AIR

100 80

FOR

TEMPERATURE, °F

200

C r2 C r1

40

1.0

1.4

1.8

2.2 2.6 3.0 3.4 3.8 CrC1τ TEMPERATURE CORRECTION FACTORS

60

CD1

ACTUAL PIPE DIAMETER INCHES

40

4.2

4.6

5.0

CD2

20

10 8 6 4 F2

F1

2

10–5

10–4

10–3

10–2

10–1

Note: Friction Factors F1 and F2 are on rate flow, while Factors CD1 and CD2 are based on actual diameter.

Figure 15.39  Evaluation curves for friction losses of air steam flowing turbulently in commercial pipe at low pressure (source: Standards for Steam Jet Ejectors, 4th. Ed., Heat Exchange Institute, 1988).  (Continued)

Fluid Flow  279 STEAM JET VACUUM SYSTEMS 105

RATE OF FLOW, POUNDS PER HOUR

104

w must be greater than 20 For turbulent flow — d F=

103

(F1 × CD1 × CT1) + (F2 × CD2 × CT2) P1

F = Pressure Drop, inches of water in 100 feet of pipe P = Initial Pressure, inches of mercury absolute

102

CD2

1

102

10

CD1

103

10 104

Figure 15.39 (Continued)  Evaluation curves for friction losses of air steam flowing turbulently in commercial pipe at low pressure (source: Standards for Steam Jet Ejectors, 4th. Ed., Heat Exchange Institute, 1988).

Therefore the system is applicable to the basis of the method, since the calculated pressure drop is less than 10% of the final pressure, and w/d = 25.5, which >20.

15.33.10 Low Absolute Pressure Systems for Air For piping with air in streamline flow at absolute pressures in the range between 50 microns and one millimeter of mercury, the following is a recommended method. Calculation procedures in pressure regions below atmospheric are very limited and often not generally applicable to broad interpretations. For this method to be applicable, the pressure drop is limited to 10% of the final pressure. Method [62, 63] Refer to Figure 15.40 for low pressure friction factor and air viscosity of Figure 15.41 to correspond to Figure 15.40.



P1′− P2′ =

4 fLρv 2 , psi 2g c D(144 )

(15.127)

280  Petroleum Refining Design and Applications Handbook Volume 2

5.00 4.00 3.00 2.00 12 AND 18 INCH PIPE

FRICTION FACTORS f

1.00 0.80 0.70 0.60 0.50 0.40 0.30 0.20

6 AND 8 INCH PIPE

0.10 0.08 0.07 0.06 0.05 0.04 0.03 0.02

0.01 40 50 60

80

200

300

500

REYNOLDS NUMBER RD =

1000

2000

DvP µ

Figure 15.40  Friction factor for streamlined flow of air at absolute pressures from 50 µHg to 1 mm Hg (source: Standard for Steam Jet Ejectors, 3rd ed., Heat Exchange Institute, 1956 [62] and Standards for Steam Jet Vacuum Systems, 4th ed., 1988).

where P1′ = upstream static pressure, psia. P2′ = downstream static pressure, psia. f = friction factor, from Figure 15.5. L = length of pipe (total equivalent), ft, incl. valves and fittings ρ = average density, lbs/ft3 v = average velocity, ft/s lb ft gc = conversion factor = 32.174 m • 2 lb D = inside diameter of pipe, ft f s = abs. viscosity of air, lbs/ft-s.

Fluid Flow  281 24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

24

23

22

21

20

19

18 17

16

15

14

13

12

11

10

0

100

200

300

400 500 600 TEMPERATURE, °F

700

800

900

1000

25 25

ABSOLUTE VISCOSITY × 106 POUNDS PER FOOT·SECOND

ABSOLUTE VISCOSITY OF AIR

Figure 15.41  Absolute viscosity of air (source: Standard for Steam Jet Ejectors, 3rd ed., Heat Exchange Institute, 1956 [62] also, Standards for Steam Jet Vacuum Systems, 4th ed., 1988 [38]).

15.33.11 Vacuum for Other Gases and Vapors Ryans and Roper categorize [64] vacuum in process systems as: Category

Absolute vacuum (absolute pressure)

Rough vacuum

760 torr to 1 torr

Medium vacuum

1 to 10−3 torr

High vacuum

10−3 to 10−7 torr

Ultra high vacuum

10−7 torr and below

The majority of industrial chemical and petrochemical plants’ vacuum operations are in the range of 100 microns to 760 torr. This is practically speaking the rough vacuum range noted above. For reference: 1 torr = 1 mm mercury (mmHg) 1 in. mercury (in. Hg) = 25.4 torr 1 micron (µm Hg) = 0.0010 torr

282  Petroleum Refining Design and Applications Handbook Volume 2 In general, partially due to the size and cost of maintaining vacuum in a piping system, the lines are not long (certainly not transmissions lines), and there is a minimum of valves, fittings, and bends to keep the resistance to flow low. The procedure recommended by [64] is based on the conventional gas flow equations, with some slight modifications. The importance in final line size determination is to determine what is a reasonable pressure loss at the absolute pressure required and the corresponding pipe size to balance these. In some cases a trial/error approach is necessary. Method [64], by permission: 1. Convert mass flow rate to volumetric flow rate, qm.

qm = W (359/M) (760/Pt) (T/(32 + 460)) (1/60), ft3/min

(15.359)

where Pt = pressure, torr T = temperature, °R W = mass flow, lbs/h M = molecular weight 2. C  alculate section by section from the process vessel to the vacuum pump (point of lowest absolute pressure). 3. Assume a velocity, v, ft/s consistent with Figure 15.42. Use Table 15.35 for short, direct connected connections to the vacuum pump. Base the final specifications for the line on pump specifications. Also the diameter of the line should match the inlet connection for the pump. General good practice indicates that velocities of 100 to 200 ft/s are used, with 300 to 400 ft/s being the upper limit for the rough vacuum classification.



Sonic velocity, vs = (kg [1544/M] T)1/2, ft/s. Use v from Figure 15.42, and qm from Eq. 15.359.

1000 8 6 4 3 Maximum

Velocity, ft/s

2

Design basis

100 8

Minimum

6 4 3 2 10

1

2

3

4 5 6 7 89

2 3 Pressure, torr

4 5 6 7 8 9 100

2

3 4 5 6 7 89 1000

Figure 15.42  Typical flow velocities for vacuum lines. Note: 1 torr = 1.33 mb = 133.3. Pa, 1 ft/s = 0.3048 m/s (source: Ryans, J. L., and D. L. Roper, Process Vacuum System Design and Operation, McGraw-Hill Book Co., Inc. 1986 [64]).

Fluid Flow  283 Table 15.35  Criteria for sizing connecting lines in vacuum service. Vacuum pump

Assumed flow velocity, ft/s

Steam jet: System pressure, torr 0.5 5

300

5 25

250

25 150

200

150 760

150

Liquid ring pump: Single-stage*

100

Two-stage

150

Rotary piston: Single-stage

50

Two-stage

25

Rotary vane:† Single-stage

200

Two-stage

400

Rotary blowers: Atmospheric discharge

50

Discharging to backing pump

100

*Assumes the pump features dual inlet connections and that an inlet manifold will be used. † Based on rough vacuum process pumps. Use 25 ft/s for high vacuum pumps. By permission, Ryans, J.L. and Roper, D.L., Process Vacuum Systems Design and Operation, McGraw-Hill Book Co. Inc., 1986 [18].

4. Determine pipe diameter, D, ft,

D = 0.146 q m /v



(15.360)

Round this to the nearest standard pipe size. Recalculate v based on actual internal diameter of the line. 5. Determine Reynolds Number, Re,



Re = ρDv/μe = density, lb/ft3 at flowing conditions D = pipe inside diameter, ft v = vapor velocity (actual),ft/s = viscosity of vapor, lb/ft-s e

(15.26)

284  Petroleum Refining Design and Applications Handbook Volume 2 6. Determine friction factor, f, from Moody Friction Factor Charts (Figure 15.5) or Chen’s explicit equation. or, calculate for turbulent flow using Blausius’ equation [64]:



f = 0.316/(Re)1/4, for Re < 2.0 × 105

(smooth pipe only)

7. T  abulate the summation of equivalent lengths of straight pipe, valves, fittings, entrance/exit losses as presented in earlier sections of this chapter. 8. Calculate the pressure drop for the specific line section (or total line) from: 2 ∆Ρ T = 0.625 ρi f D Lq m /d 5 , torr

(15.361)

ΔPT = 4.31 ρi fD L v2/2gcd, torr

(15.362)



or

where

= density, lb/ft3 d = pipe inside diameter, in. qm = volumetric flow rate, cu ft/min fD = friction factor, (Moody Darcy) Figure 15.5 PT = pressure drop, torr

Calculate:

i

= PiM/555Ti, lb/ft3

(15.363)

Pi = pressure, torr M = average molecular weight of mixture flowing Ti = temperature, °R 9. I f the calculated pressure drop does not exceed the maximum given in Figure 15.43, use this calculated value to specify the line. If the P exceeds the limit of Figure 15.43, increase the pipe size and repeat the calculations until an acceptable balance is obtained. For initial estimates, the authors [64] recommend using 0.6 times the value obtained from Figure 15.43 for an acceptable pressure loss between vessel and the pump. The suction pressure required at the vacuum pump (in absolute pressure) is the actual process equipment operating pressure minus the pressure loss between the process equipment and the source of the vacuum. Note that absolute pressures must be used for these determinations and not gauge pressures. Also keep in mind that the absolute pressure at the vacuum pump must always be a lower absolute pressure than the absolute pressure at the process.

15.33.12 Pressure Drop for Flashing Liquids When a liquid is flowing near its saturation point (i.e., the equilibrium or boiling point) in a pipe line, decreased pressure will cause vaporization. The higher the pressure difference, the greater the vaporization resulting in flashing of the liquid. Steam condensate lines cause a two-phase flow condition, with hot condensate flowing to a lower pressure through short

Maximum acceptable pressure loss across component ΔP/P0

Fluid Flow  285 1.0 8 6 5 4

Primary condenser

3

Vent condenser Section 1 Section 2

0.1 8

Sections 3 and 4

6 5 4 3 2

0.01

1

2

3

4 5

7 8 10

2

3

4 5 6 7 8 100

2

3

4

6 7 8 1000

Pressure in vacuum vessel P0

Figure 15.43  Acceptable pressure losses between the vacuum vessel and the vacuum pump. Note: Reference sections on figure to system diagram to illustrate the sectional type hook-ups for connecting lines. Use 60% of the pressure loss read as acceptable loss for the system from process to vacuum pump, for initial estimate; P, pressure drop (torr) of line in question; Po, operating pressure of vacuum pressure equipment, absolute torr (source: Ryans, J. L., and D. L. Roper, Process Vacuum System Design and Operation, McGraw-Hill Book Co., Inc. 1986 [64]).

and long lines. For small lengths with low pressure drops, and the outlet end being a few pounds per square inch of the inlet, the flash will be assumed as a small percentage. Consequently, the line can be sized as an all liquid line. However, caution must be exercised as 5% flashing can develop an important impact on the pressure drop of the system [5]. Sizing of flashing steam condensate return lines requires techniques that calculate pressure drop of two-phase flow correlations. Many correlations have been presented in the literature [49, 50, 53, 66]. Most flow patterns for steam condensate headers fall within the annular or dispersed region on the Baker map. Sometimes, they can fall within the slug flow region, however the flashed steam in steam condensate lines is less than 30% by weight. Steam is the most common liquid that is flashed in process plants, but of course, it is not the only one as many processes utilize flash operations of pure compounds as well as mixtures. Although this presentation is limited to steam, the principles apply to other materials. Steam condensate systems often are used to generate lower pressure steam by flashing to a lower pressure. When this occurs, some steam is formed and some condensate remains, with the relative quantities depending upon the pressure conditions. Figure 15.44 is a typical situation. Percent incoming condensate flashed to steam:



% flash =

(h1 − h 2 )100 Lv

(15.364)

where h1 = enthalpy of liquid at higher pressure, Btu/lb h2 = enthalpy of liquid at lower or flash pressure, Btu/lb Lv = latent heat of evaporation of steam at flash pressure, Btu/lb Example 15.28: Calculation of Steam Condensate Flashing There are 79,500 lbs/h of 450 psig condensate flowing into a flash tank. The tank is to be held at 250 psig, generating steam at this pressure. Determine the quantity of steam produced.

286  Petroleum Refining Design and Applications Handbook Volume 2

Flash Pressure, Z psig (Lower than either X or Y)

Pressure: X, psig

Vapor

Pressure: Y, psig Condensate From Various Collection Headers

Flashing

Liquid

Liquid Level

Condensate Return to Collection Tank

Figure 15.44  Typical steam condensate flashing operation.

Enthalpy of liquid at 450 psig  = 441.1 Btu/lb Enthalpy of liquid at 250 psig  = 381.6 Btu/lb Latent heat of vaporization at 250 psig = 820.1 Btu/lb From Eq. 15.364



% flash into steam =

441.1 − 381.6 (100) = 7.25% 820.1

Steam formed = (0.0725) (79,500) = 5,764 lbs/h Condensate formed = 79,500 5,764 = 73,736 lbs/h

15.33.13 Sizing Condensate Return Lines Steam condensate lines usually present a two-phase flow condition, with hot condensate flowing to a lower pressure through short and long lines. As the flow progresses down the pipe, the pressure falls and flashing of condensate into steam takes place continuously. For small lengths with low pressure drops, and the outlet end being within a

Fluid Flow  287 few pounds per square inch of the inlet, the flash will be such a small percent that the line can often be sized as an all liquid line. However, caution must be exercised as even 5% flashing can develop an important impact on the pressure drop of the system. Calculation of condensate piping by two-phase flow techniques is recommended; however, the tedious work per line can often be reduced by using empirical methods and charts. Some of the best methods are proprietary and not available for publication; however, the Sarco method [67, 68 ] has been used and found to be acceptable, provided no line less than 1½ in. is used regardless of the chart reading. Under some circumstances, which are too random to properly describe, the Sarco method may give results too small by possibly a half pipe size. Therefore, latitude is recommended in selecting either the flow rates or the pipe size. Design Procedure Using Sarco Chart [67, 68] 1. E  stablish upstream or steam pressure from which condensate is being produced and discharged into a return line through steam traps, or equivalent, psig. 2. Establish the steam condensate load or rate in lbs/h flow. 3. Establish the pressure of the condensate return line, psig. 4. The method is based on an allowable 5000 ft/min velocity in the return line (mixture). 5. Calculate load factor:



=

5, 000(100) 500, 000 = Condensate Rate, lbs / h C

(15.365)

6. E  stablish condensate receiver (or flash tank) pressure, psig. 7. Referring to Figure 15.45, enter at steam pressure of (1) above, move horizontally to condensate receiver pressure of (6) above, and then up vertically to the “factor scale.” 8. Divide the load factor (step 1) by the value from the “factor scale” of (7) above, obtain ft/min/(100 lb/h load). 9. Enter chart on horizontal velocity line, go vertically up to the steam pressure of (1) above, and read pipe size to the next largest size if the value falls between two pipe sizes. 10. For pipe sizes larger than 3-in., follow the steps (1) thru (8) above. Then enter the vertical scale at the steam pressure of (1) above, and more to the 3-in. pipe size and down to the horizontal velocity scale. 11. Divide the result of step 8 above by the result of step (10). 12. Refer to the large pipe multipliers shown in the table on the chart, and select the pipe size whose factor is equal to or smaller than the result of step (11) above. This is the pipe size to use, provided a sufficient factor of safety has been incorporated in the data used for the selection of pipe size. 13. Calculation of “factor scale” for receiver pressures different than those shown on chart:



factor =

36.2(V )(h p − h r ) L v (h p − 180)

where 3 V = specific volume of steam at return line pressure, ft /lb hp = enthalpy of liquid at supply steam pressure, Btu/lb hr = enthalpy of liquid at return line pressure, Btu/lb Lv = latent heat of evaporation at return line pressure, Btu/lb Use the factor so calculated just as if read from the chart, i.e., in step (8) above.

(15.366)

288  Petroleum Refining Design and Applications Handbook Volume 2 VELOCITY AT PIPE EXIT WHEN DISCHANGING CONDENSATE AT SATURATION TEMPERATURES FROM VARIOUS PRESSURES TO ATMOSPHERE AT A RATE OF 100 POUND/HR. FOR LARGER PIPES MULTIPLY 3" PIPE VELOCITY BY FOLLOWING FACTORS: PIPE FACTOR 4" 0.58 5" 0.37 6" 0.25 8" 0.15 10" 0.095 12" 0.066 14" 0.054

WHEN DISCHARGING TO PRESSURE HIGHER THAN ATMOSPHERIC, MULTIPLY VELOCITY TO ATMOSPHERE BY FACTOR CORRESPONDING TO SUPPLY PRESSURE AND RECEIVER PRESSURE.

600

.1

FACTOR SCALE .3 .4 .5

.2

.6

.8

1.0

500

60 P SIG

400

SSU

RE

SIG

CIT

Y

. PRE 40

60

" 1/2

" 3/4

1·1

1"

/4"

/2" 1·1

2"

/2"

3"

5 PSIG

SIG 10 P

15 P

60

SIG

20 P

80

PIP

SIG

EV

ELO

REC

100

2·1

40 P

30 P

SUPPLY PRESSURE

200

SIG

50 P

SIG

300

40 30

20

10 10

20

30

80 100

200

400

600

1000

2000

4000

VELOCITY FT/MIN PER 100 POUNDS/H CONDENSATE

Figure 15.45  Sarco flashing steam condensate line sizing flow chart (source: Spirax Sarco. Inc., Allentown, PA [75]).

Example 15.29: Sizing Steam Condensate Return Line A 450 psig steam system discharges 9425 lb/h of condensate through traps into a return condensate line. The return header is to discharge into a flash tank held at 90 psig. The calculated total equivalent length of pipe, valves, and fittings is 600 ft. Using the Sarco chart, Figure 15.45, determine the recommended line size for the return line. 1. 2. 3. 4. 5.



 pstream steam pressure = 450 psig U Condensate load = 9425 lbs/h Return line pressure = 90 psig Use the Sarco recommendation of 5000 ft/min Load factor

=

(5, 000)(100) = 53.05 9, 425

Fluid Flow  289 6. R  eceiver pressure = 90 psig 7. Refer to Figure 15.45 and note that required receiver pressure is not shown, so calculate “factor scale” by previous formula:



Data: hp = 441 Btu/lb at 450 psig

hr = 302 Btu/lb at 90 psig Lr = 886 Btu/lb at 90 psig V = 4.232 ft3/lb at 90 psig



“factor scale” value =

36.2(4.232)(441 − 302) = 0.092 886(441 − 180)

(15.366)

53.05 = 576.1 0.092 9. R  ead Chart: At 450 psig and 576.1, the line size shows just under 2-in. Recommend use 2-in. 8. Ft/min/l00#/h =

The procedure for using the convenient chart Figure 15.46 [76] is, for example: Step 1: Enter the figure at 600 psig below the insert near the right-hand side, and read down to the 200psig end pressure.

0

50 1.0 60 75 0.8 Step 7 100 0.6 150 200 0.4 End pressure 0.3 Step 6 psig

H4 0 H4

H4 10"

SC

ec

ft/s

ec

3.0

0

3"

SC H4 0 SC H4 0

0 ft/s

SC

20

ec

400 250 ft/se c ft 300 /sec ft/s ec

ec

0 2.0

SC

ec

Step 5

ec

ec

ec

ft/s

140 ft/sec f 120 t/sec ft/s ec

ft/s

ft/s

ft/s

160

ft/s

Step4

0 12 14" " SCH SC 10 H1 16" 0 18" SCH 1 20" SCH 0 SC 10 H1 0 24" SC H1 0

0.1 0.08 0.06 0.05

ft/s

ec

8"

0.2 1 0

30 15

200

6"

0.4

40

2"

1.0 0.3 0.6

60

f t/s

ec

4"

Pressure drop, psi/100 ft

1½

" SC

2.0

SC H4

1"

H8 0

SC

H8

0

H8

80

250

ft/s

0.2

100 200 400 600 Saturation pressure, psig 50 100 200 400 600 Step 1

Step 2

200 150 100 75 60 30 10 0 End pressure psig

ep St 3 1 1.5 2 100

3 4

Velocity-correction factor

100

0 H8

SC

SC

¼"

½"

10.0 8.0 6.0 4.0

6 8 1 1000

1.5 2.

3 4 6 8 1 1.5 2. Flowrate, lb/h 10,000

3 4

6 8 1

1.5 2

3 4

6 8 1

100,000

Figure 15.46  Flashing steam condensate line sizing chart (source: Ruskin, R. P., “Calculating Line Sizes For Flashing Steam Condensate”, Chem. Eng., Aug 18, p. 101, 1985).

290  Petroleum Refining Design and Applications Handbook Volume 2 Step 2: Proceed left horizontally across the chart to the intersection, with: Step 3: the 1000 lb/h flow rate projected diagonally up from the bottom scale. Step 4: Reading vertically up from this intersection, it can be seen that a 1-in. line will produce more than the allowed pressure drop, so a 1½-in. size is chosen. Step 5: Read left horizontally to a pressure drop of 0.28 psi/100 ft on the left-hand scale. Step 6: Note the velocity given by this line as 16.5 ft/s, then proceed to the insert on the right, and read upward from 600 psig to 200 psig to find the velocity correction factor as 0.41. Step 7: Multiply 0.41 by 16.5 to get a corrected velocity of 6.8 ft/s. The comparison between this method and that of Dukler [66] and others gives good agreement for reasonably good cross section of flow regimes. Because flashing steam-condensate lines represent two-phase flow, with the quantity of liquid phase depending on the system conditions, these can be designed following the previously described two-phase flow methods. Ruskin [69] assumes that a single homogeneous phase of fine liquid droplets is dispersed in the flashed vapor and the pressure drop is calculated using the Darcy equation:

0.00000336 f W 2 ∆P = , psi ρd5



(15.122)

Ruskin [69] developed a method for calculating pressure drop of flashing condensate. His method gave pressure drops comparable to those computed by the two-phase flow with good agreement with experimental data. The method employed here is based on a similar technique given by Ruskin. The pressure drop for flashing steam uses the average density of the resulting liquid-vapor mixture after flashing. In addition, the friction factor used is valid for complete turbulent flows in both commercial steel and wrought iron pipe. The pressure drop assumes that the vapor-liquid mixture throughout the condensate line is represented by mixture conditions near the end of the line. This assumption is valid since most condensate lines are sized for low pressure drop, with flashing occurring at the steam trap or valve close to the pipe entrance. If the condensate line is sized for a higher pressure drop, an iterative method must be used. For this case, the computations start at the end of the pipeline and proceed to the steam trap. The method employed determines the following: 1. Th  e amount of condensate flashed for any given condensate header from 15 to 140 psia. Initial steam pressure may vary from 40 to 165 psia. 2. the return condensate header temperature. 3. the pressure drop (psi/100ft) of the steam condensate mixture in the return header. 4. the velocity of the steam condensate mixture and gives a warning message if the velocity is greater than 5000 ft/min, as this may present problems to the piping system. The Equations The following equations are used to determine the pressure drop for flashed condensate mixture [70].



WFRFL = B(ln Pc)2 − A

(15.367)



A = 0.00671(ln Ph)2.27

(15.368)



B = ex 10−4 + 0.0088

(15.369)

 16.919  X = 6.122 −   ln Ph 

(15.370)

where

and



Fluid Flow  291

            WG = (WFRFL) (W)

(15.371)

WL = W − WG

(15.372)



TFL = 115.68(Ph)0.226

(15.373)



ρG = 0.0029Ph0.938

(15.374)



ρL = 60.827 − 0.078Ph + 0.00048Ph2 − 0.0000013Ph3

(15.375)



ρM =

WG + WL  WG WL   ρ + ρ  G L

(15-376)

For fully turbulent flow



f=

0.25   0.000486      − log  d  

2



(15.377)

where d = pipe diameter, in. Pressure drop



∆Ρ T =



v=

0.000336 f W 2 d 5 ρM

(15.378)

3.054  WG WL  + d 2  ρG ρL 

(15.379)

If v ≥ 5000 ft/min, print a warning message as condensate may cause deterioration of the process pipeline. where D = internal pipe diameter, in. F = friction factor, dimensionless = steam condensate pressure before flashing, psia Pc = flashed condensate header pressure, psia Ph V = velocity of flashed condensate mixture, ft/min W = total flow of mixture in condensate header, lb/h = flashed steam flow rate, lb/h WG = flashed condensate liquid flow rate, lb/h WL WFRFL = weight fraction of condensate flashed to vapor TFL = temperature of flashed condensate, °F = pressure drop of flashed condensate mixture, psi/100 ft ΔPT = flashed condensate liquid density, lb/ft3 ρL ρG = flashed steam density, lb/ft3 ρM = density of mixture (flashed condensate/steam), lb/ft3.

292  Petroleum Refining Design and Applications Handbook Volume 2 Example 15.30 Determine the pressure drop for the 4, 6, and 8 in. (Schedule 40) condensate headers under the following conditions Flow rate, lb/h

10,000

Steam condensate pressure, psia

114.7

Header pressure, psia

14.7

Solution For the 4 in. (Schedule 40) pipe size, I.D. = 4.026 in. The weight fraction of the condensate is:

 16.919  X = 6.122 −   ln Ph   16.919  = 6.122 −   ln14.7 





(15.370)

= −0.1726

A = 0.00671(ln Ph)2.27



(15.368)

= 0.0632



B = e(−0.1726)(10−4) + 0.0088



(15.369)

= 0.008884 The weight fraction of the condensate is:



WFRFL = B(ln Pc)2 − A



= 0.008884(ln 114.7)2.27 – 0.0632



= 0.1365

WG = (WFRFL) (W)

= 0.1365 × 10,000



= 1365 lb/h

WL = W − WG

= 10,000 – 1365



= 8635 lb/h.

(15.367)

(15.371)

(15.372)

Fluid Flow  293 The temperature of the flashed condensate is:



TFL = 115.68(Ph)0.226



(15.373)

= 212.4°F The flashed steam density, condensate and density of the mixture are:

ρG = 0.0029Ph0.938 = 0.0029(14.7 )0.938



= 0.0361 lb/ft



(15.374)

3

ρL = 60.827 − 0.078Ph + 0.00048Ph2 − 0.0000013Ph3

ρL = 60.8827 − 0.078(14.7 ) + 0.00048(14.7 )2 − 0.00000013(14.7)3 = 59.78 lb/ft

ρM =



ρM =



(15.375)

3

WG + WL  WG WL   ρ + ρ  G L (1365 + 8635)  1365 8635  +   0.0361 59.78 



(15.376)

= 0.2634 lb/ft 3 Assuming that the flow through the line is turbulent: For fully turbulent flow



f=

0.25   0.000486      − log  d  

2



(15.377)

where d = pipe diameter, in.

f=



0.25

  0.000486     − log  4.026    = 0.01628

2



294  Petroleum Refining Design and Applications Handbook Volume 2 Pressure drop of the steam condensate mixture in the return header:

∆Ρ T =



0.000336 f W 2 0.000336(0.01628)(10, 000)2 = d 5 ρM (4.026)5 (0.2634 )

= 1.964 psi /100 ft.



Velocity of the flashed condensate mixture is:

v=

3.054  WG WL  + d 2  ρG ρL 

3.054  1365 8635  + (4.026)2  0.0361 59.78  = 7154 ft/ min. =



(15.379)

Since the velocity v ≥ 5000 ft/min, the condensate may cause deterioration of the 4 in. line. The Excel spreadsheet (Example15.30.xlsx) calculates the parameters for 6 and 8 in. Schedule 40 pipe sizes. Table 15.36 compares the results of 4, 6, and 8 in. pipe sizes. Table 15.37 shows the friction factor for pipes carrying water and constant accounting for surface roughness. Table 15.36  Computer results of line sizes for flashing steam condensate of Example 15.30. Pipe internal diameter, in.

4.026

6.065

7.981

Total flow of mixture in condensate header, lb/h

10000

10000

10000

Steam condensate pressure before flashing, psia

114.7

114.7

114.7

Flashed condensate header pressure, psia.

14.7

14.7

14.7

Weight fraction of condensate flashed to vapor

0.135

0.135

0.135

Flashed steam flow rate, lb/h

1346

1346

1346

Flashed condensate liquid flow rate, lb/h

8654

8654

8654

Temperature of flashed condensate, °F

212.36

212.36

212.36

Flashed steam density, lb/ft

0.036

0.036

0.036

Flashed condensate liquid density, lb/ft3

59.780

59.780

59.780

Density of mixture, lb/ft

0.267

0.267

0.267

Friction factor:

0.0163

0.0149

0.0141

Pressure drop of flashed condensate mixture, psi/100 ft

1.937

0.228

0.055

Velocity of flashed condensate mixture, ft/min.

7,055

3,109

1,795

Velocity is greater than 5000 ft/min. Deterioration of the pipe line is possible.

Velocity is less than 5000 ft/min. The Condensate header line will not deteriorate.

Velocity is less than 5000 ft/min. The Condensate header line will not deteriorate.

3

3

Fluid Flow  295 Table 15.37  Cameron hydraulic data.* Friction losses in pipes carrying water Among the many empirical formula e for friction losses that have been proposed that of Williams and Hazen has been most widely used. In a convenient form it reads: in which 100 1.85 q1.85 f = friction head in ft of liquid per f = .2083 C d4.8655 100 ft of pipe (if desired in lb per sq in. multiply f × .433 × sp gr) d = inside dia of pipe in inches q = flow in gal per min C = constant accounting for surface roughness This formula gives accurate values only when the kinematic viscosity of the liquid is about 1.1 centistokes or 31.5 SSU, which is the case with water at about 60F. But the viscosity of water varies with the temperature from 1.8 at 32F to .29 centistokes at 212F. The tables are therefore subject to this error which may increase the friction loss as much as 20% at 32F and decrease it as much as 20% at 212F. Note that the tables may be used for any liquid having a viscosity of the same order as indicated above. Values of C for various types of pipe are given below together with the corresponding multiplier which should apply to the tabulated values of the head loss, f, as given on pages 29 to 48.

Friction losses in pipe; C = 100 1/8 in Standard wt steel Flow US gal per min 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Extra strong steel

0.269” inside dia Velocity ft per s 0.565 1.13 1.69 2.26 2.83 3.39 3.95 4.52 5.08 5.65

Velocity head ft 0.00 0.02 0.04 0.08 0.12 0.18 0.24 0.32 0.40 0.50

0.215” inside dia Head loss ft per 100 ft 1.75 6.31 13.4 22.8 34.4 48.2 64.1 82.0 102 124

Commonly used value for design purposes 140 140 140 140 130 110 100 100 100 100 100 100 100 100 100 100 90 60 70 1.93

Velocity head ft 0.01 0.05 0.11 0.19 0.30 0.44 0.61 0.78 0.98 1.21

Head loss ft per 100 ft 5.21 18.8 39.8 67.7 102 147 191 244 303 369

1/4 Inch Standard wt steel

Values of C Range — high = best, Average smooth, value well laid for — good, low = clean, poor or new Type of Pipe corroded pipe Cement—Asbestos . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160–140 150 Fibre. . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . − 150 Bitumasc-enamel-lined iron or steel centrifugally applied. . 160–130 148 Cement-lined iron or steel centrifugally applied. . . . . . . . . . . − 150 Copper, brass, lead, n or glass pipe and tubing . . . . . . . .. . . 150–120 140 Wood-stave. . . . . . . . . . . . . . . . . . . . . .. . . . .. . . . . . .. . . . . . . . 145–110 120 Welded and seamless steel. . . . . . . . . . . . . . . . . . . . . . . . . . . . 150–80 140 Connuous-interior riveted steel (no projecng rivets or joints. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . − 139 Wrought-iron. . . . . . . . . . . . . . . . .. . . . . . . .. . . . . . . . . . . . . . . 150–80 130 Cast-iron. . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . 150–80 130 Tar-coated cast-iron. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145–80 130 Girth-riveted steel (projecng rivets in girth seams only). . . − 130 Concrete. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152–85 120 Full-riveted steel (projecng rivets in girth and horizontal seams). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. − 115 Vitrified. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . − 110 Spiral-riveted steel (flow with lap). . . . . . . . . . . . . . . . . . . . . . − 110 Spiral-riveted steel (flow against lap). . . . . . . . . . . . . . . . . . . . − 100 Corrugated steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . − 60 Value of C . . . . . . . . . . . . . . . . . . . . . 150 140 130 120 110 100 90 80 Mulplier to correct tables . . . . . . 0.47 0.54 0.62 0.71 0.84 1.0 1.22 1.50

Velocity ft per sec 0.884 1.77 2.65 3.54 4.42 5.32 6.29 7.08 7.96 8.84

60 2.57

Flow US gal per min 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.5

Extra strong steel

0.364” inside dia Velocity ft per s 1.23 1.85 2.47 3.08 3.71 4.33 4.94 5.55 6.17 7.71

Velocity head ft 0.02 0.05 0.09 0.15 0.21 0.29 0.38 0.48 0.59 0.92

0.302” inside dia Head loss ft per 100 ft 5.22 11.1 18.8 28.5 39.9 53.0 67.9 84.4 103 155

Velocity ft per sec 1.79 2.69 3.59 4.48 5.38 6.27 7.17 8.07 8.96 11.2

Velocity head ft 0.05 0.11 0.20 0.31 0.45 0.61 0.80 1.01 1.25 1.95

Head loss ft per 100 ft 13.0 27.4 46.7 70.6 98.9 132 168 209 254 385

3/8 Inch Standard wt steel

Extra strong steel

0.493” inside dia

0.423” inside dia

Flow US gal per min

Velocity Velocity ft per sec head ft

Head loss Velocity Velocity ft per 100 ft ft per sec head ft

Head loss ft per 100 ft

0.8 1.0 1.5 2.0 2.5 3.0 3.5 4.0 5.0 6.0

1.35 1.68 2.52 3.36 4.21 5.05 5.89 6.73 8.41 10.1

4.30 6.50 13.8 23.4 35.4 49.6 66.0 84.5 134 179

9.07 13.7 29.0 49.4 74.6 105 139 178 269 377

0.03 0.04 0.10 0.18 0.28 .40 .54 .70 1.10 1.58

1.83 2.28 3.43 4.57 5.71 6.85 8.00 9.14 11.4 13.7

0.05 0.08 0.18 0.32 0.51 0.73 0.99 1.30 2.0 2.9

*By permission G. V. Shaw and A. W. Loomis Cameron Hydraulic Data, 11th Edition, Ingresoll-Rand Co., 1942 [53].

Example 15.31 Pressure drop for Vapor System The calculations are presented in Figure 15.47. Line Size Specification Sheet. Figure 15.48 is convenient when using Dowtherm vapor.

15.34 UniSim Design PIPESYS Generally, pipelines transport fluids over a wide range of topography and diverse conditions. Normally, this is computed with a correctly sized pipeline that sufficiently accounts for pressure drop, heat losses and includes the properly specified and sized line facilities, such as compressor, pumps, heaters, or fittings. However, the complexity of pipeline

296  Petroleum Refining Design and Applications Handbook Volume 2 SHEET NO. __________

By

AKC

LINE SIZE SHEET

Job No.

Date

Charge No.

Line No.

Flow Sheet Drawing

LP – 61

No.

Line Description

Vent through Exchanger for Tower T – 3

Fluid in line

N2+ Hydrocarbon

Temperature

GPM (Calc.)

GPM (des.)

Pressure

CFM (Calc.)

2060

CFM (des.)

2270

lb/h.(Calc.)

10,841

lb/h. (des)

12,000

Recommended Velocity

ft/s

Straight pipe, fittings, valves No.

Unit Eq. Ft.

Total Eq. Ft.

St. Line

Tee –S0

5.3

psig

Sp. Gr.

0.975

Sp. Vol.

11.3

Viscosity

0.019

1

11

11

1

6

6

1

50

50

cP

in psi 0.0617

Orifice Motor Valve Miscellaneous Exchanger drop

1.50 Total

Total

cu.ft./lb

Pressure Drop

Pipe & Equivalent

5

Gate Valve.

°F

Item

expansions, contraction, etc Item

140

1.56

72 Estimated line size

10“ (existing)

Actual Velocity

4150 fps

Unit Loss per 100 ft.

0.0857 psi

Total head loss in feet of liquid

37

Cross-sect. area, 10” pipe = 0.547 sq. ft. Velocity = 2270 / 0.547 = 4150 ft/min.

Total pressure drop in psi

Selected pipe size

10”

Material & Weight

Calculations:

Re = 6.31 W/dµ = [ (6.31) (12,000) / (10.02) (0.019) ] = 3.98 × 105 f = 0.0158

∆P/100 feet

=

(0.000336) ( f ) (W)2 d5ρ

Schedule 40, Steel

ρ = 1/ V

=

(0.000336) (0.0158) (12,000)2 (10.02)5 (1/11.3)

= 0.0857 psi/100 equivalent feet of pipe (as pipe, fittings, valves, etc.) ∆P Total (friction) = (0.0857 / 100) (72) = 0.0617 psi

Checked by:

1.56

Date:

Figure 15.47  Line size sheet. Example of pressure drop for a vapor system, Example 15.31.

Fluid Flow  297 80 50 40 30

12"

10"

8"

6"

4"

3"

2½ "

1¼ "

1" SIZ E

5.0 4.0 3.0

PIP E

PRESSURE DROP — lb/in.2/100 ft

10 8.0

1½ "

20 15

2.0 1.5 1.0 0.6

TEMP.—°F 500 550 600 650 700 750

0.5 0.3 0.2

CORRECTION 8.95 5.77 3.72 2.40 1.55 1.00

All sizes are schedule 40 except 1" & 1¼" which are schedule 80 1

2

3

5

8 10

20

30

50 100 200 300 500 800 1000 2000 DOWNTHERM VAPOR FLOW — lb/h × 102

5000

10,000

Figure 15.48  Pressure drop, Dowtherm “A” ® vapor in steel pipe (by permission from Sruthers Wells Corp., Bull. D-45).

network calculations often proves the task to be arduous and difficulty. It is not uncommon that during the design phase, an over-sized pipe is chosen to compensate for inaccuracies in the pressure loss calculations. Additionally, with multi-phase flow, this can result to greater pressure and temperature losses, increased requirements for liquid handling and increased pipe corrosion. Accurate fluid modeling resolves these and other complications and results in a more economic pipeline system. Accomplishing this requires single and multi-phase flow technology that is capable of accurately and efficiently simulating the pipeline flow. PIPESYS is a powerful model pipeline hydraulics that uses the most reliable single and multi-phase flow technology available to simulate pipeline flow. It accesses UniSim Design features such as the component database and fluid properties; includes many inline equipment and facility options relevant to pipeline construction and testing. The extension models pipelines that stretch over varied elevations and environments. The software allows the user to [50]: • Rigorously model single phase and multi-phase flows. • Compute detailed pressure and temperature profiles for pipelines that traverse irregular terrain, both on shore and off. • Perform forward and reverse pressure calculations. • Model the effects of inline equipment such as compressors, pumps, heaters, coolers, regulators and fittings including valves and elbows. • Perform special analyses including: pigging slug prediction, erosion velocity prediction, and severe slugging checks. • Model single pipelines or networks of pipelines in isolation or as part of a UniSim Design process simulation. • Perform sensitivity calculations to determine the dependency of system behavior on any parameter. • Quickly and efficiently perform calculations with the internal calculation optimizer, which significantly increases calculation speed without loss of accuracy.

298  Petroleum Refining Design and Applications Handbook Volume 2 • Determine the possibility of increasing capacity in existing pipelines based on compositional effects, pipeline effects and environmental effects. In computing the PIPESYS extension, a wide variety of correlations and mechanistic models are employed such as horizontal, inclined and vertical flows, flow regimes, liquid holdup, and friction losses. There is also flexibility in performing calculations such as • Calculate the pressure profile using an arbitrarily defined temperature profile, or determine the pressure and temperature profiles simultaneously. • Given the conditions at one end of the pipe, perform pressure profile calculations either with or against the direction of flow to determine either upstream or downstream conditions. • Perform iterative calculations to determine the required upstream pressure and the downstream temperature for a specified downstream pressure and upstream temperature. • Calculate the flow rate corresponding to specified upstream and downstream conditions.

PIPESYS Features The PIPESYS extension is functionally equivalent to a UniSim Design Flowsheet operation and it is installed in a flowsheet and connected to material and energy streams. All PIPESYS extension properties are accessed and changed through a set of property views and amongst these and the starting point for the definition of a PIPESYS operation is the Main PIPESYS view, which is: Main PIPESYS View—Used to define the elevation profile, add pipeline units, specify material and energy streams, and choose calculation methods and check results. The PIPESYS extension includes these pipeline units, each of which is accessible through a property view: • Pipe—The basic pipeline component used to model a straight section of pipe and its physical characteristics • Compressor—Boosts the gas pressure in a pipeline • Pump—Boosts the liquid pressure in a pipeline • Heater—Adds heat to the flowing fluid(s) • Cooler—Removes heat form the flowing fluid(s) • Unit X—A “black box” component that allows you to impose arbitrary changes in pressure and temperature on the flowing fluid(s) • Regulator—Reduces the flowing pressure to an arbitrary value • Fittings—Used to account for the effect of fittings such as tees, valves, and elbows on the flowing system • Pigging Slug Size Check—An approximate procedure for estimating the size of pigging slugs • Severe Slugging Check—A tool for estimating whether or not severe slugging should be expected • Erosion Velocity Check—Checks fluid velocities to estimate whether or not erosion effects are likely to be significant. Case Study: Pressure Drop Through Pipeline Water at 25°C (density 1000 kg/m3) and 2.5 atm pressure is being transferred with a 0.45 kW pump that is 75% efficient at a rate of 8.025 m3/h. All the piping is 4 in. Sch 40 steel pipe and the last section is a 2 in. Sch. 40 steel pipe. Solution PIPESYS simulation software is used to determine the pressure drop and to calculate the pump duty at 75% adiabatic efficiency. Figure 15.49 shows a snap shot of the process flow diagram of PIPESYS (Pipeline-deltaP.usc) and Table 15.38 shows the results of the flow streams. Figures 15.50a–d show profiles of the pressure and temperature

Fluid Flow  299

Temperature Pressure Molar Flow Pipe-100

Temperature Pressure Molar Flow

S1 25.00 202.6 444.1

C kPa kgmole/h Pipe-101

Pump-100

PIPESYS-UniSim

S1

S3 25.02 356.3 443.3

PIPESYS-UniSim

S3

S2 E-100

C kPa kgmole/h

Q-100

Temperature Pressure Molar Flow

S4

Q-101 Temperature Pressure Molar Flow

Pump-100 Speed Energy Actual Vol. Flow Feed Pressure Product Pressure Product Temperature

S2 25.00 C 202.6 kPa 443.3 kgmole/h

rpm

S4 25.02 353.9 443.3

C kPa kgmole/h

1642 kJ/h 8.011 m3/h 202.6 kPa 356.3 kPa 25.02 C

Figure 15.49  Process flow diagram of the Case study using PIPESYS software (courtesy of Honeywell, UniSim ® Design Suite).

Table 15.38  Results of the simulation of the case study. Streams 1

2

3

4

Temperature, °C

25

25

25.02

25.02

Pressure, kPa

202.6

202.6

356.3

353.9

Molar flow, kg mole/h

444.1

443.3

443.3

443.3

Comp. mass frac (H2O)

1

1

1

1

Flowing Pressure : Pipe−100 202.7 202.6 202.6 Pressure (kPa)

202.6 202.6 202.6 202.6 202.6 202.6 202.6 0.000

1.000

2.000

3.000

4.000

5.000

Distance (m)

Figure 15.50a  Flowing pressure profile of Pipe-100.

6.000

7.000

8.000

9.000

10.000

300  Petroleum Refining Design and Applications Handbook Volume 2 Flowing Temperatuare: Pipe-100 25.00

Fluid Temperature Ambient Temperature

Temperature (°C)

25.00 25.00 25.00 25.00 25.00 25.00 0.000

1.000 2.000

3.000

4.000

5.000

6.000

7.000

8.000 9.000 10.000

7.000

8.000 9.000 10.000

Distance (m)

Figure 15.50b  Flowing temperature profile of Pipe-100. Flowing Pressure: Pipe-101 256.5

Pressure (kPa)

256.0 255.5 255.0 254.5 254.0 253.5 0.000

1.000 2.000

3.000

4.000

5.000

6.000

Distance (m)

Figure 15.50c  Flowing pressure profile of Pipe-101.

for Pipe-100 and Pipe-101 respectively. Appendix E shows the flow diagram and results of the Pipeline-deltaP.usc simulation program of the case study.

15.35 Pipe Line Safety Process pipe lines are employed to transfer fluid types (liquids, gases, and solids) from one location to another and are considered as the safest, most economical, and environmental friendly mode of transportation of crude oil and gas and their products. This provides important link of petroleum supply chain management and cutting edge to petroleum/petrochemical industry. However, there have been significant losses due to failure of piping and piping leaks. Major hazards associated in pipeline safety are the results of the following: • • • •

Corrosion—internal/external. Human errors during pigging hot tapping, valve operation. System procedure failure—inspection, operation, start-up/shut down, material specification, and testing. External reason—accidental excavation, earthquake, flood, fire, lightening, rail/road accident.

Fluid Flow  301 Flowing Temperature; Pipe-101

25.02

Fluid Temperature Ambiemt Temperature

25.01

Temperature (°C)

25.01 25.01 25.01 25.01 25.00 25.00 25.00 0.000

1.000 2.000

3.000

4.000

5.000

6.000

7.000

8.000 9.000 10.000

Distance (m)

Figure 15.50d  Flowing temperature profile of Pipe-101.

Major causes of pipeline external corrosion are poor/defective coatings, inadequate cathodic protection (CP), and coating defects combination with inadequate CP, interference due to external agencies, stress and bacterial corrosion. Major causes of internal corrosion is the corrosive nature of fluid being transported through pipeline, erosion–corrosion, localized chemical attack/bacterial corrosion. Nigam [71] provides the salient features in the transportation of petroleum: • No leaky tank or container that contains petroleum shall be tendered for transport. Barrels, drums, and other container filled with petroleum shall be loaded with their bung upwards. • No ship, vessel or vehicle shall carry petroleum (class A or B or C) in bulk, if it is carrying passengers or any other combustible cargo other than petroleum. • No person while engaged in loading/unloading or transporting petroleum shall smoke or carry matches, lighters, and any other appliances capable of producing ignition or explosion. • Petroleum shall not be loaded into or unloaded from any ship vessel or vehicle between the hours of sunset or sunrise unless adequate electric lighting is provided at the place of loading or unloading and adequate fire fighting facilities with trained personnel are kept in place for immediate action in the event of a fire.

15.36 Mitigating Pipeline Hazards The following are considered in mitigation hazards in pipeline: • • • • • • • •

Protection against external corrosion Protection against internal corrosion Protection against third party damages Protection of pipeline supports Leak detection system Pig based monitoring system Protection against overpressures Protection against detonation hazards.

15.37 Examples of Safety Design Concerns The following concerns are typically included in the design of piping systems and valves [75].

302  Petroleum Refining Design and Applications Handbook Volume 2

Piping Systems • Has all piping systems handling toxic or lethal materials been identified? (e.g., piping handling hydrogen cyanide, nitrogen, etc). • Does the piping need to be designed to contain a deflagration? A denotation? • Are special monitoring provisions provided for overflow lines which have a tendency to plug? (e.g., lines in caustic services) • Has the proper metallurgy been selected for the fluid transported? Has deleterious materials of construction been avoided? (e.g., has copper or brass been eliminated from ammonia service? Or has copper or iron been eliminated from benzyl chloride service? • Have high temperature shutdowns been provided for pumps which handle heat sensitive or reactive material? • Has the proper bolt design been provided for frangible flange systems to accurately control the break point? • Has a surge vessel been provided to contain thermal expansion of a hazardous liquid (like chlorine) instead of a pressure relief valve? • Has special insulation been used on Therminol or high temperature systems to prevent cracking of high molecular weight organics to a lower flash point material with subsequent auto-ignition? • If a bellows type expansion joint is used in flammable and/or pressure relief systems, has this type joint been correctly aligned during installation to maintain integrity? • If a hazardous condition exists when mechanical agitation is lost, has emergency gas agitation via a dip-pipe been provided? • Do dip pipes have weep holes to de-inventory the pipe during a plant shutdown? • Has a “deadman” start–stop station on a pump been provided to prevent overflow of flammable or very hazardous materials from the downstream vessel due to operator in attention? • Has a remote “stop” been provided on a pump which transports flammable material into an operating unit from the outside the battery limits? • Should uninsulated sections of pipe be added for planned heat loss? (e.g., the feed water regulator on a boiler). • Have the spring hanger settings for piping used in high temperature or high pressure service been documented during installation? • Has the proper gasket type and material been used in hazardous service? (e.g., lethal systems need spiral wound gaskets).

Valves • Have “air or open” control valves been selected for those remote valves which you want to activate closed during a fire event and has plastic air tubing been provided? • Are the valves which must be manually opened or closed during an emergency capable of remote operation? • Have the valves, nipples (open ended), etc., used in pressurized flammable, lethal gas or oxygen service been capped off? • Have the valves and piping, etc., in chloride or oxygen service been degreased before start up (and/or after repair)? • Have excess flow check valves been installed in pressured hazardous gas systems such as those involving ammonia, chlorine, hydrogen, etc.? • Has a hole been drilled in a butterfly valve to prevent overpressure due to thermal expansion? If this is not possible, has a pressure relief valve been provided? • Have “deadman” (spring or close) sampling valves been installed in high pressure, flammable, or lethal systems to prevent continued flow of material if the operator becomes incapacitated? • Has a manually activated water flush or quench system (if possible) been provided to stop an uncontrolled reaction or to provide internal fire fighting capability? • Have air-activated valves been locked out (defused) in the field while maintenance is in progress?

Fluid Flow  303 • Has a valve in a tank car and/or truck unloading line been provided which closes on disconnecting or which must be closed to disconnect? • Has a hazard analysis of the process been conducted to determine the fail safe position of control valves during a specific or total utility outage (electrical power, instrument air, etc.)? • Have special position indicators been provided for three way valves to clearly indicate which port is active?

Piping and Valves Used in ASME Section 1 Service • Have the piping systems been analyzed for stresses and movements due to thermal expansion? • Are the piping systems properly supported and guided? • Have the piping systems been provided with freezing protection, particularly cold water lines, instrument connections, lines in dead end service such as piping in standby pumps? • Have case iron valves and fittings been eliminated from piping which subjected to strain or shock service? • Have non rising stem valves been avoided where possible and has a visual indication of valve position been provided? • Have double block and bleed valves been provided on battery limit piping and/or emergency interconnections to ensure positive isolation and/or to prevent cross-contamination where this is undesirable? • Has a means of draining and trapping condensate from steam piping been provide?

15.38 Safety Incidents Related With Pipeworks and Materials of Construction Table illustrates various incidents involving pipeworks and materials of construction that occurred in refinery and chemical plants; investigations that determined the root causes of these incidents, findings and recommendations of mitigation/preventing similar occurrences in the future. Incidents

U.S. Chemical Safety and Hazard Investigation Board (CSB)

Tosco Refinery in Martinez, California February 23, 1999

Root Causes, Findings and Recommendations

This incident occurred on February 23, 1999 as workers attempted to remove and replace a leaky petroleum pipe, which was attached to an operating oil distillation/ fractionating tower. Over a 13 day period prior to the accident, workers had repeatedly tried to isolate and drain the pipe, but leaking and corroded shut-off valves hampered their efforts. At the same time of the incident, the pipe still contained a significant volume of pressurized naphtha, a highly flammable petroleum mixture similar to gasoline. While workers were in the process of replacing the pipe, the naphtha was released and burst into flame, and caused four fatalities. At the time of the fire, these workers were positioned on scaffolding up to an hundred feet off the ground and had limited means of escape.

Although the refinery procedures directed that the piping should be isolated and drained prior to attempting this kind of repair. This procedure was not followed, as opening a pipe containing naphtha in the presence of multiple ignition sources would result in a disaster. The entire process unit should have been shut down, which would have eliminated ignition source and allowed the naphtha to be fully and safely drained. The CSB concluded that management had a responsibility to ensure that work was halted, and should not have relied solely upon individual workers to stop an unsafe activity. Worker's error was not a root cause of this accident as a satisfactory management system is one that anticipates that humans will inevitably make mistakes, still ensures the safe conduct of work. An effective job planning, hazard review, and management oversight could have prevented the tragedy. The CSB recommended that the refinery implements a comprehensive system for safely managing hazardous maintenance work. Key provisions include a process for evaluating hazards before work is started and increased management oversight of ongoing work. The Board further recommended that the Corporation improves its safety auditing procedures and applies these to its seven refineries. (Continued)

304  Petroleum Refining Design and Applications Handbook Volume 2 Hydrogen Blast in 2009 Silver Eagle Refinery Accident in Woods Cross, Utah A massive explosion and fire at the Silver Eagle Refinery on November 4, 2009 damaged homes was caused by a rupture in a pipe that had become dangerously thin from corrosion was the finding by the CSB Board. The catastrophic rupture occurred in a 10-in. pipe at the bottom of a reactor in the distillated dewaxing unit. This led to a massive release of hydrogen, which caught fire immediately and exploded, sending a blast wave across the refinery into a subdivision. The blast wave damaged over 100 homes.

Root Causes, Findings and Recommendations Metallurgical failure and study analysis was carried out on the pipe segments recovered after the incident. The history of the pipe that ruptured was examined and the component that failed had no record of ever being inspected for corrosion as it thinned over the years. CSB inferred that metallurgical analysis details the same kind of sulfidation corrosion at the Silver Eagle Refinery as was found in the Bay Area Chevron refinery fire of 2012 and the Tesoro refinery explosion and fire that killed seven in Anacortes, Washington in 2010. The sulfur compounds in the process stream corroded a steel piping segment causing the pipe walls to become severely thin. The CSB noted that the examination of the ruptured pipe segment and adjacent piping clearly indicated wall thinning had occurred in the piping component. The elbow adjacent to the pipe segment that failed was noted to have an original thickness of 0.719 in. A 2007 thickness measurement of the elbow indicated a wall thickness of 0.483 in., indicating years of thinning had taken place. Furthermore, the adjacent straightrun segment that failed was found to have a wall thickness as low as 0.039 in. and there were no records of previous inspection.

Initial gas release on security video.

(Continued)

Fluid Flow  305 The CSB’s investigation noted records indicating other serious wide spread mechanical integrity deficiencies and gaps across the refinery at the time of the incident. The goal of mechanical integrity program is to ensure that process equipment is fabricated from the proper materials of construction and is properly installed, monitored and maintained to prevent failures and accidental releases.

Security video showing gas release rapidly expanding.

The hazardous nature of the materials in a refinery and the high temperatures and pressures that are frequently used should ensure a robust mechanical integrity program is essential to safe refinery operations. It is also a regulatory requirement for refineries and chemical plants under the OSHA Process Safety Management standard enacted in 1992.

Security video showing gas release rapidly expanding. R30101 discharge pipe bent around reactor support beam.

Ignition of released gas.

Rapture end of pipe still attached to R30101.

View from hydro pad towards adjacent residential community Ruptured end of pipe wrapped around support beam.

(Continued)

306  Petroleum Refining Design and Applications Handbook Volume 2

Pipe supports

Explosion damage to light structural elements, hydro pad.

Elevation view of surveyed pipe.

Plan view of surveyed pipe.

Images of the “SER 34” ruptured segment after sectioning and removal in March 2010.

Pipe support location. The fractured end SER 34, before and after sectioning in August 2010.

Approximate sectioning location

In-service location

SER 36 valve

Image of the downstream fractured section “SER 35” prior to sectioning for removal from the site in March 2010.

(Continued)

Fluid Flow  307 BP Texas City Refinery, TX Refinery Fire

Root Causes, Findings, and Recommendations

On July 28, 2005, the BP Texas City refinery experienced a major fire in the Residue Hydrotreater Unit (RHU) that caused a reported $30 million in property damage. One employee sustained a minor injury during the emergency unit shutdown and there were no fatalities.

The U.S. Chemical Safety and Hazard Investigation Board has now issued a safety Bulletin to focus attention on process equipment configuration control and positive material verification of critical alloy steel piping components. The CSB recommends that the refining, petrochemical and chemical industries review material verification programs to ensure that maintenance procedures include sufficient controls and positive material identification (PMI) testing to prevent improper material substitutions in hazardous process system.

Residual material from the crude oil processing unit is processed in the RHU to remove nitrogen, sulfur, and metals. Hydrogen is pressurized to about 3000 psi, and then preheated in the RHU heat exchangers (Figure 2) to about 600°F. The preheated hydrogen next passes through a furnace to increase the hydrogen temperature and then is injected into the reactor feedstock. Hydrogen combines with nitrogen compounds and sulfur within the feedstock in the presence of the catalyst inside the RHU reactors to hydrogen sulfide and ammonia. Light hydrocarbon, such as gasoline is then processed in downstream refinery units. On July 25, 2005, at about 6:00 pm, an RHU hydrogen gas heat exchanger process pipe ruptured. The venting hydrogen gas ignited and a huge fireball erupted in the unit. One employee sustained a minor injury while assisting with the RHU emergency shutdown. The RHU sustained major damage from the hydrogen-fed fire that burned for 2 h. There were no offsite impacts, but as a precaution Texas City ordered a shelter-in-place for nearby residents until the fire was contained. This incident occurred after a maintenance contractor accidentally switched a carbon steel elbow with an alloy steel elbow during a scheduled heat exchanger overhaul in February 2005. The alloy steel elbow was resistant to high temperature hydrogen attack (HTHA) but the carbon steel elbow was not. Metallurgical analyses of the failed elbow concluded that HTHA severely weakened the carbon steel elbow. BP personnel examined the extensively damaged unit and determined that an 8-in. diameter pipe elbow on an RHU heat exchanger hydrogen gas outlet pipe ruptured (Figure 3). The BP investigation team recovered the elbow segments that remained attached to the pipe and three pieces found in the debris (Figure 4).

Incidents involving HTHA are as far back as 1940s. Carbon steel in hydrogen service at temperatures above about 450°F and pressures above 100 psia is susceptible to HTHA. At these operating conditions, atomic and molecular hydrogen permeates the steel and reacts with dissolved carbons or carbides to form methane gas (CH4). The loss of carbon in the steel or “decarbonization,” significantly degrades the steel’s mechanical properties, including tensile strength and ductility. The CH4 gas creates high localized stresses, which combine with the normal piping system stresses to create voids and fissures in the steel, which ultimately causes the pipe to rupture (API, 2004). The American Petroleum Institute (API) Recommended Practice, 941, Steels in Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants, recommends operating limits for carbon steel and low alloy steel piping systems in hydrogen service. Experiments and operating plant data show that HTHA is typically avoided by using low alloy steels containing 1.25–3.0% chrome, as the chrome combines with carbon to form chromium carbide, which is resistant to reacting with hydrogen. Chemical analysis and microscopic examination determined that the elbow was made from carbon steel, and also that the segments were severely decarburized and had deep fissures on the inside surface (Figure 4). The decarburized steel and severe fissuring confirmed that HTHA caused the catastrophic elbow failure.

(Continued)

308  Petroleum Refining Design and Applications Handbook Volume 2

Figure 1. Carbon steel RHU heat exchanger outlet pipe (arrow) ruptured after operating only 3 months in high-temperature hydrogen service.

Figure 2. Dimentionally identical piping elbows on RHU heat exchangers A and B

A Elbow 3

A Elbow 2 Elbow 1

B

Detailed metallurgical examinations and micro-hardness testing quantified the extent of hydrogen damage to estimate the total time the elbow could have been in the hightemperature, high-pressure hydrogen service before it failed. The results compared to existing experimental data and empirical service life predictions, concluded that the elbow failed after being in service for fewer than 3000 h. Recommendations: To revise the maintenance quality control program to require positive material identification testing or another suitable material verification process for all critical service alloy steel piping components removed and reinstalled during maintenance, and inform work crews of special material and handling precautions. To develop/update the written piping component installation quality control procedure to require positive material identification testing or other suitable verification or tracking process for all alloy steel piping components removed during maintenance.

Upper left & top arrow-Allow steel elbows 2 and 3 Low left & top arrow-Carbon steel elbow I

Figure 3. Ruptured 8-inch pipe elbow on heat exchanger A outlet.

BP personal examined the extensively damaged unit and determined that an 8-inch diameter pipe elbow on an RHU heat exchanger hydrogen gas outlet pipe ruptured . . .

Figure 4. Ruptured 8-inch carbon steel pipe elbow pieces recovered after the fire

Figure 5. RHU hydrogen heat exchanger piping material requirements

The BP investigation team recovered the elbow segments that remained attached to the pipe and three pieces found in the debris . . . . 7/8"

Upper left -- Carbon steel elbow segments (view of inside surface) Above -Flange segments Lower left -- Close-up of fissure on middle elbow segement

High-temperature hydrogen to furnace

Preheat gas

Heat exchanger A Elbow 3 (failure location) Elbow 2

Bolted flange (typical)

1-¼ chrome alloy piping Elbow 1 Carbon steel Heat exchanger B

Preheat Gas to Separator Low temperature 3000 psig hydrogen feed

1-¼ chrome alloy pipe Carbon steel pipe

(Continued)

Fluid Flow  309 Valero’s McKee Refinery, Sunray Texas On February 16, 2007, a liquid propane release from cracked control station piping resulted in a massive fire in the propane deasphalting (PDA) unit injuring three employees and a contractor. The fire caused extensive equipment damaged and resulted in the evacuation and total shutdown of the refinery. The refinery remained shutdown for 2 months; the PDA unit was rebuilt and resumed operation nearly one year after the incident. Direct losses attributed to the fire were reported to exceed $50 million. The liquid propane under high pressure was released in the PDA, and the resulting vapor found an ignition source, and the subsequent fire injured workers, damaged unit piping and equipment and collapsed a major pipe rack. The fire grew rapidly and threatened surrounding units, including a Liquefied Petroleum Gas (LPG) storage area. Fire-fighting efforts were hampered by high and shifting winds and the rapid spread of the fire. A refinery-wide evacuation was ordered approximately 15 min after the fire ignited. The fire occurred in the refinery’s propane de-asphalting unit, which uses high-pressure propane as a solvent to separate gas oil from asphalt; gas oil is used as a feedstock in other gasoline-producing refinery processes. The propane leaked from an ice-damaged piping elbow that is believed to have been out of service since the early 1990s. PDA Unit

Root Causes, Findings, and Recommendations The CSB launched an investigation into the cause of the incident. The root cause was the water that leaked through a valve, froze, and cracked an out-of-service section of piping, causing a release of high-pressure liquid propane. The CSB report concluded the root causes of the incident were that the refinery did not have an effective program to identify and freeze-protect piping and equipment that was out of service or infrequently used; that the refinery did not apply the company’s policies on emergency isolation valves to control fires; and that current industry and company standards do not recommend sufficient fireproofing of structural steel against jet fires. CSB investigation reported that unknown to refinery personnel, a metal object had wedged under the gate of a manual valve above the piping elbow, allowing liquid to flow through the valve. Piping above the valve contained liquid propane at high pressure, and small amounts of water were entrained in the propane. The elbow was part of a dead-leg formed when the piping was taken out of service. This section of piping remained connected to the process but was not intended to have any flow of liquid through it. Dead-legs can pose special hazards in refineries that should be carefully managed. Hazards rising from the dead-leg when it was created in the 1990s were not identified and safeguards were not implemented such as removing the piping, isolating it from the process using metal plates known as blinds, or protecting it against freezing temperatures. Over time, water seeped past the leaking valve and built up inside the low point of the piping elbow. A period of cold weather in early February 2007 likely caused the water to freeze, expand and crack the piping. On February 16, the daytime temperature increased and the ice began to melt. At 2:09 p.m. high-pressure liquid propane flowed through the leaking valve and was released through the fracture elbow. Propane escaped from the pipe at an initial rate of 4500 lb/min, which quickly created a huge flammable vapor cloud that drifted toward a boiler house that acted as the ignition source.

Figure 1. PDA unit location in the McKee Refinery

(Continued)

310  Petroleum Refining Design and Applications Handbook Volume 2

High-Pressure C3 Accumulator

C3 = Propane

C3 to Extractor

Water drain

Pitch Feed No. 1 C3 Wash to Extractor Extractor

DAGO 1st Stage Flash Drum

Propane from Asphalt Flash Drums

Propane Makeup

(Not Used) Mix C3

Low-Pressure C3 Accumulater

DAGO Flash Drums

Failed elbow

To Asphalt Heater & Flash

Water drain DAGO to Processing

C3 to Extractor

Figure 2. No. 1 Extractor simplified process flow diagram

No. 1 Extractor

Figure 3. Approximately 90 seconds after ignition (from surveillance video)

Damaged Cooling Tower

Once the fire started, there was no way to shut off the supply of fuel, because the refinery had not implemented Valero procedures requiring the installation of remotely operable shutoff valves. These valves are critical in high-pressure service to prevent large inventories of flammable material inside process equipment from contributing to a fire. The CSB recommended that Valero and industry standards require fireproofing of structural steel supports to a maximum of 50 ft. from possible fuel sources. The collapse of a nonfireproofed pipe bridge 77 ft. away from the source of the jet fire indicated that industry practices require revision. The Board further called on the American Petroleum Institute (API) to develop a new recommended practice for freezeprotection of refinery equipment and to improve existing practices related to fireproofing, emergency isolation valves and water deluge systems. The CSB report called on Valero Energy Corporation to improve freeze protection, fireproofing, hazard analysis and emergency isolation procedures at its 16 refineries. Further, the CSB urged Valero to implement its strategic plan to eliminate the use of chlorine for water treatment in favor of inherently safer alternatives such as bleach. Also that staff work should upgrade hazard analysis procedures.

Heat Affected Butane Sphere

Chlorine Container Shed PDA Extractors

Collapsed Rack

Damaged Naphtha Column

Figure 4. Aerial photograph of damage from the PDA unit fire From Propane Pumps 10” Piping (Pressurized)

8" globe valve (closed)

10" inlet gate valve (closed, leaking) Cracke 10" diameter inlet elbow

To Extractor

10" gate valve (closed) 6" control valve

Figure 5. Propane mix control station schematic (not to scale)

(Continued)

Fluid Flow  311

Figure 6. Crack in the 10" diameter propane mix control station inlet elbow

Damaged Inlet to Extractor No. 1 Figure 8. Damaged 10" propane inlet on Extractor No. 1

Valve Body Foreign Material

Valve Gate

Collapsed Support

Edge of PDA Unit

Fireproofed Supports

Chlorine Shed

Figure 10. Extractor towers (upper right) and collapse pipe rack Figure 7. Downstream view of propane mix control station inlet block valve

Failed Pipe Rack Support (not fireproofed

- Remotely Operated Shutoff Valve (ROSOV) - Pump Column

Intact Pipe Rack Supports (fireproofed) Raw Materials Tanks

Reactor

Products Tanks

90 Feet Between Pipe Bridge Supports

Graphic based on FM Global Property Loss Prevention Data Sheet 7-14, 2004

Figure 12. Insurer-recommended locations for ROSOVs

Figure 9. Pipe bridge support fireproofing

(Continued)

312  Petroleum Refining Design and Applications Handbook Volume 2 Approx. location of Propanr Mix Valve & first release point No. 1 Extractor

Jet fire from failed flange

Non-affected rack supports

Deluge Valve Location

77 t fee

No. 2 Extractor

51

fee t

Heat Damaged Coating

Failed. nonfireproofed, pipe rack support

Figure 11. Distance between the E-W pipe rack supports the extractors

Extractors

Figure 14. Heat-damaged coating on sphere and location of sphere deluge valves

Figure 13. Ruptured one-ton chlorine container

ExxonMobil Baton Rouge Refinery, Louisiana, USA

Root Causes, Findings, and Recommendations

On November 22, 2016, two operators were preparing isobutane equipment for maintenance. As part of this preparation, the operators required to adjust valves to put a spare isobutane plug valve to the spare pump. The refinery used a type of valve known as a quarter-turn plug valve for many applications in the alkylation unit, including the inlet valves to these isobutane pumps.

The CSB learned that there were long – standing reliability issues with gearboxes used to operate plug valves in the refinery’s alkylation unit. Furthermore, when alkylation unit operators encountered a malfunctioning gearbox on a plug valve, it was an accepted practice for the operator to remove the gearbox to open or close the valve with a pipe wrench. Baton Rouge refinery management did not provide the workers performing this operations activity with a written procedure or training on safe gearbox removal from plug valves and its associated hazards.

During the removal of an inoperable gearbox, on a plug valve, the operator performing this activity removed critical bolts securing the pressure-retaining component of the valve known as the top-cap. When the operator then attempted to open the plug valve with a pipe wrench, the valve came apart and released isobutane into the unit, forming a flammable vapor cloud. The isobutane reached an ignition source within 30 s of the release causing a fire and severely burning four workers who were unable to exit the vapor cloud before it ignited.

There are a number of safety management deficiencies that led to the removal of the plug valve gearbox, and the inadvertently disassembly of its pressure-retaining top-cap resulted in an isobutane release and fire.

(Continued)

Fluid Flow  313 The deficiencies included:

Isobutane Vessel Spare Pump Suction Plug Valve

Normal Pump Suction Plug Valve

Spare Pump

Isobutane Recycle Pump

Figure 1. Simplified diagram of the alkylation unit equipment where the release occurred.

Gearbox

Handwheel

Valve Stem

Support Bracket

Equipment Design and Human Factor Analysis

Top-Cap

Figure 2. Illustration showing an alkylation unit plug valve with gearbox, valve stem, top-cap, support bracket, and handwheel similar to the one involved in the incident. Valve That Was Disassembled on Day of Incident

Method Gearbox Removed on Day of Incident

• Failure to identify and address the older model plug valve design and gearbox reliability issues. • Lack of a human factors evaluation to identify the older model plug valves’ design and reliability issues as well as the potential hazards associated with operating and maintaining these valves. • No written procedures detailing the steps needed to remove different models of gearboxes from plug valves to manually open or close the valve safely. • No training workers to safely remove the various plug valve gearbox models in the alkylation unit and the hazard associated with this type of work. • An organizational culture that accepted operators removing malfunctioning plug valve gearboxes despite the lack of detailed procedures and training for safe removal.

Designed Way to Remove Gearbox

Gearbox support brackets (Figure 2) on 15 plug valves located in the refinery’s alkylation unit were attached using the same four vertical bolts that secure the pressure retaining top-cap to the valve body. This gearbox (a 30-plus year old design), however could be removed by taking off the horizontal bolts without disturbing the critical top-cap bolts.

According to API Standard 599, Metal Plug Valves—Flanged, Threaded, and Welding Ends, Valves supplied with the capability of mounting actuators or gear operators shall be capable of doing so without removal of any [pressure-retaining parts (e.g., body bolts, bonnet bolts, flange bolts, packing gland bolts, packing retaining stem nut, etc.). The CSB provides the following key lessons for companies with chemical manufacturing facilities including refineries: Evaluate human factors associated with operational difficulties that exist in your machinery and other equipment, especially when the equipment is part of a process covered by the Process Safety Management (PSM) standard.

Figure 3. Gearbox removal. The left column illustrates how operators removed the plug valve gearbox on the day of the incident. Its shows operators removed the entire support bracket. By design, removing the gearbox did not require removing the four vertical bolts that secured the pressure-retaining top-cap. The right column illustrates how the plug valve gearbox should be disassembled. The gearbox and handwheel could be disconnected from the support bracket by removing the two horizontal bolts on the side of the support bracket.

Apply the hierarchy of controls to mitigate the identified hazards. In the case of Baton Rouge refinery, the personnel should have evaluated the fact that approximately three percent of the plug valves in the alkylation unit used a gearbox attachment design that could result in inadvertent disassembly of pressure-retaining components. Once identified the refinery should have applied the hierarchy of controls to establish a mitigating strategy for susceptible plug valves. (Continued)

314  Petroleum Refining Design and Applications Handbook Volume 2 Establish detailed and accurate procedures for workers performing potentially hazardous work, including job tasks such as removing an inoperable gearbox. In this case, establish procedures specific to removing malfunctioning gearboxes from plug valves.

Figure 4. Welding machine that was the likely ignition source of the isobutane vapor cloud.

Time = 2 seconds

Time = 27 seconds

Ignition

Isobutane Release

Time = 30 seconds

Time = 33 seconds

Time = 39 seconds

Time = 51 seconds

Figure 5. Sequence of events. Baton Rouge refinery security video clips showing the isobutane release and subsequent fire. This sequence does not show time zero − the first indication of the isobutane vapor cloud.

Provide training to ensure workers can perform all anticipated job tasks safely. This training should include a focus on processes and equipment to improve hazard awareness and help prevent chemical incidents. The CSB provides the following guidance to companies with chemical manufacturing facilities including refineries, which use manual gear-operated plug valves. Survey valves to identify gear-operated plug valves with gearbox support brackets attached to pressure-retaining components. Perform a hazard analysis and risk assessment on susceptible valves using the hierarchy of controls to establish a mitigating strategy. Consider upgrading to a newer plug valve design and attach the gearbox support bracket to the valve flanges (see Figure 9) or otherwise address the potential hazard. For susceptible valves identified for future upgrades, develop an interim hazard mitigation plan to control hazards and protect workers. Provide written procedures and training to ensure workers can safely remove the gearbox from the plug valve. Consider expanding this guidance beyond manual gear operators to evaluate other devices such as motors or actuators that may attach to pressure-retaining valve components.

Figure 6. Gearbox support bracket for the valve involved in the incident. The two horizontal bolts (yellow arrows) can be removed to take the gearbox off the support bracket and the valve without disturbing the top-cap bolts. By removing the gearbox in this manner, the pressure-retaining valve components are not disturbed.

Figure 7. The improved plug valve design includes an additional four gearbox support barcket holes separate from the pressure-retaining top-cap (located on the valve body flanges) as seen at the yellow arrows. The photo on the right shows a gearbox support bracket attached to the valve body flange for a valve that was not involved in the incident. The photo on the left shows a different plug valve in the alkylation unit with its gearbox removed.

(Continued)

Fluid Flow  315

Figure 8. Two of several designs of gearbox support brackets (yellow circles) used at the Baton Rouge refinery. These specific brackets attach to the valve body flange – they are not among the approximetly three percent of valves in the alkylation unit that attach the gearbox support bracket using the same four vertical bolts that secure the pressure-retaining top-cap.

Handwheel

Gearbox

Support Bracket Valve Stem

Support Bracket

Top-Cap

Figure 9. The post-1984 plug valve design, showing how one type of gearbox connects to all four dedicated attachment points on the valve flanges that are not pressure-retaining parts.

Newer Gearbox Design Not PressureRetaining Bolts

Gearbox Involved in Incident Pressure Retaining Bolts

Figure 10. Comparison of newer gearbox attachment designs, which are among the approximetly 97 percent of the gearboxes in the alkylation unit, and the gearbox involved in the incident. Importantly, the improved valve design connects the gearbox support bracket to dedicated connection points on the valve flange as shown in the left illustration.

VALVE COMPONENTS

Valve Bonnet (Continued) • Bonnet is connected to the body by a threaded, bolted, or welded joint • In all cases, the attached of the bonnet to the body is considered a pressure boundary • The weld joint or bolts that connect the bonnet to the body are pressure-retaining parts • Valve bonnets, although as necessity for most valves, represent a cause for concern. Bonnets can: – Complicate the manufacture of valves – Increase valve size/weight – Be a source for potential leakage

Figure 11. Slide from ExxonMobil Manual Valve Basics training course. The third bullet point in the slide, which is slide 24 of 153, indicates that the bolts connecting the bonnet to the body are pressureretaining parts.

(Continued)

316  Petroleum Refining Design and Applications Handbook Volume 2 Pump switch

Valve needed to be opened Gearbox Inoperable

Planned maintenance

Chronic reliability issues with plug valve gearboxes in alkylation unit Gearbox assembly removed to manually turn valve stem with a wrench

Past practice Described as a “learned habit”

Chronic gearbox reliability issues

Valve design Gearbox support bracket removed

Four bolts removed from pressure-containing top-cap

Support bracket could appear to be part of gearbox

Human factors No written procedures for gearbox removal. No training for gearbox removal

Plug valve disassembled Organizational culture Flammable Isobutane released

Hazard not identified

Work allowed without procedure or training Serious incidents at Torrance and Baton Rouge refineries Not evaluated in human factors analysis 30 year-old design

Gearbox attached to pressureretaining valve component

Isobutane release and fire critically injured four workers

Human factors

Valve Design

Only three percent of unit values with this gearbox attachment design Valves not upgraded Hierarchy of controls not applied

Isobutane used in alkylation

Process design

Post-turnaround maintenance Multiple ignition sources present

Oxygen present in atmosphere

Welding machine most likely source of ignition

Common practice at Baton Rouge refinery

Welding job permitted

Normal concentration

Figure 12. Simplified causal analysis of the November 22, 2016 incident at the Baton Rouge refinery.

Flixborough Chemical Plant Explosion, 1st June, 1974, U.K.

Health and Safety Executive (HSE) Root Causes, Findings, and Recommendations

On 1st June 1974, a vapor cloud explosion occurred in the reactor section of the caprolactam plant (a chemical used in the manufacture of Nylon 6) at the Flixborough Works (U.K.).

The cause of the disaster was a modification to a 28 in. pipe connection between two reactors. The modification involved the installation of a temporary 20 in. pipe with bellows at each end. The design of the pipe system was defective in that it did not take into account the bending moments on the pipe due to the pressure in it. The bellows were not installed in accordance with the manufacturer’s instructions. The pipework assembly was not adequately supported. The relevant British Standards, notably BS 3351 and 3974 were not followed.

The chemical works, owned by Nypro UK (a joint venture between Dutch State Mines (DSM) and the British National Coal Board (NCB)) had originally produced fertilizer from by-products of the coke ovens of a nearby steelworks. Since 1967, it had instead produced caprolactum, a chemical used in the manufacture of nylon 6. The caprolactam was produced from cyclohexanone. This was originally produced by hydrogenation of phenol, but in 1972 additional capacity was added, built to a DSM design in which hot liquid cyclohexane was partially oxidized by compressed air. The plant was intended to produce 70,000 tpa (tons per annum) of caprolactam but was reaching a rate of only 47,000 tpa in early 1974. Government controls on the price of caprolactam put further financial pressure on the plant. In the DSM process, cyclohexane was heated to about 155°C (311°F) before passing into a series of six reactors. The reactors were constructed from mild steel with a stainless steel lining; when operating they held in total about 145 tons of flammable liquid at a working pressure of 8.6 bar gauge (0.86 MPa gauge; 125 psig). In each of the reactors, compressed air was passed through the cyclohexane, causing a small percentage of the cyclohexane to oxidize and produce cyclohexanone, some cyclohexanol also being produced. Each reactor was slightly (approximately 14 in., 350 mm) lower than the previous one, so that the reaction mixture flowed from one to the next by gravity through nominal 28-in. bore (DN 700 mm) stub pipes with inset bellows. The inlet to each reactor was baffled so that liquid entered the reactors at a low level; the exiting liquid flowed

The disaster involved (and may well have been caused by) a hasty modification. There was no on-site senior manager with mechanical engineering expertise (virtually all the plant management had chemical engineering qualifications); mechanical engineering issues with the modification were overlooked by the managers who approved it, nor was the severity of the potential consequences of its failure appreciated. Failings in technical measures: • A plant modification occurred without a full assessment of the potential consequences. Only limited calculations were undertaken on the integrity of the bypass line. No calculations were undertaken for the dog-legged shaped line or for the bellows. No drawing of the proposed modification was produced. • Plant Modification /Change Procedures. Hazop. • Design Codes—Pipework. Use of flexible pipes. • No pressure testing was carried out on the installed pipework modification. • Maintenance Procedures. Recommissioning. • Those concerned with the design, construction and layout of the plant did not consider the potential for a major disaster happening instantaneously.

(Continued)

Fluid Flow  317 over a weir whose crest was somewhat higher than the top of the outlet pipe. The mixture exiting reactor 6 was processed to remove reaction products, and the unreacted cyclohexane (only about 6% was reacted in each pass) then returned to the start of the reactor loop. Although the operating pressure was maintained by an automatically controlled bleed valve once the plant had reached steady state, the valve could not be used during start-up, when there was no air feed, the plant being pressurized with nitrogen. During start-up the bleed valve was normally isolated and there was no route for excess pressure to escape; pressure was kept within acceptable limits (slightly wider that those achieved under automatic control) by operator intervention (manual operation of vent valves). A pressure-relief valve acting at 11 kg/cm2 (156 psi) gauge was also fitted. At about 16:53 on Saturday 1 June 1974, there was a massive release of hot cyclohexane in the area of the missing reactor 5, followed shortly by ignition of the resulting cloud of flammable vapor and a massive explosion in the plant. It virtually demolished the site. Since the accident took place at a weekend there were relatively few people on site: of those on-site at the time, 28 were killed and 36 injured. Fires continued on-site for more than 10 days. Off-site there were no fatalities, but 50 injuries were reported and about 2000 properties damaged. The occupants of the works laboratory had seen the release and evacuated the building before the release ignited; most survived. None of the 18 occupants of the plant control room survived, nor did any records of plant readings. The explosion appeared to have been in the general area of the reactors and after the accident only two possible sites for leaks before the explosion were identified: “the 20 in. bypass assembly with the bellows at both ends torn asunder was found jack-knifed on the plinth beneath” and there was a 50-in. long split in nearby 8-in. nominal bore stainless steel pipework. It was a failure of this plant that led to the disaster. A major leak of liquid from the reactor circuit caused the rapid formation of a large cloud of flammable hydrocarbon. When this met an ignition source (probably a furnace at a nearby hydrogen production plant) there was a massive fuel–air explosion.. The plant control room collapsed, killing all 18 occupants. Nine other site workers were killed, and a delivery driver died of a heart attack in his cab. Fires started on-site which were still burning 10 days later. Around 1000 buildings within a mile radius of the site (in Flixborough itself and in the neighboring villages) were damaged.

• Plant Layout: positioning of occupied buildings. • Control Room Design: structural design to withstand major hazards events. • The incident happened during start up when critical decisions were made under operational stress. In particular the shortage of nitrogen for inerting would tend to inhibit the venting of offgas as a method of pressure control/reduction The disaster was caused by “a well designed and constructed plant” undergoing a modification that destroyed its technical integrity. • Modifications should be designed, constructed, tested and maintained to the same standards as the original plant. When the bypass was installed, there was no works engineer in post and company senior personnel (all chemical engineers) were incapable of recognizing the existence of a simple engineering problem, let alone solving it. • When an important post is vacant special care should be taken when decisions have to be taken which would normally be taken by or on the advice of the holder of the vacant post. • All engineers should learn at least the elements of other branches of engineering than their own. HYDROGEN PLANT

LABORATORY

SECTION 25 A

MAIN OFFICE BLOCK

CONTROL ROOM

PLATE 1

Figure 1. Aerial photo of the plant.

Figure 2. Explosion and fire due to vapor cloud with an ignition source. (Continued)

318  Petroleum Refining Design and Applications Handbook Volume 2

Figure 3. Aerial photo of the plant site after explosion.

28” DIAMETER STUB PIPE

28” DIAMETER STUB PIPE

JACK KNIFE BY-PASS PIPE

PLATE

Figure 4. Damage to pipework, reactors, etc. Inside the plant, 28 people were killed and another 36 were injured. Injuries and damage were widespread outside the Works.

Trevor Kletz saw the plant as symptomatic of a general failure to consider safety early enough in process plant design, so that designs were inherently safe—instead processes and plant were selected on other grounds than safety systems bolted on to a design with avoidable hazards and unnecessarily high inventory. Health and Safety at Works Acts, 1974 (HASAWA) already required companies to have a safety policy, and a comprehensive plan to implement it. Advisory Committee on Major Hazards (ACMH) felt that for major hazard installations the plan should be formal and include: • the regulation by company procedures of safety matters (such as; identification of hazards, control of maintenance (through clearance certificates, permits to work etc.), control of modifications which might affect plant integrity, emergency operating procedures, access control). • clear safety roles (e.g., the design and development team, production management, safety officers). (Continued)

Fluid Flow  319 • training for safety, measures to foster awareness of safety, and feedback of information on safety matters. • Safety documents were needed both for design and operation. The management of major hazard installations must show that it possessed and used a selection of appropriate hazard recognition techniques, had a proper system for audit of critical safety features, and used independent assessment where appropriate.

15.39 Lessons Learned From Piping Designs There are case histories relating to system design that emphasize that accidents occur rapidly with inadequate time to manually return the system to control once the accident is in progress; the system designs required for preventing accidents or mitigating the consequences of accidents are precise that require only minor process changes and the time and effort required to develop a safe system design are justified. An engineer can be hired for a fraction of the cost most accidents. Howard [72] and Kletz [73] have emphasized the design features for safer plants and Crowl and Louvar [74] provide the following recommendations: • • • • • • • • • • • • • • • • • • • • • • •

Use the appropriate materials of construction, especially when using old systems for new applications. Do not install pipes underground. Be sure that the quality of construction (e.g., welds) meets the required specifications. Check all purchased instruments and equipment for integrity and functionality. Do not secure pipes too rigidly. Pipes must be free to expand so that they will not damage other parts of the system. Do not install liquid-filled flanges above electrical cables. A flange leak will douse the cables with liquid. Provide adequate supports for equipment and pipes. Do not allow spring supports to be completely compressed. Design doors and lids so that they cannot be opened under pressure. Add interlocks to decrease pressure before the doors can be opened. Also, add visible pressure gauges at the doors. Do not let pipes touch the ground. Remove all temporary supports after construction is completed. Remove all temporary startup or checkout branches, nipples, and plugs and replace them with properly designed welded plugs. Do not use screwed joints and fittings when handling hazardous chemicals. Be sure that all tracing is covered. Check to ensure that all equipment is assembled correctly. Do not install pipes in pits, trenches, or depressions where water can accumulate. Do not install relief tailpipes too close to the ground where ice blockage may make them inoperable. Be sure that all lines that can catch water can be appropriately drained. When welding reinforcement pads to pipes or vessels, ensure that trapped air can escape through a vent during heating. Do not install traps in lines where water can collect and develop a corrosion problem. Install bellows carefully and according to manufacturers’ specifications. Bellows should be used cautiously. If required, inspect frequently and replace when necessary before they fail. Make static and dynamic analyses of pipe systems to avoid excessive stresses and excessive vibrations. Design systems for easy operation and easy maintenance, e.g., install manual valves within easy reach of the operators, and design pipe networks for easy maintenance or with easy access to equipment requiring maintenance. Install bug screens on vent lines.

320  Petroleum Refining Design and Applications Handbook Volume 2 • Make structural analyses or relief system to avoid structural damage during emergency reliefs. • Safety technology must not work right the first time. Usually, there is no opportunity to adjust or improve its operation. • Critical safety instruments must have backups. • Provide hand-operated or automatic block valves, equivalent valves for emergency shutdowns. • Use electronic or mechanical level gauges, not glass sight glasses. • Add fail-safe block valves with a positive indication to the valve position (limit switches). Organizations should ensure that a good safety program is developed with personnel who can readily identify and eliminate safety problems. Better safety program can be developed by implementing management systems to prevent the existence of safety problems. The systems commonly employed in industry include safety reviews, operating procedures and maintenance procedures. The causes of major accidents can ultimately be attributed to a lack of management systems. Case histories have exemplified and recognized that the existence of procedures is inadequate. There must also be a system of checks in place to ensure that the procedures are used effectively and strictly followed. Process hazard analysis (PHA) and management systems are discussed later in Volume 4 of these series.

15.40 Design of Safer Piping Inherent safer piping design relies on abiding by several regulations and standard codes, such as the American Society of Mechanical Engineers (ASME) and American Petroleum Institute (API), British Standards (BS) and other international relevant standards and codes. A review of these codes and standards is presented as follows [81].

15.40.1 Best Practices for Process Piping ASME B31.3 Process piping provides best practices for compressor station air, hydraulic power and lube oil piping. This is applicable to piping that is typically found in petroleum refineries, chemical process industries, and related facilities. For these applications, the required thickness of straight steel piping is determined by [76]

tm = t + c

(15.380)

where tm = minimum required wall thickness, including mechanical, corrosion, and erosion allowances. t = nominal wall thickness based on the internal design pressure c = sum of the mechanical allowance (thread or groove depth) plus corrosion and erosion allowances.



t=

Pg D 2(S s Q f W + PgY )

(15.381)

where Pg = Internal design gage pressure Ss = Stress value for the material Qf = quality factor W = weld joint strength reduction factor Y = temperature coefficient and is calculated by:



t=

d + 2c D + d + 2c

(15.382)

Fluid Flow  321 where d = inside diameter of the pipe. D = nominal outside diameter of the pipe. Eqs. 15.381 and 15.382 apply when t < D/6, and is therefore checked after determining the thickness. For t ≥ D/6 or Ps/Ss Qf > 0.385, calculation of wall thickness for straight pipe requires special consideration of factors, namely: effects of fatigue, thermal stress, and theory of failure and so on. ASME B31.3 “Process Piping” and all gas compressing station, water and steam piping should be constructed in accordance with ASME B31.1 “Power Piping” [77]: • The discharge stacks, vents or outlet ports of all pressure relief devices must be located where gas can be discharged into the atmosphere without undue hazard. • Each pressure relief station, pressure-limiting station, or group of such stations installed to protect a piping system or pressure should have sufficient capacity and be set to operate to prevent the pressure from exceeding the level specified [78]. • Any safety device that consists of a series of regulators to control or limit the pressure in a piping system should be inspected to determine that the maximum allowable operating pressure of the system will not be exceeded should any one of the associated regulators malfunction or remain in the fully open position. • If the pressure < 10 psig, the steel service pipe should be designed for at least 100 psig pressure. • All pressure-relieving devices in compressor stations should be inspected and/or tested and all devices except rupture disks should be operated periodically to determine that they open at the correct set pressure. Any defective or inadequate equipment found must be promptly repaired or replaced. • All pressure-limiting stations, relief devices and other pressure regulating stations and equipment should be inspected and/or tested periodically. • Pressure relief or other suitable protective devices of sufficient capacity and sensitivity must be installed and maintained to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than 10%. • A pressure relief valve or pressure-limiting device, such as a pressure switch or unloading device, should be installed in the discharge line of each positive-displacement transmission compressor between the gas compressor and the first discharge block valve. • If the pressure relief valve is the primary overprotection device, the relieving capacity should be equal to or greater than the capacity of the compressor. • Vent lines provided to exhaust the gas from the pressure relief valves to atmosphere should be extended to a location where the gas may be discharged without due hazard. • Vent lines must be sufficient capacity so that they will not inhibit the performance of the relief valve. • At least once each calendar year, a review should be conducted to ensure that the combined capacity of the relief devices on a piping system or facility is adequate to limit the pressure at all times to the required values [78]. • An inspection and/or test of stop valves should be performed to determine that the valves will operate and are correctly positioned. ASME B31.3 provides a table for determining the minimum thickness of external threaded components. Chapter 22 in volume 4 reviews process safety and pressure relieving devices.

15.40.2 Designing Liquid Piping Designing safer hazardous liquid piping requires that the piping complies with 49 CFR part 195, “Transportation of Hazardous Liquids of Pipeline” [79]. If the piping has a maximum operating pressure (MOP) > 20% of the specified

322  Petroleum Refining Design and Applications Handbook Volume 2 maximum yield strength, or if the piping is carrying petroleum in a non rural area, it must comply with this standard. The internal design pressure for steel piping is calculated by [79].



P = 2S

t Fs E s D

(15.383)

where P = internal design pressure S = yield strength t = nominal wall thickness of the pipe D = nominal outside diameter of the pipe Fs = design factor for steel equal to 0.72 Es = seam joint factor. When designing for liquid piping, attention is given to these overlooked requirements [81]: • The minimum wall thickness of the pipe may not be 150

250+

15,000

300

3000

5000

Mixed flow (V)

100,000

75

Axial flow (V)

100,000

25

Centrifugal (V)

400±

5750

Single stage (V) Double suction Single stage (H) Multistage (H) Single and multistage (V)

*Not necessary at same point. (H), horizontal; (V), vertical.

Pumps  333 STATIONARY FACE ADAPTER

SEAT GASKET GLAND ROTATING FACE ROTATING FACE GASKET COIL SPRING

SHAFT SLEEVE DOUBLE MECHANICAL SEAL

IN

OUT

IMPELLER WASHER

CASING

STUFFING BOX COVER

IMPELLER

IMPELLER SCREW

Figure 16.1  Cross-sectional view of a vertical inline pump (by permission from Knoll, H. and S. Tinney, Hydroc. Proc., May 1971, p. 131 and Goulds Pump, Inc. Mechanical seal and seal venting details courtesy Borg-Warner).

The centrifugal pump (Table 16.2) develops its pressure by centrifugal force on the liquid passing through the pump and is generally applicable to high capacity, low to medium head installations. In order to satisfy pump discharge head (or pressure) requirements the unit may be a multistage (multiple impellers) instead of a single stage [1]. The conditions of pumping water vs. pumping hot light hydrocarbons require considerably different evaluation in pump design features for satisfactory operation, safety, and maintenance. The inline centrifugal process pump, Figure 16.1, is relatively new to general applications; however, it is finding many applications where space and installation costs are important. Each application must be carefully evaluated, as there are three basic types of pump construction to consider. Generally, for many applications the dimensions have been standardized through the American Voluntary Standard, American National Standard Institute (ANSI), or American Petroleum Institute (API)-610. The performance curves are typical of single stage centrifugal pumps. The turbine is a special type of centrifugal pump (Figure 16.2) and has limited special purpose applications. Generally, pumps can be used to move fluids that flow from regions of high pressure to regions of low pressure, by increasing the pressure of the fluid. A centrifugal pump increases the absolute pressure of a fluid by adding velocity 1  energy to the fluid  mv 2  and then converting that to pressure or head energy (mgh) in the volute as illustrated 2  in Figure 16.3. The fluid is drawn into the impeller eye (Point 1) at a velocity v1, which is approximately equal to the volumetric flow rate divided by the cross-sectional area of the impeller eye. The rotation of the impeller increases the velocity and pressure of the fluid (Point 2). When the fluid reaches Point 3, it is slowed down by the increasing area of the volute, and the velocity is converted into the pressure head. Euler’s pump equation showing the relationship between the head to the change in velocity of the fluid through the impeller shroud is:



∆h = ηHY

∆(Uv u ) g

(16.1)

334  Petroleum Refining Design and Applications Handbook Volume 2

40 psi

10 psi

30 psi

Cross-section of Heads and Impellers Turbine – Pump Principle 20 psi

Figure 16.2  Turbine pump (courtesy of Roth Pump Co.).

Discharge

3

Impeller Eye 2

1

Suction

Volute Impeller

Figure 16.3  Centrifugal pump increases process head by adding energy to a fluid. Note: a rotating impeller imparts energy to the fluid moving through the pump.

where ηHY = hydraulic efficiency (excluding mechanical loss) U = centrifugal velocity component of the fluid (equal to the angular velocity (Ω) multiplied by impeller radius (r) vu = circumferential velocity component of the absolute velocity vector v g = acceleration due to gravity

Pumps  335 The pressure head (h) is related to the increase in height of a column of fluid that the pump would deliver if the velocity head were converted, without loss into the elevation head. The actual change in pressure resulting from this head can be determined by:



ΔP = hρg

(16.2)

where ΔP = change in pressure ρ = fluid density. Low density hydrocarbon fluids (e.g., ethylene (C2H4), propylene (C3H6) and diesel fuel) require more head to produce the same differential pressure as a higher-density fluid (e.g., water). Therefore, pumps for low-density fluids must incorporate more stages and/or larger impellers to achieve the same results as a pump producing the same differential pressure with a higher-density fluid. Table 16.3 and Figure 16.4 illustrate how fluid density affects the head required to produce the same change in pressure. The differential pressure required to produce flow is created by adding energy to the fluid through the spinning impeller. The amount of pressure increase is directly related to the density of the fluid (ρ) and the product of the impeller radius and the shaft rotation speed squared (rΩ)2. The Table 16.3  Effects of fluid density on head. Property

Ethylene (C2H4)

Propylene (C3H8)

Diesel fuel

Water

ρ (kg/m3)

440

614

850

1000

∆P (kPa)

2000

2000

2000

2000

h (m)

463

332

240

204

Note: h (m) =

10.2•∆P( bar ) Sp.Gr

800

700

Head, m

600

500

Ethylene

400

Propylene

300

Diesel fuel

200

100

0 0

500

1,000

1,500

2,000

2,500

Pressure, kPa

Figure 16.4  Head required to produce similar pressures is higher for lower density fluids.

3,000

336  Petroleum Refining Design and Applications Handbook Volume 2 radius of the impeller determines the pump’s size as well as the initial cost. At slow speeds, fewer problems and less net positive suction head (NPSH) often occur; however, a slow-speed pump requires a larger impeller and is more expensive than a higher-speed pump producing the same head.

16.2 Pump Design Standardization Certain pump designs have been standardized to aid manufacturer’s problems, and to allow the owners to take advantage of standardization of parts and dimensions, and consequently maintain a more useful inventory. The standards are sponsored through ANSI; however, many manufacturers also produce to the API standards and their own proprietary standards. These are special pumps that do not conform to all the standards, but are designed to accomplish specific pumping services. The primary pump types for the petroleum and chemical industries for horizontal and vertical inline applications have been standardized in ANSI B-123, ANSI Std # B73.1M for horizontal end suction centrifugal pumps, and ANSI B73.2M for vertical inline centrifugal pumps. The standards are in a continuous process of upgrading to suit requirements of industry and the manufacturers. The API-610 standard is primarily a heavy-duty application, such as is used for the refinery and chemical industry requirements. This is the only true world pump [2] standard, although the International Organization for Standardization (ISO) is studying such an improved design [3]. The standards are important because they allow the dimensional interchangeability of pumps and shaft packing of different manufacturers, but only as long as the manufacturers conform to the standard.

16.3 Basic Parts of a Centrifugal Pump Table 16.4 is a quick reference as to the function of the basic parts. Table 16.4  Basic parts of a centrifugal pump. Part

Purpose

Impeller

Imparts velocity to the liquid, resulting from centrifugal force as the impeller is rotated.

Casing

Gives direction to the flow from the impeller and converts this velocity energy into pressure energy which is usually measured in feet (meter) of head.

Shaft

Transmits power from the driver to the impeller.

Stuffing box

This is a means of throttling the leakage which would otherwise occur at the point of entry of the shaft into the casing; usually not a separate part, but rather made up of a group of small details, as “A” to “D”.

(A) Packing

This is the most common means of throttling the leakage between the inside and outside of the casing.

(B) Gland

Used to position and adjust the packing pressure.

(C) Seal gauge (also called water-seal or lantern ring)

Provides passage to distribute the sealing medium uniformly around the portion of the shaft that passes through the stuffing box. This is very essential when suction lift conditions prevail to seal against in-leakage of air.

(D) Mechanical seal

Provides a mechanical sealing arrangement that takes the place of the packing. Basically it has one surface rotating with the shaft and one stationary face. The minutely close clearance between these two faces prevents leakage of liquid out or air in.

Shaft sleeve

Protects the shaft where it passes through the staffing box. Usually used in pumps with packing but often eliminated if mechanical seals are employed. (Continued)

Pumps  337 Table 16.4  Basic parts of a centrifugal pump. (Continued) Part

Purpose

Wearing rings

Keeps internal recirculation down to a minimum. Having these rings as replaceable wearing surfaces permits renewal of clearances to keep pump efficiencies high. On small types only one ring is used in the casing and on larger sizes, composition rings are used in the casing and on the impeller.

Wearing plates

With open type impellers or end clearance wearing fits, these perform the same purpose as wearing rings do with radial clearances.

Bearings

Accurately locate shaft and carry radial and thrust loads.

Frame

Used to mount unit rigidly and support bearings. In most single suction pumps this is a separate piece. In many double suction pumps, the support is through feet cast as part of the casing. In some special suction pumps, the feet are also part of the casing and the bearing assembly is overhung. With close coupled single suction types, this support is provided by the motor or by special supporting adapters.

Coupling

Connects the pump to the driver.

Impellers The three common types of impellers that impart the main energy to the liquid for process applications are (see Figure 16.5) as follows: 1. F  ully enclosed—used for high head, high pressure applications. 2. Semi-enclosed—used for general purpose applications, has open vane tips at entrance to break up suspended particles and prevent clogging. 3. Open—used for low heads, suspended solids applications, very small flows. Small radial vanes are usually provided on back shroud or plate of impeller to reduce the pressure on the stuffing box, and to prevent suspended solids from entering the backside and possibly causing clogging. The working or pumping vanes are backward in form relative to the impeller rotation. These impellers are available in nearly any material of construction as well as rubber, rubber-lined, glass-lined, and plastic. The lined impellers are of the open or semi-open type.

Casing The casing maybe constructed of a wide variety of metals, as well as may be lined to correspond to the material of the impeller. Operating pressures go to about 5000 psi (345 bar) for the forged or cast steel barrel-type designs. However, the usual process application is in the 75–1000 (5 - 69 bar) psi range, the latter being in light hydrocarbon and similar high vapor pressure systems. The removal of the casing parts is necessary for access to the impeller and often to the packing or seals. Some designs are conveniently arranged to allow dismantling the casing without removing the piping connections. There are proposed construction standards being considered which will allow easy maintenance of many of the types now being offered in a non-standard fashion.

Shaft Care should be given in selecting the shaft material. It must be resistant to the corrosive action of the process fluids, yet possess good strength characteristics for design. For some designs it is preferable to use a shaft sleeve of the proper corrosion-resistant material over the preferred structural shaft material. These sleeves may be metal, ceramic, rubber, and so on, as illustrated in Figure 16.6.

338  Petroleum Refining Design and Applications Handbook Volume 2

Enclosed single-suction impeller with sealing on suction and back sides (courtesy The Deming Co.).

Mixed flow semi-enclosed impeller (courtesy The Deming Co.).

Front

Enclosed double-suction impeller with sealing rings on both sides (courtesy The Deming Co.).

Semi-open or semi-enclosed impeller (courtesy Goulds Pumps Inc.).

Back

Figure 16.5  Impeller types. Open impeller for corrosive or abrasive slurries and solids (courtesy of Goulds Pumps, Inc.).

Bearings The bearings must be adequate to handle the shaft loads without excessive wear, provided lubrication is maintained. Usually this is not a point of real question provided the manufacturer has had experience in the type of loads imposed by the service conditions, and the responsibility for adequate design must be his/hers. In all cases, the bearings should be of the outboard type, that is, not in the process fluid, unless special conditions prevail to make this situation acceptable.

Packing and Seals on Rotating Shaft Conventional soft or metallic packing in a stuffing box (Figure 16.7) is satisfactory for many low pressures, noncorrosive fluid systems. Special packings such as Teflon, or mechanical seals are commonly used for corrosive fluids, since there can be leakage through the packing along the rotating shaft. However, for these conditions a mechanical seal is preferred. When the pressure becomes high (above about 50 psig (3.4 barg)) or the fluid is corrosive, additional means of sealing the shaft must be provided. Particular care must be taken in handling and using the mechanical seals, and these special instructions should be obtained from the seal manufacturer [4]. Generally, it is not wise to

Pumps  339 Turn Pump Over by Hand before Starting Motor to see that It Turns Freely. 3

44 74

1

No. 1. 3. 4. 7. 10. 12. 13. 44. 55. 56. 59. 60. 61. 62. 74. 79. 82. 88. 98. 106. 144. 164. 165. 167.

X&Y

165

Lubricate Stuffing Box By Circulating Water or Clear Solution thru Connections “X” & “Y”.

167

60

164

79

10

59 60

Tang of Key Must be Located Here

98

144

74 10

12 56

88

GAP

13 106

82 7

Impeller

3

Lining

62

55

Thrower Ring Must Not Cover Gap

61 4

Part Name Pump Casing Impeller Pump Frame Split Gland Shaft Lantern Ring Packing Nipple (2) Thrower Ring Rubber Ring Resilient Sleeve Shaft Sleeve Rubber Ring Retaining Ring Rubber Ring Capscrew (6) Gland Yoke Key Shaft Sleeve Ext’n. Tie Rod Key Washer (2) Retainer (2) Rubber Ring (2)

Figure 16.6  Stuffing box details lined pump with porcelain or Teflon® shaft sleeve (courtesy of Dorr-Oliver, Inc.).

Stuffing box packing Throat bushing

Lantern gland Longitudinal section with Lantern Gland

Stuffing box gland

Figure 16.7  Packed stuffing box (courtesy of Dean Brothers Pumps, Inc.).

have the mechanical seal installed at the pump factory, as the slightest amount of grit on the faces can cause permanent damage or destruction on only one or two revolutions at pump speed. The seals should be inspected and cleaned immediately prior to initial start-up. A mechanical seal system (Figures 16.8a [5] and b [6]) contains a rotating element attached to the rotating shaft by set screws (or a clamp) that turns against a stationary unit set in the gland housing. The necessary continuous contact between the seal faces (see Figure 16.8a) is maintained by hydraulic pressure in the pump from the fluid being pumped and by the mechanical loading with springs or bellows. To seal the mechanical seal elements to the rotating shaft to prevent leakage along the shaft, two basic types of seals are used: (a) pusher type using springs and seal “O” rings, wedge rings, and so on; and (b) non-pusher type using some form of bellows of elastomer or metal [7] (Table 16.5). The matching contact rubbing faces are made of dissimilar materials, precision finished to a mirror-like flat surface. There is little friction between these, and hence, they form a seal that is practically fluid tight. The rubbing materials may be some combination of low friction carbon, ceramics (aluminum oxide, silicon carbide), and/or tungsten.

340  Petroleum Refining Design and Applications Handbook Volume 2 Gland gasket

Flush connection

Driven pin

Gland ring

Stuffing-box housing

Pumped liquid

Shaft Primary seal elements

Mechanical-seal hardware

Secondary seals (a)

Figure 16.8a  Basic components of all mechanical seals (by permission from Adams, W. H. Chem. Eng., Feb. 7, 1983, p. 48). C L

C L Stuffing Box

Stuffing Box

(1) Impeller

Impeller

(1)

(2)

(3) C L

(3)

(2)

Shaft

Internal Seal

External Seal (b)

Figure 16.8b  The three sealing points in mechanical seals (by permission from Sniffen, T.G., Power and Fluids, Winter 1958, Worthington Corp.).

The choice of materials will depend on the service, as will the selection of the materials of construction for the other components, such as springs, “O” rings, other seal rings, and even the housing. The designer should consult the seal manufacturers for details of application not possible to include here. The “single” mechanical seal is made of a rotating element fixed to the shaft (or shaft sleeve), and a stationary element fixed to the pump casing [6]. The “double” seal is for severe sealing problems where out-leakage to the environment cannot be tolerated and must be controlled (Figures 16.9a and b). Depending upon the fluid’s characteristics, the vent between the double seals (Figures 16.9c and d) may be purged with process liquid, or a different liquid or oil, or it may be connected to a seal pot and vent collection to prevent leakage to the air/environment. There are techniques for testing for leakage of the inner seal by measuring the vent space pressure through the seal liquid surge port. This should be essentially atmospheric (depending on the vent system backpressure). This allows detection before the leakage breaks through the outer seal.

Pumps  341 Table 16.5  Requirements for mechanical seal installations. Feature

Description

Remarks

Cooling

Water jacketed stuffing box

Liquid must dead end in stuffing box

Cooling

Gland plate

Efficient to cool contact faces

Lubrication

Dead end

Good under vacuum, mild abrasives metal–metal, dry seals

Lubrication

Circulating

Good cooling of contact faces

Flushing

Inside seal

Good for volatile liquids, solutions tending to crystallize, steam

Flushing

Outside seal

Heating to prevent solidification

Quenching

Outside seals (only)

For oxidizing and corrosive liquids, seal liquid washes process fluid, for high temp.

Vent and drain

Inside seal

Safety feature, for venting to flare, draining

Flushing

Double

Requires circulation system

Flushing

Tandem

Requires circulation system

Two rotary

Double

For improved sealing

Four rotary

Double tandem

For improved sealing problem

Figure 16.10 illustrates a seal installed in a conventional stuffing box with cooling liquid flow path. Figures 16.8a, 16.8b, 16.8, to 16.12 identify the fundamentals of mechanical seals, even though there are many specific designs and details. These various designs are attempts to correct operational problems or seal weaknesses when used under various conditions in the wide variety of process fluids. The average unbalanced external seal is good for pressures of about 30 psig (2.1 barg), while the balanced design will handle 150 psig (10.3 barg). Special designs will handle much higher pressures. Actually the maximum operating process pressures are a function of the shaft speed and diameter for a given seal design fluid and fluid temperature. Figure 16.13 is an outside balanced seal designed for vacuum to 150 psig (10.3 barg) and −40°F to +400°F (−40 to 204°C) (see Table 16.5). The process fluid must be free of solids (as for practically all mechanical seals) and must not attack the material of the O-ring shaft packing. Many other designs are available, and the manufacturers should be consulted for advice on specific sealing problems.

16.4 Centrifugal Pump Selection The centrifugal pump is a versatile unit in the process plant, since its ease of control, non-pulsing flow; pressure-­ limiting operation fits many small and large flow systems [37].

Barrier Fluid In

Product Side

Atmosphere Side

Barrier Fluid In Product Side

Atmosphere Side A

(a)

B

A1

B2

(b)

Figure 16.9  (a) Double mechanical seal, two rotary elements against common stationary (by permission from Fischer, E. E., Chem. Process, Oct. 1983 [7]). (b) Tandem double seal (by permission from Fischer, E. E., Chem. Process, Oct. 1983 [24]).

342  Petroleum Refining Design and Applications Handbook Volume 2 PI

FLUSH

PI 3/8" 3/8" S.S. TUBING

PUMP END

PSV

DRIVE END

SHAFT

INNER SEAL

VIKING GEAR PUMP (1.5–2 GPM/ PROCESS PUMP)

OUTER SEAL

SEAL OIL TANK 25 GALLON (LOW MINERAL OR OTHER ACCEPTABLE LOW VISCOSITY OIL)

PUMP SEAL HOUSING

(c)

Figure 16.9  (c) Typical seal flush arrangement for double mechanical seals. PLANT VENT HEADER SYSTEM PI

½" SIGHT GLASS

½"

SEAL OIL SUPPLY TANK 2–3 GAL CAPACITY

FLUSH 3/8"

DISCHARGE PIPE FROM PUMP

½" ½" PUMPING RING IN SEAL

SHAFT

PUMP END

DRIVE END LOW PRESSURE SEAL (OUTSIDE)

INSIDE SEAL

PUMP SEAL HOUSING (d)

Figure 16.9  (d) Typical seal flush arrangement for tandem mechanical seals.

Pumps  343 SPRING HOLDER 11–13 CHROME SPRING–18-8 WORK HARDENED DRIVE COLLAR 11–13 CHROME

“U” CUP MOLDED HYCAR

ROTATING FACE MIN. CHROME 16% STATIONARY FACE-CARBON GLAND STUDS–18-8 AUXILIARY GLAND BRONZE ALL METAL SELF LOCKING NUTS

SHAFT SLEEVE 11–13 CHROME

SEAL COVER SAE 1020 CAD PLATED

DRIVE PINS–18-8

Figure 16.10  Typical single mechanical seal inside pump stuffing box (courtesy of Borg – Warner Co.). P = Pressure of Liquid in Box P' = Average Pressure Across Seal Faces

P P

P

B O

A CL

B

Shaft

Closing Force = P × Area “A” + Spring Loading Opening Force = P' × Area “B”

Figure 16.11  Area relationship for unbalanced seal construction (by permission from Sniffen, T. J., Power and Fluids, Winter 1958, Worthington Corp.). P = Pressure of Liquid in Box P' = Average Pressure Across Seal Faces

P P

P

B CL

B O

Shaft

Closing Force = P × (Area “A” – Area “C”) + Spring Loading Opening Force = P' × Area “B” “A”, “B” and “C” are Variable

Figure 16.12  Area relationship for balanced seal construction (by permission from Sniffen, T. J., Power and Fluids, Winter 1958, Worthington Corp.).

344  Petroleum Refining Design and Applications Handbook Volume 2

Figure 16.13  Single outside balanced seal (courtesy of Durametallic Corp.).

Generally, the centrifugal pump has these characteristics: 1. 2. 3. 4. 5. 6. 7.

 ide capacity, pressure, and fluid characteristics range. w easily adapted to direct motor, V-belt or other drive. relatively small ground area requirements. relatively low cost. difficult to obtain very low flows at moderate to high pressures. develops turbulent conditions in fluids. turbine type: (a) offers very high heads at low flows, (b) self-priming, (c) limited to very clean, non-abrasive fluids with limited physical properties, (d) clearances can be problem on assembly and maintenance.

Single-Stage (Single Impeller) Pumps This type of pump (Figures 16.14 and 16.15) is the workhorse of the chemical and petrochemical industries. It also serves important functions in petroleum refining and almost every industry handling fluids and slurries. Although the performance characteristics may vary for specific applications, the general fundamental features are the same especially for manufacturers who standardize to some extent through the Hydraulic Institute [8] and ANSI. Figure 16.16 indicates the relative relationship for three of the centrifugal type pumps, with curves labeled “centrifugal” referring to the usual process (open or enclosed impeller) type unit. A similar set of curves is shown in Figure 16.17 for the turbine unit. Note that the flat head curve of the centrifugal unit has advantages for many process systems, giving fairly constant head over a wide range of flow. For some systems where changes in flow must be reflected by pressure changes, the turbine characteristic is preferred. The centrifugal impeller provides an ever rising horsepower requirement with increasing flow, while the horsepower of the turbine pump falls off with increasing

Pumps  345 5

3 77A 7

17

14

15

76

25

SECTION A–A 29

77B

3 5 7 9 10 10K 13 14 15 17 18 25 25A

56

77

55

10 13 10K 18

Impeller Casing Back Head Cradle Bearing Housing Foot Shaft Sleeve Shaft Sleeve Key Stuffing Box Gland Stuffing Box Gland Stud Stuffing Box Gland Stud Nut Seal Cage Splash Collar Shaft Bearing—Radial Shaft Bearing—Thrust

80

26 28 29 55 56 75 76 76A 77 77A 77B 80 105 105A

26

9

25A 76A 105

75

28

105A

Bearing Housing Bearing End Cover Pump Shaft Oil Disc. (Flinger) Casing Foot Retaining Ring Oil Seal—Front Oil Seal—Rear Gasket—Casing Gasket—Sleeve Gasket—Drain Plug Oil Vent Shaft Adjusting Sleeve Sleeve Lock Nut

Figure 16.14  General service centrifugal pump (courtesy of Dean Brothers Pumps, Inc.).

flow (and decreasing head); hence it is “overloading” at low flows and must be operated with ample horsepower for these conditions. Figure 16.18 shows typical pump performance curves created by the manufacturer based on actual tests. The diagram illustrates the relationship between volumetric flow rate and total dynamic head, efficiency, required net positive suction head (NPSHR) and required power (i.e., brake horsepower, BHP). The effects of impeller shape for the usual centrifugal process pump performance are given in Figure 16.19. The only part the process designer can play is in the selection of a manufacturer’s performance curve to fit the control requirements of the system. If the curve is too steep, select an impeller of necessary basic characteristics to move the curve in the proper direction, providing the manufacturer has an impeller pattern to fit that pump casing, and with the improved physical dimensions. This may require changing the make of pump to obtain the necessary range and characteristic. For conditions of (1) high suction side (or inlet) friction loss, from suction piping calculations or (2) low NPSHA (10 ft (3 m) or less), a large open eye on the impeller inlet is necessary to keep the inlet velocity low. Net Positive

346  Petroleum Refining Design and Applications Handbook Volume 2 Heavy Duty Volute (150,300 lb. Steel and 125 lb. Cast Iron)

Confined Type Gasket Quench Type Gland (Optional Construction) Constant Level Oiler

Wear Rings (Hardened Materials Optional) Seal Lantern

Oil Breather Thrust Bearing; Ball Type Shaft; Alloy Steel Slinger; Labyrinth Type

Enclosed Type Impeller; Hydraulically Balanced for Reduced Thrust Load

Vent and Drain (Optional)

Oil Reservoir Radial Bearing; Ball Type Water Jacket Cools Oil Reservoir Slinger; Labyrinth Type

Shaft Sleeve (Optional Construction) Back Plate; Water Cooled Type, Extra Deep Stuffing Box

Figure 16.15  Cut-a-way section of single-stage pump, Part 1 (above) enclosed type impeller, Part 2 (lower left) open type impeller (courtesy of Peerless Pump Div. FMC Corp.).

Suction Head is discussed in a later section. The manufacturer should be given the conditions in order to properly appraise this situation. In most instances the manufacturer has a series of impellers to use in one standard casing size. The impeller may be trimmed to proper diameter to meet head requirements and yet stay within the power range of a specified driver. It is not necessary to place a full size impeller in a casing unless the system requires this performance. It is good to know when larger impellers can be placed in the casing, and what their anticipated performance might be in order to adequately plan for future uses and changing loads on the pump. Although the previous discussion has pertained to single impellers, the principles are the same for the multi-stage units (impellers in series in the casing) and the casing with double inlets. The latter pump is used for the higher flows, usually above 500 gpm (114 m3/h), and this design serves to balance the inlet liquid load as it enters the impeller, or first stage (if more than one) from two sides instead of one as in the single impeller. The double suction pump has the liquid passages as a part of the casing, with still only one external suction piping connection.

Pumps  347

C

M

Head, ft of Liquid B.H.P. Efficiency Head (ft liquid)

Efficiency

A

A

A = Axial M = Mixed C = Centrifugal

M C

Rating Point Brake Horsepower A M C

Gallons per minute

Figure 16.16  Comparison of impeller types for centrifugal pump performance (adapted by permission from Pic-a-Pump. Allis – Chalmers Mfg. Co.).

The axial and mixed flow impellers are used primarily for very high capacities at relatively low heads as shown in Table 16.2. They are usually applied to services such as water distribution to a large system, waste water disposal, recirculating large process liquor flows, and so on. Many applications can be handled either by a horizontal or a vertical pump. In the range usually associated with process plants and the associated services, Tables 16.6 and 16.7 are helpful guides in making the selection [9].

Pumps in Series Sometimes it is advantageous or economical to use two or more pumps in series (one pump into and through the other) to reach the desired discharge pressure. In this situation the capacity is limited by the smaller capacity of any one of the pumps (if they are different) at its speed of operation. The total discharge pressure of the last pump is the sum of the individual discharge pressures of the individual pumps. For identical pumps, the capacity is that of one pump, and the discharge pressure of the last pump is the sum of the individual heads of each pump acting as a single unit. Thus, for two identical pumps the discharge head is twice that of the rated pressure of one pump at the designated flow rate (Figure 16.20). The pump casing of each stage (particularly the last) must be of sufficient pressure rating to withstand the developed pressure. Consider two centrifugal pumps in series as shown in Figure 16.20a. The total head for the pump combination ∆hT is the sum of the total heads for the two pumps, i.e.

348  Petroleum Refining Design and Applications Handbook Volume 2

1,000

Eff

y

Capacity-head at 30 ft NPSH

600 Head in Feet

Efficiency - %

30

nc

icie

800

40

20

Brake Horsepower

50

Capacity-head at 9 ft NPSH 400

Capacity-head at 6 ft NPSH

He

ad

-C ap

15.0

ac

200

10

ity

Horsep ower (B HP)

10.0 5.0

0

0 10

15

20

25

30

35

40

45

Capacity - GPM

Figure 16.17  Performance of turbine type centrifugal pump (courtesy of Roy E. Roth Co.). 40 20 0

380 360

80

340

70

320

Efficiency, %

60

Head, ft

90

NPSHR, ft

NPSHR

Efficiency

Rated Flow Head

BEP

300

50

280

40

260

30

240

Allowable Operating Region Preferred Operating Region

150 Power, BHP

100

20

Power

50

10

0

0 0

100

200

300

400

500

600 700 800 Flowrate, U.S gal/min

900

1000

Figure 16.18  Characteristics of a centrifugal pump are described by the pump performance curves [36].

1100

1200

1300

Pumps  349 Enclosed impeller characteristics Wide impeller

Head

Narrow impeller

Capacity, gpm

Enclosed or open impeller characteristics Less wrap of vanes

More vanes B

Head

A

C More wrap of vanes less vanes (some wrap as B above)

Capacity, gpm

Figure 16.19  Impeller performance guide. Wrap refers to curvature of vanes on impeller (adapted by permission from Pic-a-Pump. Allis Chalmers Mfg. Co.).

Table 16.6  Pump selection guide. Feature

Horizontal

Vertical

Space requirements

Less head room

Less floor area, more head room.

NPSH

Requires more*

Requires less

Priming

Require*

Usually not required

Flexibility (relative to future changes)

Less

More

Maintenance

More accessible

Major work project

Corrosion and abrasion

No great problem

Can be considerable problem

Cost

Less

More (requires more alloy to handle corrosive fluid)

*For some conditions.

350  Petroleum Refining Design and Applications Handbook Volume 2 Table 16.7  Type selection based on liquid handled. Liquid

Basic pump type

Type impellers

Water and other clear noncorrosive liquids at cold or moderate temperatures.

Single or double suction.

Closed except for very small capacities.

Water above 250°F

Single or double suction. This is usually boiler feed service at high pressures requiring multi-stage pumps.

Closed except for very capacities

Hydrocarbons, hot

Single suction, often of the special type called refinery pumps, designed particularly for high temperature service.

Closed with large inlets.

Corrosives: Mild acid or alkaline

Single or double suction

Strongly acid or alkaline

Single or double suction with single suction probably less expensive if available for the rating.

Hot corrosives

Single suction, with many refinery pump types also used here because of high temperatures and corresponding suction pressures.

Water with solids in suspension:

Coarse abrasives

Pulpy solids such as paper stock

Closed except for very small capacities or where liquid tends to form scale on surfaces of moving parts.

Single suction with end clearance wearing fits. If all particles pass through 1/8" mesh screen, rubber lined pumps are available which will give many times the life of metal pumps, providing no chemical action or excessive temperature will deteriorate the rubber. Special rubber compounds can be applied to improve resistance to certain chemicals.

Open, which allows better application of the rubber, except in larger sizes. Also made in closed type.

Single suction, Not available for full range of ratings, that is, small capacities not too easily obtained. Often have very large impellers operated at slow speeds for use when solids larger than 1" diameter are the standard diet. This would be of the type called dredge pumps handling sizeable rocks.

Closed

Single suction. Double suction only used on very slight solids concentrations and then with special end clearance wearing fits.

Closed. Open type used to be standard but change to end clearance wearing fits made closed impellers better suited.

ΔhT = Δh1 + Δh2

(16.3)

The volumetric flow rate or capacity for the pump combination QT is the same as the capacity for each pump, i.e.

QT = Q1 + Q2

(16.4)

The operating characteristics for two pumps in series are obtained as follows [38]: 1. D  raw the ∆h against Q characteristic curves for each pump together with the system ∆hs against Qs curve on the same plot (Figure 16.20a).

Pumps  351 2. D  raw a vertical constant capacity line which intersects the two pump curves at total heads ∆h1 and ∆h2 respectively and the system curve at total head ∆hs. 3. Add the values of ∆h1 and ∆h2 obtained in Step 2 to give

ΔhT = Δh1 + Δh2

(16.3)

4. C  ompare ∆hT from Step 3 with ∆hs from Step 2. If they are not equal, then repeat Steps 2, 3, and 4 until ∆hT = ∆hs. This is the operating point of the two pumps in series. An alternative to the above trial and error procedure for two pumps in series is to calculate ∆hT from Eq. 16.3 for various values of the capacity from known values ∆h1 and ∆h2 at these capacities. The operating point for stable operation is at the intersection of the ∆hT against QT curve with the ∆h against Qs curve. The piping and valves may be arranged to enable two centrifugal pumps to be operated either in series or in parallel. For two identical pumps, series operation gives a total head of 2∆h at a capacity Q and parallel operations gives a capacity of 2Q at a total head ∆h. The efficiency of either the series or parallel combination is practically the same as for a single pump.

∆hT ∆h1

∆h2

QT QT

∆hT

∆hS Pump curve (1)

∆h

Pump curve (2)

∆h2 ∆h1 System curve

Q

Figure 16.20a  Operating point for centrifugal pumps in series [38].

QT

352  Petroleum Refining Design and Applications Handbook Volume 2 300

Two Pu

mp s in

S er

Note: Systems illustrated Assume Duplicate Pumps.

ies

240 S

2

R H2

Head in Feet

180

150

Two Pumps in Pa

P–R

120

rallel

P–R Sing le P um p

S R H1

60

Q1

0

50

Q2

100

150

200

Capacity, gpm Pump in Series:

Pump in Parallel:

Q = Constant H (Total) = H1 + H2 + ’’’ 2O = S-R denotes Series-Rating Point, Total = Constant Q (Total) = Q1 + Q2 + ”’ (at H for each Single Pumps Curve)  = P-R denotes Parallel-Rating Point 1O = Single pump rating

Figure 16.20b  Operating curves of two duplicate centrifugal pumps in series and parallel.

Pumps in Parallel Pumps are operated in parallel to divide the load between two (or more) smaller pumps rather than a single large one, or to provide additional capacity in a system on short notice, or for many other related reasons. Figure 16.20 illustrates the operational curve of two identical pumps in parallel, each pump handling one half the capacity at the system head conditions. In the parallel arrangement of two or more pumps of the same or different characteristic curves, the capacities of each pump are added, at the head of the system, to obtain the delivery flow of the pump system. Each pump does not have to carry the same flow; but it will operate on its own characteristic curve, and must deliver the required head. At a common tie point on the discharge of all the pumps, the head will be the same for each pump, regardless of its flow.

Pumps  353 The characteristic curves of each pump must be continuously rising (right to left) as shown for the single pump of Figure 16.20, otherwise with drooping or looped curves they may be two flow conditions for anyone head and the pumps would “hunt” back and forth with no means to become stabilized. Figures 16.21a–d represent typical and actual performance curves showing discharge total head (head pressure at pump outlet connection for any fluid), required minimum water horsepower (for pumping water), and capacity or pumping volume of the pump (for any fluid) for several impeller diameters that would fit the same case (housing). Additionally, the important NPSHR characteristics of the pump’s design, impeller entrance opening and diameter, and the hydraulic operating efficiency of the pump at the fixed designated speed of the performance curves are shown on the chart. All of this performance is for one specific impeller diameter of the fixed rotating speed (rpm), and the fixed impeller design pattern proprietary to the manufacturer (number, shape and spacing of vanes, and wrap or curvature of vanes). Note that Figure 16.21c plots the NPSHR curve for this “family” of impellers (different diameters, but exact same design dimensions and features), while Figure 16.21a shows the NPSHR numbers printed at selected points on the curve. Figure 16.21c illustrates the change in performance for the exact same pump, same impellers, but for different rotating speeds of 1750 and 3550 rpm. (Note that the respective motor designated standard speeds are 1800 and 3600 rpm, but the pump manufacturer cannot count on these speeds under load in order to provide performance information the customer needs for the design of a system). Consider two centrifugal pumps in parallel as shown in Figure 16.21d. The total head for the pump combination ∆hT is the same as the total head for each pump, i.e.

ΔhT = Δh1 = Δh2

(16.5)

Horsepower for Liquid of Sp gr = 1.0 200

10 hp 6 1/2" Impeller Diameters

Total Head in Feet (for any Liquid)

160

6"

Performance

4 7/8"

60

5 hp Curves

67 70

3 hp

5 1/2"

120

Efficiency Values

7 1/2 hp

71

2 hp

4 1/2"

80

67 N.P.S .H. Re qu (Any Liquid ired, Fee t ) Suctio n Lift , Fee (Max t imu on W m Limit, B ater a t 70° ased F

40

60

12 17

21

22

16

0 Pump Speed: 3,500 rpm Pump Size: 2" × 2" Maximum Impeller Diameter: 6" Minimum Impeller Diameter: 4 1/2"

0

20

40

60

11

80

100

120

140

160

Capacity for any Liquid, gpm

Figure 16.21a  Typical centrifugal pump curves (adapted by permission from Allis-Chalmers, Mfg. Co.).

180

200

220

Figure 16.21b  Typical performance curves showing NPSHR in convenient form (by permission from Crane Co. Deming Pump Div.).

354  Petroleum Refining Design and Applications Handbook Volume 2

Pumps  355

Figure 16.21c  Exact same pump casing and impellers at different shaft speeds (by permission from Goulds Pumps, Inc.).

356  Petroleum Refining Design and Applications Handbook Volume 2

∆hT Q1 QT

QT Q2

Pump curve (1) Pump curve (2) ∆hT

QS

∆hS

∆h

System curve

Q1

Q2

QT

Q

Figure 16.21d  Operating point for centrifugal pumps in parallel [38].

The volumetric flow rate or capacity for the pump combination QT is the sum of the capacities for the two pumps, i.e.

QT = Q1 + Q2

(16.6)

The operating characteristics for two pumps in parallel are obtained as follows [38]: 1. D  raw the ∆h against Q characteristic curves for each pump together with the system ∆hs against Qs curve on the same plot as shown in Figure 16.21d. 2. Draw a horizontal constant total head line which intersects the two pump curves at capacities Q1 and Q2 respectively, and the system curve at capacity Qs. 3. Add the values of Q1 and Q2 obtained in Step 2 to give

QT = Q1 + Q2

(16.6)

4. C  ompare QT from Step 3 with Qs from Step 2. If they are not equal, repeat Steps 2, 3, and 4 until QT = Qs. This is the operating point of the two pumps in parallel. An alternative to this trial and error procedure for two pumps in parallel is to calculate QT from Eq. 16.6 for various values of the total head from known values of Q1 and Q2 at these total heads. The operating point for stable operation is at the intersection of the ∆hT against QT curve with the ∆hs against Qs curve. Figures 16.22 and 16.23 show photos of a motor driven centrifugal pump for the pre-flashed crude in the crude distillation unit; a main distillation tower and a mild vacuum column with associated centrifugal pumps, piping, and accumulators, respectively.

Pumps  357

Figure 16.21e  Pump sizing calculation (SI units) for reflux centrifugal pump of Example 16.19.

358  Petroleum Refining Design and Applications Handbook Volume 2

Figure 16.22  Motor driven centrifugal pump for the pre-flashed crude in the crude distillation unit.

Figure 16.23  Main distillation tower and a mild vacuum column with associated centrifugal pumps, piping, and accumulators.

Pumps  359

16.5 Hydraulic Characteristics for Centrifugal Pumps Capacity: the rate of liquid or slurry flow through a pump. This is usually expressed as gallons per minute (gpm) or cubic meters per hour (m3/h) by pump manufacturers and design engineers in the chemical and refinery and petrochemical industries. A few convenient conversions are as follows: 1 Imperial gal/min    = 1.2005 US gpm 1 barrel (42 gal)/day = 0.0292 US gpm = 0.04167 m3/h 1 m3/day 1 l/h = 1 × 10−3 m3/h 1 l/s = 3.6 m3/h For proper selection and corresponding operation, a pump capacity must be identified with the actual pumping temperature of the liquid in order to determine the proper power requirements as well as the effects of viscosity. Figures 16.18 and 16.21a illustrate typical manufacturers’ performance curves for centrifugal pumps as a function of capacity. Pumps are normally selected to operate in the region of high efficiency, and particular attention should be given to avoiding the extreme right side of the characteristic curve where capacity and head may change abruptly. Total Head: the pressure available at the discharge of a pump as a result of the change of mechanical input energy into kinetic and potential energy. This represents the total energy given to the liquid by the pump. Head, previously known as total dynamic head, is expressed as feet (meters) of fluid being pumped. The total head read on the pump curve is the difference between the discharge head (the sum of the gauge reading on the discharge connection on the pump outlet, for most pumps corrected to the pump centerline, plus the velocity head at the point where the gauge is attached) and the suction head (the sum of the suction gauge reading corrected to the pump centerline and the velocity head at the point of attachment of the suction gauge) [10]. Note that the suction gauge reading may be positive or negative, and if negative, the discharge head minus a minus suction (termed lift) creates an additive condition (See Section 16.6). This is shown on the curves of Figure 16.21a. This head produced is independent of the fluid being pumped and is, therefore, the same for any fluid through the pump at a given speed of rotation and capacity. Through conversion, head may be expressed in units other than feet of fluid by taking the specific gravity of the fluid into account.



(Head in feet), h = (psi) (2.31 ft/psi)/SpGr, for any fluid

(16.7)

(Head in meters), h = (bar) (10.2 m/bar)/SpGr, for any fluid

(16.8)

In Metric units



Note that pounds per square inch (psi) is the pressure on the system and is not expressed as absolute unless the system is under absolute pressure. Feet (meters) are expressed as head, not head absolute or gauge (see Example 16.1). Note the conversion of psi pressure to feet of head pressure.



or, (head in ft), h = (psi) (144/ )

(16.9)

(head in m), h = (bar) (10200/ )

(16.10)

In Metric units,



360  Petroleum Refining Design and Applications Handbook Volume 2 where

= fluid density, lb/ft3(kg/m3) = 2.31 ft of water at SpGr = 1.0 1 lb/in. = 2.31 ft of water/SpGr of liquid = ft liquid 1 lb/in.2 1 in. mercury = 1.134 ft of water = 1.134/SpGr liquid   = foot liquid 1 bar = 10.2 m of water at SpGr = 1.0 2

For water, SpGr = 1.0 at 62°F (16.67°C), although for general use it can be considered 1.0 over a much wider range. For explanation of vacuum and atmospheric pressure see Chapter 15. The three main components illustrated in the example are (adapted [11]). 1. S tatic head 2. Pressure head 3. Friction in piping, entrance and exit head loss. The main influences on pump hydraulic efficiency are [43]: • • • •

Disc friction (secondary vortex between outer surface of impeller and casing). Surface roughness. Leakage (backflow from discharge through seating gaps) Mixing losses (flow direction changes).

These combine to reduce the hydraulic efficiency of the common centrifugal pump to typically 70–80% as the efficiencies result as heat. However, pump efficiencies exceeding 80% are possible by employing advanced manufacturing techniques, but these result in increased capital cost. Pumps produce pressure/head, and the consequence of head flow characteristic they produce higher pressures at low flow rates and to balance the hydraulics, the high discharge pressure is reduced across a control valve. This fitting wastes energy, and is better to employ a variable speed drive by matching speed to the required discharge pressure and thereby improving efficiency [43].

Example 16.1: Liquid Heads If a pump were required to deliver 50 psig (3.45 barg) to a system, for water, the feet (m) of head on the pump curve must read, 2.31 (50) = 115.5 ft In metric units 10.2 (3.45) = 35.19 m For a liquid of SpGr 1.3, the feet (m) of head on the pump curve must read, 115.5/1.3 = 88.8 ft of liquid. In metric units The head on the pump is 35.19/1.3 = 27.07 m of liquid For liquid of SpGr 0.86, the feet (m) of head on the pump curve must read, 115.5/0.86 = 134.2 ft of liquid. In Metric units The head on the pump is 35.19/0.86 = 40.92 m of liquid

Pumps  361 If a pump were initially selected to handle a liquid where SpGr = 1.3 at 88.8 ft (27.07 m), a substitution of light hydrocarbon where SpGr = 0.86 would mean that the head of liquid developed by the pump would still be 88.8 feet, but the pressure of this lighter liquid would only be 88.8/[(2.31)/(0.86)] or 33.06 psi. In Metric units, the pressure would be 27.07/[(10.2)/(0.86)] or 2.3 bar Note that for such a change in service, the impeller seal rings, packing (or mechanical seal) and pressure rating of casing must be evaluated to ensure proper operation with a very volatile fluid. For other examples, see Figures 16.24a and 24b. The total head developed by a pump is composed of the difference between the static pressure and velocity heads plus the friction entrance and exit head losses for the suction and discharge sides of the pump (Figures 16.25 and 16.26).



H = hd − hs

(16.11)

The sign of hs when a suction lift is concerned is negative, making H = hd − (−hs) = hd + hs. A pump is acted on by the total forces, one on the suction (inlet) side, and the other on the discharge side. By subtracting (algebraically) all the suction side forces from the discharge side forces, the result is the net force that the pump must work against. However, it is extremely important to recognize the algebraic sign of the suction side components, that is; if the level of liquid to be lifted into the pump is below the pump centerline, its algebraic sign is negative (−). Likewise, if there is a negative pressure or vacuum on the liquid below the pump centerline, then this works against the pump and it becomes a negative (−). (See discussion to follow.)

c) Butane sp gr = 0.6 b) Naphtha sp gr = 0.8

a) For water, sp gr = 1.0

166.7' d) Carbon tetrachloride sp gr = 1.50

125'

100' 66.6'

a) 43.3 psig

b) 43.3 psig

c) 43.3 psig

d) 43.3 psig

Pressure gauge attached at the bottom

Figure 16.24a  Comparison of columns of various liquids to register 43.3 psig on pressure gauge at bottom of column.

362  Petroleum Refining Design and Applications Handbook Volume 2 c) Butane sp gr = 0.6 b) Naphtha sp gr = 0.8

a) For water, sp gr = 1.0

50.8 m d) Carbon tetrachloride sp gr = 1.50 38.1 m

30.48 m 20.3 m

a) 3.0 barg

b) 3.0 barg

d) 3.0 barg

c) 3.0 barg

Pressure gauge attached at the bottom

Figure 16.24b  Comparison of columns of various liquids to register 3.0 barg on pressure gauge at bottom of column.

D'

Total static head

Liquid Exit loss

Atmospheric pressure

Suction head

Discharge head

Suction static head

Liquid

Discharge static head

D

Note: Suction: hS = S – hSL hSL = Pipe, fittings and other friction losses Discharge: hd = D + hdL

S

Entrance loss

Discharge piping

Note: Sw = Worst condition to empty this tank, ft

Sw Centerline pump

Suction piping Pump

Figure 16.25  Suction head system.

hdL = Pipe, fittings and other friction losses

Pumps  363 Exit loss D' Suction Discharge lift head Liquid

Total static head

Valve

Discharge static head

Exchanger

D

S

SL (Worst case) = SL + S1

Suction static lift

Centerline of pump Pump SL

S1

Entrance loss Liquid

Note: *Suction: h = –S – h S L SL hSL = Pipe, fitting, valves, exchanger, and other friction losses –hS = –SL + hSL **Discharge: h = D + h d dL

hdL = Pipe, fitting, valves, exchanger, and other friction losses *Suction: Worst case = S (substitute in L above) **Discharge: Worst case use = (D + D')

Figure 16.26  Suction lift system.

Static Head This is the overall height to which the liquid must be raised. For Figure 16.27a Discharge static head: H Suction static head: L (actually −L) Total system static head: H + L;



actually H − (−L)

(16.12)

H

L

Figure 16.27a  Static head, overall = H + L (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

364  Petroleum Refining Design and Applications Handbook Volume 2

H

S

Figure 16.27b  Static head, overall = H – S (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

For Figure 16.27b Discharge static head: H (from centerline of pump) Suction static head: S, (actually +S)



Total system static head: H − S; or H − (+S)

(16.13)

Pressure Head For Figure 16.27c Discharge pressure head = 100 psig Suction pressure head = 0 psig Total pressure head = 100 − (+0) = 100 psig = 100 2.31 ft/psi/SpGrH2O=1 * = 231 ft of water Note: The totals are differentials and neither gauge nor absolute values.

(

)

*Applies to water only. For the other fluids use appropriate specific gravity conversion. For Figure 16.27d Discharge pressure head = 100 psig Suction pressure head = +50 psig (=64.7 psia) Total pressure head = 100 (+50) = 50 psi not gauge or absolute = 50 2.31 ft/psi/SpGrH2O=1 = 115.5 ft of water

(

)

Atmosphere

100* GA.

The above examples purposely disregarded pressure head, friction, entrance, and exit losses.

Figure 16.27c  Pressure head (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

Pumps  365 100* GA. ABS

100* GA.

Figure 16.27d  Pressure head, positive suction (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

100* GA.

50

10 50* GA.

Figure 16.27e  Pressure head with negative suction (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

Note that both the discharge and suction pressures must be on the same base/units. These illustrations are for static head only, while overall the pump has to work against the static and the pressure heads (discussed in Section 16.5). For Figure 16.27e Discharge pressure head = 100 psig = 100 2.31 ft/psi/SpGrH2O=1   = 231 ft water (system fluid) Discharge static head = 50 ft Total discharge head = 231 + 50 = 281 ft

(

)

(*Note that no flow friction losses or entrance/exit losses are included in this example) Suction pressure head   = +50 psig = 50 2.31 ft/psi/SpGrH2O=1           = + 115.5 ft water (system fluid) Suction static head = −10 ft *Total suction head = +115.5 + (−10) = +105.5 ft *Total head on pump = 281 − 105.5 = 175.5 ft fluid

(

)

Friction Losses Due to Flow Friction, Entrance and Exit Heads, Valve Losses. These losses and calculation methods were presented in Chapter 15. Comments here will be limited. These losses are a function of the characteristics of the fluid flowing in the piping systems and the velocities of flow. Entrance and exit losses relate to the pipe and not the suction or discharge

366  Petroleum Refining Design and Applications Handbook Volume 2 connections at the pump. Usually they are very small, but cannot be ignored without checking. Velocity heads at the pump connections are considered internal losses. These are handled by the manufacturer’s design of the pump and are not considered with the external losses in establishing the pump heads.

Example 16.2: Illustrating Static, Pressure, and Friction Effects Refer to Figure 16.27f for basis of the example. 8" Check Valve 26* GA.

8" Gate Valve

60'

141'

10' of 10" pipe

of 8" Pipe

1500 GPM Capacity

10'

Figure 16.27f  Pumping arrangement for Example 5-2 (adapted by permission, Centrifugal Pumps Fundamentals, Ingersoll-Rand Co., Washington, N.J. 07882).

To aid in speed of computation, the friction figures are taken from the Cameron Hydraulic Tables in Chapter 15 and water, which is suited to these tables, is used as an example fluid. Discharge head = 60 ft Discharge pressure head = 26 psig     = 26(2.31 ft/psi/SpGr) = 60 ft gauge Discharge friction and exit head (at pipe/tank): 140 ft of 8-in. pipe: 6.32 ft/100(140) 3 8-in. 90° ell: (6.32/100) (3) (20.2) 1 8-in. gate valve 1 8-in. check valve *Exit loss: Assume 8-in. pipe

= 8.8 ft = 3.8 ft = 0.3 ft = 3.3 ft = velocity head = 1.4 ft

Subtotal, ft = 17.6 ft Total discharge head = 137.6 ft Suction static head (lift) = −10.0 ft Suction pressure head 0, psig (atm) = 0.0 Suction friction and entrance head: 10 ft of 10-in. pipe, (2.1 ft/100) (10) = 0.2 ft 1 10-in. suction 90° ell;(2.1/100) (25.3) = 0.5 ft *Entrance loss: 10-in. pipe assume = velocity head = 0.6 ft

Pumps  367 Subtotal = −1.3 ft Total suction head = 10 + (−1.3) = 11.3 ft Total pump head = 137.6 − (−11.3) = 148.9 ft *These are not velocity heads at pump connections, but are related to the piping connections. See earlier note in this regard.

16.6 Suction Head or Suction Lift, hs The total suction head, Figure 16.28, is the difference in elevation between the liquid on the pump suction side and the centerline of the pump (plus the velocity head). Note that the suction head is positive when above the pump centerline and that it decreased with an increase in friction losses through the suction piping system. Thus,



Total suction head (TSH) = static head −hSL

(16.14)

The total suction lift is defined as above except the level of the liquid is below the centerline of the pump or the head is below atmospheric pressure. Its sign is negative.



Total Suction Lift (TSL) = static lift plus friction head losses

In summary: 1. Th  e pressure units (gauge or absolute) must be consistent for all components used in determining both suction side and discharge side conditions. Most designers use gauge as a reference, but this is not necessary.

P

SW

S

Pump

S P

Pump

hs = S – hSL + P (a)

hs = – S – hSL + P (b) Note: When P is expressed in absolute pressure units, hs will be in absolute units. If P is less than atmospheric pressure: P is (–) if expressed as a gauge reading and will be a negative feet of liquid. P is (+) if expressed in absolute units. The friction loss hSL includes any entrance or exit losses and other such fittings in the system.

Figure 16.28  Typical suction systems (adapted by permission, Carter, R. and Karassik, “R.P.-477.” Worthington Corp.).

368  Petroleum Refining Design and Applications Handbook Volume 2 2. S tatic head is positive pressure of fluid on pump suction above its centerline (S), (+). 3. Positive external pressure, P, on the surface of fluid on pump suction is used as a positive integer, expressed as feet (meters) of fluid, (+). 4. Partial vacuum, P, on the surface of liquid is a negative pressure. As a partial vacuum expressed as a gauge reading as feet (mm) of liquid below atmospheric, the pressure is negative and would be designated by a minus (−) sign. A partial vacuum, P, expressed as absolute vacuum or absolute pressure would be designated by a positive (+) sign. It is essential to be consistent for all pressure units. If absolute units are used, the total suction head would be in absolute units and the discharge head must be calculated in absolute units. 5. Suction lift is a negative suction head, S, used to designate a negative static condition on the suction of the pump (below atmospheric). The sign for suction head is positive (+), while its corresponding terminology of suction lift is negative (−), since the term “lift” denotes a negative condition. Note that the only difference in these terms is the difference in signs. This applies because the total head for a pump is total discharge head a(+), minus (−) the [suction head, a(+)], or [suction lift, a(−)]. For general service the average centrifugal pump should lift about 15 feet (5 m) of water on its suction side. However, since each process situation is different, it is not sufficient to assume that a particular pump will perform the needed suction lift. Actually, certain styles or models of a manufacturer’s pumps are often specially adapted to high lift conditions. On the other hand it is unnecessary to select a high lift pump when pressure head or flooded suction conditions prevail. Proper evaluation of suction lift conditions cannot be over emphasized. The theoretical maximum suction lift at sea level for water (14.7 psi) (2.31 ft/psi/SpGr) = 34 ft. However, due to flow resistance, this value is never attainable. For safety, 15 ft. (5 m) is considered the practical limit, although some pumps will lift somewhat higher columns of water. When sealing a vacuum condition above a pump, or the pump pumps from a vessel, a seal allowance to atmosphere is almost always taken as 34 ft. of water. High suction lift causes a reduction in pump capacity, noisy operation due to release of air and vapor bubbles, vibration and erosion, or pitting (cavitation) of the impeller and some parts of the casing. (The extent of the damage depends on the materials of construction.) (EL) Atmospheric Pressure

(EL)

Entrance Loss (EL) D

D

C Pump

D

C

C

Pump

Pump

hd = D + hdL + P

hd = D + hdL

hd = D + hdL

(a)

(b)

(c)

Note: For a system evaluation, icluding suction and discharge, the units of P must be the same either gage or absolute, expressed as feet of fluid. The friction losses from the pump to the vessel include any entrance or exit losses. Unless velocities are high, these losses are usually negligible.

Figure 16.29  Typical discharge systems.

Pumps  369

16.7 Discharge Head, hd The discharge head of a pump is the head measured at the discharge nozzle (gauge or absolute), and is composed of the same basic factors previously summarized: 1. S tatic head. 2. Friction losses through pipe, fittings, contractions, expansions, entrances, and exits. 3. Terminal system pressure. Some typical discharge systems are given in Figure 16.29. General practice is to express the terminal discharge pressure, P, at a vessel as in Figure 16.29 in terms of gauge pressure, and hence P = 0 for atmospheric discharge. If P is less than atmospheric or otherwise expressed in absolute units, then it must be added as equivalent feet (meters) of liquid to the value of hd ordinarily expressed as a gauge reading. Figures 16.25 and 16.26 illustrate the use of siphon action in pump systems. Theoretically, the head in the siphon should be recoverable, but actually it may not, at least not equivalent foot for foot. Usually not more than 20 ft. (60 m) of siphon action can be included [12] even though 34 ft. (10 m) are theoretical at sea level. The siphon length is D in the figures [13]. For some systems, the discharge head on the pump should be used as (D + D ), neglecting the siphon action. In any case, if air can be trapped in the loop, (and it usually can) it must be vented during start-up, otherwise the pump will be pumping against the head established using (D + D ). On start-up the flow can be gradually increased, making more head available from the pump to overcome the higher starting head of the system. This should not be overlooked nor underestimated in determining the specifications for the pump.

16.8 Velocity Head Velocity head is the kinetic energy of a liquid as a result of its motion at some velocity, v. It is the equivalent head in feet (meter) through which water would have to fall to acquire the same velocity.

hv= v2/2 g, ft.(m) of fluid

(16.15)

where hv = velocity head, ft (m) v = liquid velocity, ft/s (m/s) g = acceleration of gravity, 32.2 ft/s2 (9.81 m/s2) As a component of both suction and discharge heads, velocity head is determined at the pump suction or discharge flanges respectively, and added to the gauge reading. The actual pressure head at any point is the sum of the gauge reading plus the velocity head, the latter not being read on the gauge since it is a kinetic energy function as contrasted to the measured potential energy. The values are usually (but not always) negligible. Present practice is that these velocity head effects at the pump suction and discharge connections are to be included in the pump performance curve and pump design, and need not be actually added to the heads calculated external to the pump itself [11]. It is important to verify the effects of velocity head on the suction and discharge calculations for pump selection. In general, velocity head (kinetic energy) is smaller for high head pumps than for low head units. Sometimes the accuracy of all the other system calculations does not warrant concern, but for detailed or close calculations velocity head should be recognized. The actual suction or discharge head of a pump is the sum of the gauge reading from a pressure gauge at the suction or discharge and the velocity heads calculated at the respective points of gauge measurement. Regardless of their density, all liquid particles moving at the same velocity in a pipe have the same velocity head [14]. The velocity head may vary across a medium to large diameter pipe. However, the average velocity of flow (i.e., dividing the total flow as ft3/s (m3/s) by the cross-sectional area of the pipe) is usually accurate enough for most design purposes.

370  Petroleum Refining Design and Applications Handbook Volume 2 Using the example of Karassik and Carter [10], for a pump handling 1500 gpm, having a 6-in. discharge connection and 8-in. suction connection, the discharge velocity head is 4.5 ft and the suction is 1.4 ft, calculated as shown above. If the suction gauge showed 8.6 ft, the true head would be 8.6 + 1.4 = 10.0 ft. If the discharge head showed 105.5 ft head, the true total head would be 105.5 + 4.5 = 110.0 ft, less (8.6 + 1.4) or 100 ft. The net true total head would be 110 ft − 10ft = 100.0 ft. Looking only at the gauge readings, the difference would be 105.5 − 8.6 = 96.9 ft, giving an error of 3.1% of the total head. As an alternate example, if the discharge head were 45.5 ft, then the true total head = (45.5 + 4.5) − (8.6 + 1.4) = 40 ft, and the difference in gauge readings would be 45.5 − 8.6 = 36.9 ft, or an error of 7.8%. Most designers ignore the effects of velocity head, but the above brief examples emphasize that the effect varies depending on the situation and the degree of accuracy desired for the head determinations.

16.9 Friction The friction losses for fluid flow in pipe valves and fittings are determined as presented in Chapter 15. Entrance and exit losses must be considered in these determinations, but are not to be determined for the pump entrance or discharge connections into the casing.

16.10 Net Positive Suction Head (NPSH) and Pump Suction

Discharge

A pump is designed to handle liquid and not vapor. However, there are many instances where vapor easily gets into the pump if the design is not carefully done. As the fluid moves through the pump, pressure losses occur as shown in Figure 16.30, in the inlet passage (Point A to Point B), due to internal frictional (Point B to Point C), and at the blade and within the impeller (Point C to Point D). If the static pressure drops below the fluid’s vapor pressure, the fluid begins to boil, creating vapor bubbles and reducing the density of the fluid. When this occurs, the differential pressure created by the dynamic head of the

Impeller Eye

D

C

B

Suction

A

Volute Impeller

Figure 16.30  Static pressure losses occur as the fluid travels into the pump suction and moves in and out of the impeller [24].

Pumps  371 impeller decreases (Eq. 16.2). The lowest pressure occurs right at the impeller inlet where a sharp pressure dip occurs. The impeller rapidly builds up the pressure, which collapses vapor bubbles, causing cavitation and damage. Furthermore, if fluid enters a pump at its bubble point, it will start vaporizing inside the pump. The formation of these bubbles in the area of the impeller accounts for the noise associated with cavitation. The conversion of the pump’s suction pressure to velocity in the eye of the impeller is known as the required net positive suction head (NPSHR). This is the head of liquid that must exist at the edge of the inlet vanes of an impeller to allow liquid transport without causing undue vaporization. NPHSR is a function of impeller geometry and size, and is determined by factory testing. The NPSHR of an impeller can range from a few feet to a three-digit number. Figure 16.31 shows that as the flow-control valve on the discharge of the pump is opened, the velocity of liquid in the eye of the impeller rises. More of the pump’s suction pressure, or feet (meters) of head is converted to velocity or 1  kinetic energy  mv 2  . This means that the NPSHR of a pump increases as the volumetric flow through the pump 2  increases [27].

The NPSHR of a pump is due primarily to the conversion of feet (meters) of head to velocity in the eye of the impeller. The NPSHA to a pump has the definition: Physical pressure pump at suction minus vapor pressure of liquid at pump suction. When the NPSHR of a pump equals the NPSHA to the pump, the pump will cavitate or slip. Figure 16.31 shows the liquid in the vessel is equilibrium with the vapor leaving the drum. This means that the liquid is at its bubble point pressure and the vapor is at its dew point temperature. The vapor pressure of the liquid is 10 psig (24.7 psia). The physical pressure at the suction of the pump is 15 psig (29.7 psia). Therefore, the physical pressure at the suction of the pump is 5 psia. Therefore, the NPSHA is 20 ft. (2.31 × 5/0.58). This matches the level of liquid in the drum above the suction line of the pump and equals the NPSHA. The NPSHR of the pump may be determined from Figure 16.32 (regardless of the specific gravity of the liquid being pumped). At 250 gpm, the NPSHR

Vapor and liquid P

Vapor 140°F

10 psig

Bubble-point liquid

P

20 ft

P 15 psig (s.g. = 0.58)

Figure 16.31  NPSHA equals 20 ft [27].

372  Petroleum Refining Design and Applications Handbook Volume 2

25 ft

20 ft

15 ft

Required net positive suction head

10 ft

5 ft

50

100

150

200

250

300

GPM

Figure 16.32  NPSHR increases with flow [27].

of 20 ft will equal the NPSHA of 20ft. Therefore, at a flow rate of 250 gpm, the pump will cavitate. This calculation neglects the frictional losses in the suction line, which should be subtracted from the NPSHA. At 300 gpm, if the flow control valve is opened, the flow will momentarily increase, but shortly afterwards; the flow will become erratically low as the pump begins to cavitate. This is because an additional 6 ft. of NPSH is required to increase the flow from 250 to 300 gpm (Figure 16.31). A way of achieving this extra suction pressure or NPSH is to raise the liquid level in the drum. For example, with SpGr = 0.58, with very 4 ft rise in the level in the drum, the suction pressure will increase by 1 psi (4 * 0.58/2.31) and the NPSHA will increase by 4ft. But the drum is almost full as shown in Figure 16.29. A way of remedying this is to cool the liquid by 5oF after it leaves the drum. The cooled liquid is not in equilibrium with the vapor in the drum. It has been subcooled by 5°F; this indicates that the bubble point liquid has been cooled without altering its composition. The vapor pressure of the liquid has been reduced as shown in Figure 16.33; and subcooling by 5°F reduces its vapor pressure by 2 psi. This is equivalent to an increase in the NPSH by 8 ft (with the same specific gravity of 0.58). However, as the objective is to increase the flow from 250 to 300 gpm, Figure 16.30 indicates that the NPSHR increases from 20 to 26 ft. But as the liquid is subcooled by 5°F, the NPSHA increases from 20 to 28 ft. This exceeds the NPSHR by 2 ft, and the flow can be increased without the risk of pump cavitation. Insufficient NPSH can also result in pump cavitation. This occurs when the vapor bubbles that have formed in low static pressure areas move along the impeller vanes into higher-pressure areas and rapidly collapse. The forces produced by these bubbles as, they implode to erode the impeller vane surfaces, causing progressive pitting damage as shown in Figure 16.34. Cavitation is associated with distinct crackling noise that resembles the sound of a fluid starting to boil. Note that at a 3% head loss, cavitation has already begun. This must be avoided by maintaining sufficient net positive suction head (NPSH) as specified by the manufacturer. API 610 defines Net Positive Suction Head required (NPSHR) as the amount of suction head needed to limit head loss at the first stage of the pump to 3% (using water as the test fluid). Although hydrocarbons generally require less NPSH than water, reduction factors for hydrocarbons are not allowed by API. Net positive suction head (in feet/meters of liquid absolute) above the vapor pressure of the liquid at the pumping temperature is the absolute pressure available at the pump suction flange, and is a very important consideration in selecting a pump which might handle liquids at or near their boiling points, or liquids at high vapor pressures.

Pumps  373

25

23

Vapor pressure, psia

Vap

21

e sur

res

p or

19

17

120°F

125°F

130°F

135°F

140°F

Temperature, °F

Figure 16.33  Subcooling increases NPSHA [27].

Le ad

ing

Ed

ge

of

Va n

e

Cavitation Damage

(a)

(b)

Figure 16.34  (a) Cavitation damage has occurred on an impeller and (b) erosion–corrosion of an impeller.

Do not confuse NPSH with suction head, as suction head refers to pressure above atmospheric [8]. If this consideration of NPSH is ignored the pump may well be inoperative in the system, or it may be on the border-line and become troublesome or cavitating. The significance of NPSH is to ensure sufficient head of liquid at the entrance of the pump impeller to overcome the internal flow losses of the pump. This allows the pump impeller to operate with a full “bite” of liquid essentially free of flashing bubbles of vapor due to boiling action of the fluid.

374  Petroleum Refining Design and Applications Handbook Volume 2 The pressure at any point in the suction line must never be reduced to the vapor pressure of the liquid (see Eqs. 16.14 and 16.15). Both the suction head and the vapor pressure must be expressed in ft (m) of the liquid, and as gauge pressure or absolute pressure. Centrifugal pumps cannot pump any quantity of vapor, except possibly some vapor entrained or absorbed in the liquid. The liquid or its gases must not vaporize in the eye/entrance of the impeller. (This is the lowest pressure location in the impeller.) For low available NPSH (less than 10 ft or 3 m) the pump suction connection and impeller eye may be considerably oversized when compared to a pump not required to handle fluid under these conditions. Poor suction condition due to inadequate NPSHA is one major contribution to cavitation in pump impellers, and this is a condition at which the pump cannot operate for very long without physical erosion damage to the impeller [14, 15]. Cavitation of a centrifugal pump, or any pump, develops when there is insufficient NPSH for the liquid to flow into the inlet of the pump, allowing flashing or bubble formation in the suction system and entrance to the pump. Each pump design or “family” of dimensional features related to the inlet and impeller eye area and entrance pattern requires a specific minimum value of NPSH to operate satisfactorily without flashing, cavitating, and loss of suction flow. Under cavitating conditions, a pump will perform below its head-performance curve at any particular flow rate. Although the pump may operate under cavitation conditions, it will often be noisy because of collapsing vapor bubbles and severe pitting, and erosion of the impeller often results. This damage can become so severe as to completely destroy the impeller and create excessive clearances in the casing (Figure 16.34). To avoid these problems, the following are a few situations to watch. 1. H  ave NPSHA available at least 2 ft (0.6 m) of liquid greater than the pump manufacturer requires under the worst possible operating conditions (see Figures 16.22a–c) with pump curve values for NPSH expressed as feet (meter) of liquid handled. These are the pump’s minimum NPSHR. The pump’s piping and physical external system provide the NPSHA.

NPSHA must be greater than NPSHR

(16.16)

2. 3. 4. 5. 6.

I nternal clearance wear inside pump. Plugs in suction piping system (screens, nozzles, etc.). Entrained gas (non-condensable). Deviations or fluctuations in suction side pressures, temperatures (increase), low liquid level. Piping layout on suction, particularly tee-intersections, globe valves, baffles, long lines with numerous elbows. 7. Liquid vortexing in suction vessel, thus creating gas entrainment into suction piping. Figure 16.35 suggests a common method to eliminate suction vortexing. Since the forces involved are severe in vortexing, the vortex breaker must be of sturdy construction and firmly anchored to the vessel. 8. Nozzle size on liquid containing vessel may create severe problems if inadequate. Liquid suction velocities, in general, are held to 3 6.5 ft/s (0.9 2.0 m/s). Nozzle losses are important to recognize by identifying the exit design style (See chapter 15). Usually, as a guide, the suction line is at least one pipe size larger than the pump suction nozzle. The NPSHA available from or in the liquid system on the suction side of a pump is expressed (corrected to pump centerline) as:





(

)

NPSH A = p′a − p′vp ± S +

v s2 − h SL 2g

 2.31 ft /psi  v s2 NPSH A = (Pa − Pvp ) ± S + − h SL 2g  SpGr 

(16.17)

(16.18)

Pumps  375

Air/Vapor (non-condensed) entrained

Desired Liquid Level

Liquid Level Control Actual Liquid Flow Pattern

To Pump Suction

Note: (a) Dimension, “h”, min. of 5" to “h” = 1.25 x nozzle Dia.

(b) Dimension “L” approx. 3.5 to 5 times nozzle Dia.

Clearance, 2" min. to usual 4–6", except large nozzles require more clearance.

h L

(c) Bottom of vortex breaker may be attached to bottom or raised up 2" to 4". Vortex “cross” must be sturdy, welded of heavy plate (not light sheet metal). Vortex breaker must not restrict liquid flow into nozzle opening, but prevent swirling of liquid.

Figure 16.35  Liquid vortex in vessel and suggested design of vortex breaker.

With commonly used suction pipe diameters, the velocity head may be negligible, and the frictional head loss at the suction, hSL can be expressed in terms of velocity head loss by:



h SL = K

v2 2g

(16.19)

376  Petroleum Refining Design and Applications Handbook Volume 2 where

v=

Q

( πd 4 ) 2



(16.20)

and 2

K Q  h SL =  2  2g  πd 4 



(16.21)

2



 2.31 ft psi  v s2 K  Q  NPSH A = (Pa − Pvp ) ±S+ −  2  2g 2g  πd  SpGr  d 4

(16.22)

 10.2 m bar  v 2s NPSH A = (Pa − Pvp ) ± S + − h SL 2g  SpGr 

(16.23)

In Metric units

or

2



 10.2 m bar  v 2s K  Q  NPSH A = (Pa − Pvp ) ± S + − 2g 2g  πd 2 4   SpGr 

(16.24)

where p′a or Pa represents the absolute pressure in the vessel (or atmospheric) on the liquid surface on the suction side of the pump. p′vp or Pvp represents the absolute vapor pressure of the liquid at the pumping temperature. hSL is the suction line, valve, fitting, and other friction losses from the suction vessel to the pump suction flange. S may be (+) or (−) depending on whether static head or static lift is involved in the system. Figure 16.36 shows a typical relationship between the NPSHA in the system and the NPSHR by the pump as the volumetric flow rate of liquid or capacity Q is varied. The NPSHR by a centrifugal pump increases approximately with the square of the liquid throughput. Eqs. 16.22 and 16.24 show that the NPSHA in a system decreases as the liquid throughput increases because of the greater frictional head losses. A centrifugal pump will operate normally at a point on its total head against capacity characteristic curve until the NPSHA falls below the NPSHR curve. Beyond this point, the total head generated by a centrifugal pump falls drastically as illustrated in Figure 16.37 as the pump begins to operate in cavitation conditions. In centrifugal pump systems, a throttling valve is located on the discharge side of the pump. When this valve is throttled, the system ∆h against Q curve is altered to incorporate the increased frictional head loss. The effect of throttling is shown in Figure 16.38. Throttling can be used to decrease cavitation. A flow regulating valve or other constriction must not be placed on the suction side of the pump. This available value of NPSHA (of the system) must always be greater by a minimum of 2 ft (610 mm) and preferably three or more feet than the NPSHR stated by the pump manufacturer or shown on the pump curves in order to

Pumps  377

NPSH

Available NPSH in the system

NPSH required by the pump

Q

Figure 16.36  NPSHA and NPSHR vs. capacity in a pumping system [37].

∆h

Normal pump curve for adequate suction condition

Normal operating point System curve Pump curve for insufficient available NPSH

Q

Figure 16.37  Effect of insufficient NPSH on the performance of a centrifugal pump [37].

378  Petroleum Refining Design and Applications Handbook Volume 2

Pump curve

∆h

Operating point with throttling

System curve with throttling Normal operating point

Normal system curve

Q

Figure 16.38  Effect of throttling the discharge valve on the operating point of a centrifugal pump [37].

overcome the pump’s internal hydraulic loss and the point of lowest pressure in the eye of the impeller. The NPSHR by the pump is a function of the physical dimensions of casing, speed, specific speed, and type of impeller, and must be satisfied for proper pump performance. The pump manufacturers must always be given complete suction conditions if they are expected to recommend a pump to give long and trouble-free service. As the altitude of an installation increases above sea level, the barometric pressure, and hence p′a s or Pa decreases for any open vessel condition. This decreases the NPSHA. Figures 16.18 and 16.21 are present typical manufacturer’s performance curve. The values of NPSHR given are the minimum values required at the pump suction. As mentioned, good practice requires that the NPSHA available be at least 2 ft. (610 mm) of liquid above these values. It is important to recognize that the NPSHR and suction lift values are for handling water at about 70°F (21.1°C). To use with other liquids it is necessary to convert to the equivalent water suction lift at 70°F (21.1°C) and sea level. Total Suction Lift (as water at 70°F) = NPSHA (calculated for fluid system) −33 ft. The vapor pressure of water at 70°F is 0.36 psia.

16.11 General Suction System The suction system piping should be kept as simple as reasonably possible and adequately sized. Usually, the suction pipe should be larger than the pump suction nozzle. Furthermore, the suction system must maintain the pressure above the vapor pressure at all points. Usually, possible points of intermediate low pressure occur in the area of the vessel (drawoff) nozzle. Kern [26] provides some good rules of thumb on this. 1. Th  e minimum liquid head above the drawoff nozzle must be greater than the nozzle exit resistance. Based on a safety factor of 4 and a velocity head “K” factor of 0.5:

Pumps  379

hL =



2u 2 2g

(16.24)

where hL = Liquid level above nozzle, ft. u = Nozzle velocity, ft/s. g = acceleration due to gravity, 32.2 ft/s2. 2. F  or a saturated (bubble point) liquid, pipe vertically downward from the drawoff nozzle as close to the nozzle as possible. This gives maximum static head above any horizontal sections or piping networks ahead of the pump. A vortex breaker should be provided for the vessel drawoff nozzle (Figure 16.33). Some rules of thumb for the suction lines are: 1. K  eep it short and simple. 2. Avoid loops or pockets that could collect vapor or dirt. 3. Use an eccentric reducer with the flat side up (to prevent trapping vapor) as the transition from the larger suction line to the pump suction nozzle. 4. Typical suction line pressure drops: Saturated liquids = 0.05 − 0.5 psi/100 ft Subcooled liquids = 0.5 − 1.0 psi/100 ft

Example 16.3: Suction Lift What is the Suction Lift value to be used with the pump curves of Figure 16.21a, if a gasoline system calculates an NPSH of 15 ft?

Solution Total Suction Lift (as water) = 15 − 33 = −18 ft. Therefore, a pump must be selected which has a lift of at least 18 ft. The pump of Figure 16.21a is satisfactory using an interpolated suction lift line between the dotted curves for 16 ft and 21 ft of water. The performance of the pump will be satisfactory in the region to the left of the new interpolated 18-ft line. Proper performance should not be expected near the line. If the previous system were at sea level, consider the same pump with the same system at an altitude of 6000 ft. Here the barometric pressure is 27.4 ft of water. This is 34 − 27.4 = 6.6 ft less than the sea level installation. The new NPSHA will be 15 ft − 6.6 ft = 8.4 ft. Referring to the pump curve of Figure 16.21a, it is apparent that this pump cannot do greater than 21 ft suction lift as water or 12 ft NPSHR of liquid (fluid). Total Suction Lift as water = 8.4 − 33 = −24.6 ft. The pump curves show that 21 ft suction lift of water is all the pump can do, hence the 24.6 ft is too great. A different pump must be used which can handle this high a suction lift. Such a pump may become expensive, and it may be preferable to use a positive displacement pump for this high lift. Normally lifts are not considered reasonable if over 20 ft.

Example 16.4: NPSHA in Open Vessel System at Sea Level Conditions: at sea level, atmospheric pressure, Pa = 14.7 psia (1.013 bara) (use Figure 16.25). Assume liquid is water at 85°F (29.4°C), vapor pressure, Pvp = 0.6 psia (0.04 bara). Assume tank liquid level is 10 ft above center line of pump, then S = + 10 ft (3.05 m). Assume that friction losses have been calculated to be 1.5 ft, hSL = 1.5 ft (0.46 m)

380  Petroleum Refining Design and Applications Handbook Volume 2 Using Eq. 16.18 gives: NPSHA = (14.7 − 0.6) (2.31/0.997) + 10 – 1.5 = 41.2 ft (good) In Metric units, by using Eq. 16.23 NPSHA = (1.013 − 0.04) (10.2/0.997) + 3.05 − 0.46 = 12.54 m (41.2 ft) Note: For the worst case, which is an empty tank, “S” becomes Sw on the diagram.

Example 16.5: NPSHA in Open Vessel Not at Sea Level Conditions: Vessel is at altitude 1500 ft (457.2 m), where atmospheric pressure is Pa = 13.92 psia (0.96 bara) (use Figure 16.26) Liquid: Water at 150°F (65.56°C), vapor pressure Pvp = 3.718 psia (0.256 bara) and specific gravity, SpGr = 0.982 Assume vessel liquid level is 12 ft (3.657 m) below centerline of pump, SL = −12(−3.657 m). Friction losses: Assume as calculated to be 1.1 ft (0.335 m) of liquid. Using Eq. 16.18 NPSHA = (13.92 − 3.718) (2.31/0.982) − 12 − 1.1 = 10.90 ft In Metric units, using Eq. 16.23 NPSHA = (0.96 − 0.256) (10.2/0.982) − 3.657 − 0.335 = 3.32 m (10.90 ft) The worst condition case should be calculated using S′L, since this represents the maximum lift.

Example 16.6: NPSHA in Vacuum System Conditions: Vessel is liquid collector at 28 in. Hg Vacuum (referred to a 30 in. barometer) (use Figure 16.28a). This is 30 − 28 = 2 in. Hg abs, or Pa = [(14.7/30)] (2) = 0.98 psia (0.067 bara). Liquid: Water at 101.2°F (38.4°C), vapor pressure = 0.98 psia (0.067 bara). Assume vessel liquid level is 5 ft (1.524 m) above centerline of pump, S = + 5ft, worst case, Sw = 2 ft (0.61 m) Friction losses: Assume to be 0.3 ft (0.091 m) of liquid Using Eq. 16.18 NPSHA = (0.98 − 0.98) (2.31/0.994) + 5 – 0.3 = 4.7 ft Worst case = 4.7 ft (not practical design) The pump selected for this application (water boiling at 0.98 psia) must have a NPSHR less than 4.7 ft preferably about 3–3.5 ft. This is a difficult condition. If possible the vessel should be elevated to make more head (S) available which will raise the NPSHA. In Metric units, using Eq. 16.23 NPSHA = (0.067 − 0.067) (10.2/0.994) − 1.524 − 0.091 =1.433 m (4.7 ft)

Pumps  381

Example 16.7: NPSHA in Pressure System Conditions: Vessel contains butane at 90°F (32.22°C) and 60 psia (4.138 bara) system pressure, Pa = 60 (4.138 bara) (use Figure 16.28b) Butane vapor pressure, Pvp at 90°F (32.22°C) = 44 psia (3.034 bara), SpGr = 0.58. Assume liquid level is 8 ft (2.438 m) below pump centerline, S = −8 ft (−2.438 m). Friction losses: Assume to be 12 ft (3.658 m) of liquid. Then from Eq. 16.18 NPSHA = (60.0 − 44) (2.31/0.58) − 8 − 12.0 = 43.72 ft In Metric units, from Eq. 16.23 NPSHA = (4.138 − 3.034) (10.2/0.58) − 2.438 − 3.658 = 13.32 m (43.7 ft) This presents no pumping problem.

Example 16.8: Closed System Steam Surface Condenser NPSH Requirements Refer to Figure 16.39 for this example This is a closed steam surface condenser system with condensate being pumped out to retreatment facilities. From the conditions noted on the diagram, Friction loss in suction line side = 2.92 ft Absolute pressure in condenser = pʹ = 1.5 in. Hg Abs = 1.5(1.137 ft/in. Hg) = 1.71 ft water

CONDENSER Abs = 1.50” Hg Vacuum = 28.42” Hg

Condensate 91.72°F

10'

Figure 16.39  Surface condenser condensate removal. Closed system steam surface condenser NPSH requirements (by permission, Cameron Hydraulic Data, 16th ed. Ingersoll-Rand Co., 1979, p. 1–12).

382  Petroleum Refining Design and Applications Handbook Volume 2 Water from steam tables at saturation = 1.5 in. Hg abs at 91.72°F Vapor pressure, p′vp, at 1.5 in. Hg Abs = 1.5(1.137) = 1.71 ft H2O NPSHA = (1.71 − 1.71) + 10 − 2.92 = + 7.08 ft The suction head or lift for the pump (separate calculation from NPSHA) is as follows: The 28.42 in. Hg vacuum (gauge) is equivalent to 1.5 in. Hg abs 28.42 in. vacuum (1.137 ft/in Hg) = 32.31 ft H2O Static submergence = 10.0 ft (see Figure 16.39) Friction/entrance losses = 2.92 ft Net static submergence = 7. 08 ft Equivalent suction lift = 25.23 ft (Note: 32.31 − 7.08) (= vacuum effect less net submergence) Note that the equivalent suction lift must be added to the total discharge head for the pump system to obtain the total system head. Keep in mind that the work the pump must accomplish is overcoming the suction losses (+ or −) plus the discharge losses, that is, + discharge loss (all) – (+ if head, or −if lift on suction losses all). Thus, the suction lift becomes a (−) (−) or a (+) to obtain the total system head. Keep in mind that a vacuum condition on the suction of a pump never helps the pump, but in effect is a condition that the pump must work to overcome.

Example 16.9: Process Vacuum System For this process example, again using water for convenience, a low pressure, low temperature water is emptied into a vented vessel, and then pumped to the process at a location at about 3000 ft. altitude where atmospheric pressure is approximately 13.2 psia, Water SpGr is at 200°F = 0.963 (refer to Figure 16.40 for this example) Determine the NPSHA for pump:

High altitude venting

P = 13.2 PSIA

Low pressure water

S = 10'

P = 11.5 PSIA 200°F Water

Friction/entrance type losses = 1', hSL

Figure 16.40  High altitude process vacuum system, NPSH requirements.

Pumps  383 Then From Eq. 16.18 NPSHA = (13.2 − 11.5) (2.31 ft/0.963) + 10 − 1.0 = 13.08 ft available For hydrocarbons and water significantly above room temperatures, the Hydraulic Institute [8] recommends the use of a correction deduction as given in Figure 16.41. This indicates that the NPSHR as given on the pump curves can be reduced for conditions within the range of the curve based on test data. 1000

500 400 300 10 9.5

E

N PA RO

200

P

8

150 100

4 3

VAPOR PRESSURE psia

50

2

40

1.5

30

NPSH REDUCTIONS-FEET

6 5

1.0

20

NE

TA

·BU

ISO

15

E

N TA BU

·1

10

1

0.5

RA

GE

I FR

R NT

TH YL AL CO H

OL

RE

5

ME

4

WA TE

R

3 2 1.5 1.0

0

50

100

150

200

250

300

400

TEMPERATURE °F

Figure 16.41  NPSH reductions for pumps handling hydrocarbon liquids and high temperature water (Note: Do not use for other fluids.) (by permission from Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pumps, Hydraulic Institute, 13th ed., 1975).

384  Petroleum Refining Design and Applications Handbook Volume 2 If the pump given in the curve of Figure 16.21a were being used to pump butane at 90°F and 0.58 gravity, the correction multiplier from the NPSH curve is about 0.99 by interpolation. This means that the values of Figure 16.21a should be multiplied by 0.99 to obtain the actual NPSH the pump would require when handling a hydrocarbon of these conditions. The correction does not apply to other fluids. If the system pressure were 46 psia, then NPSHA = (46 − 44) (2.31/0.58) − 8 − 12 = −12 ft, and this is an impossible and unacceptable condition. This means liquid will flash in the line and in the impeller, and cannot be pumped, and NPSH must always be positive in sign.

16.12 Reductions in NPSHR Limitations for use of the Hydraulic Institute NPSH reduction chart (Figure 16.41) are as follows [8]: 1. N  PSH reductions should be limited to 50% of the NPSHR required by the pump for cold water, which is the fluid basis of the manufacturer’s NPSHR curves. 2. It is based on handling pure liquids, without entrained air or other non-condensable gases, which adversely affect the pump performance. 3. Absolute pressure at the pump inlet must not be low enough to release non-condensables of pure liquids. If such release can occur, then the NPSHR would need to be increased above that of the cold water requirements to avoid cavitation and poor pump performance. 4. For fluids, the worst actual pumping temperature should be used. 5. A factor of safety should be applied to ensure that NPSH does not become a problem. 6. The chart should not be extrapolated beyond NPSH reductions of 10 ft.

Example 16.10: Corrections to NPSHR for Hot Liquid Hydrocarbons and Water In Figure 16.41, use the dashed example lines at a temperature of 55°F for propane [8], and follow the vertical line to the propane vapor pressure dashed line, which reads 100 psia vapor pressure. Then follow the slant lines (parallel) to read the scale for NPSH reductions, that is, feet at 9.5 ft. Now the pump selected reads NPSHR on its pump performance curve of 12 ft for cold water service. Now, half of 12 ft = 6 ft But in Figure 16.41, the reduction = 9.5 ft Corrected value of NPSHR to use = 6 ft, since 9.5 ft is >half the cold water value.

Example 16.11: Alternate to Example 16.10 Assume that a boiler feed water is being pumped at 180°F. Read the chart in Figure 16.41 and the water vapor pressure curve, and follow over to read NPSH reduction = 0.45 ft. A pump selected for the service requires 6 ft cold water service NPSHR: Half of 6 = 3 ft Value from chart for 180°F = 0.45 ft reduction Then correct NPSHR to use = 6 ft − 0.45 ft = 5.55 ft required by the pump for this service

16.13 Charting NPSHR Values of Pumps For a given pump and speed, the NPSHR depends primarily on flow rate; thus NPSHR depends on the pump’s design characteristics such as the physical dimensions of the casing, pump speed and impeller types. The NPSHR of a pump

Pumps  385 at a given capacity-head rating increases with increasing pump speeds ( rpm is proportional to NPSH0.75). As a result, critical suction applications as those required to have a low NPSHA will have to employ pumps running at slow speeds. These include such applications as pumping of fluids in systems with restricted suction heads, relatively long suction pump lines or at the liquid boiling points. In critical suction installations, designers select pumps capable of running at 1750 rev/min or lower rather than units that operate at typically higher values, such as at 3500 rev/min. This requires that pumps have to be bigger for a given capacity requirement. Figure 16.42 shows a chart that provides a simple way of estimating the value of NPSHR of a pump and therefore helps to fix the conditions of the pipe system at pump suction so that the NPSHA can be sufficiently higher. Therefore, finding the NPSHR from the chart, designers can select the correct suction conditions (e.g., pipe diameter, length, static head, and so on), to ensure that the NPSHA will be higher than the NPSHR from the pump. Figure 16.42 requires using the following steps in determining NPSHR 1. D  etermine the flow rate (gal/min) of the fluid to be pumped. Then by using the bottom half of Figure 16.40, a rough idea of the size of the pump that is required for the application is determined. For example, to pump 500 gal/min over 300 ft of head would require a pump with an 8-in. impeller running at about 3560 rev/min. 2. Looking at the upper section of the chart, the NPSHR is approximately 13 ft H2O. 3. Since the NPSHA of the system should be at least 3 ft higher than the NPSHR, the NPSHA should be a minimum of 16 ft. To prevent cavitation in a pumping system, NPSHA should be at least 3 ft above the NPSHR, read from the pump curve for the given total dynamic head (TDH) and pumping rate.

NPSHA ≥ NPSHR + 3ft

(16.25)

30

3,578

Required NPSH, ft

20

3,480 RPM

3,560

3,550

1,750

10 3,490 0 Pump sizes are in inches

1,300

3,578 3,560

173/16

Head, ft

1,000 13

500 3,480 RPM

3,490

14 15

3,560 7

6

100

14

16 3,550 8

19 18 1617 15 14

9¼

8

14 12

15¼

1,750

60 10

50

100 Flowrate, gal/min

Figure 16.42  Head, NPSHR vs. flow rate [25].

500

1,000

4,000

386  Petroleum Refining Design and Applications Handbook Volume 2 Based on Eq. 16.18, there are various ways to increase the NPSHA to make a pumping system feasible. These are [32]: 1. 2. 3. 4. 5.

 aise the liquid level in the suction tank (increasing the S term). R Lower the pump location (increasing the S term). Reduce the frictional loss on the suction side (by reducing suction side velocity or pipe length). Pressurize the suction tank (increase Ps). Lower the vapor pressure by reducing pumping temperature (reduce pv).

16.14 Net Positive Suction Head (NPSH) NPSHR is normally specified by the pump supplier, while based on the installation of pump, NPSHA should be calculated and specified by the designer. Theoretically, NPSHA should be greater than zero to avoid cavitation. NPSHR depends on properties of liquid, the total liquid head; pump speed, capacity and impeller design. Practical curves of NPSHR vs. capacity and speed of the pump are supplied by the pump manufacturer. Figures 16.43 and 16.44 can be employed as a guideline to find the value of NPSHR for centrifugal pump handling water at temperatures below 100°C and above 100°C, respectively. When a pump installation is designed, the available net positive suction head, NPSHA can be calculated by the following equation.

NPSHA = hss – hfs – pv

(16.26)

30 25 20 15 e 70 abov rpm 0 5 5 3 bar to 70 en 35 e w t m be

(NPSH)R, m

10 7.5

3550 5

3550

4

r

rp

w 35

elo pm b

bar

bar

en 35 1750 rpm betwe

bar to 70

3

1750

2

min rpm/

w 35

belo

bar

Capacity, m3/h

Figure 16.43  Net positive suction head for high pressure centrifugal hot-water pumps (source: Hydraulic Institute (USA)).

400

350

300

250

200

175

150

125

100

90

80

70

60

50

45

40

35

30

25

1.5

Pumps  387 8

7

6

Additional (NPSH)R, m

5

4

3

2

1

0 100

150

200

Water Temperature, °C

Figure 16.44  Temperature correction chart for net positive suction head requirement for centrifugal hot water pumps (source: Hydraulic Institute).

where hss = Static suction head, m liquid column (LC) = p ± Z hfs = Friction loss in suction line, m of liquid column (LC) pv = Vapor pressure of liquid at suction temperature expressed in m of liquid column (LC) For existing installation, NPSHA can be determined by

NPSHA = atm pressure + hgs –pv + hvs

(16.27)

where hgs = suction gauge pressure, m of liquid column (LC) pv = vapor pressure of liquid at suction temperature expressed in m of liquid column (LC) As a general guide, NPSHA should preferably be above 3 m for pump capacities up to a flow rate of 100 m3/h and 6 m above this capacity. For a given system, if NPSHA is less than NPSHR, the following remedial measures are recommended as follows: 1. Change the location of the pump to improve NPSHA and increase the positive suction head.

388  Petroleum Refining Design and Applications Handbook Volume 2 2. P  rovide jacketed cooling in the suction line to decrease the vapor pressure pv of the liquid. 3. Reduce the operating speed of the pump; thereby reducing the specific speed of the pump and subsequently its NPSHR is less.

16.15 NPSH Requirement for Liquids Saturation With Dissolved Gases There are instances where the liquid to be pumped is saturated with gases, which have definite solubility in the liquid. When a suction system for such a liquid is to be designed for a centrifugal pump, NPSHA calculations differ from Eq. 16.26 or 16.27. Pumping of cooling water (saturated with air), pumping of condensate from a knock-out drum of a compressor, pumping of solution from an absorber, and so on., are examples of situations where the liquids are saturated with gases. Dissolved gases start desorbing when the pump is started and suction is generated at the pump eyes. Generally, a pump can tolerate 2–3% flashed gases at the pump eye without encountering cavitations. If the design of the suction system is made to restrict about 2.5% flash, it is considered safe for the pump operation. In Eq. 16.26, suction source pressure is the system pressure minus the vapor pressure, pv for a normal liquid having practically no dissolved gases. For a liquid saturated with dissolved gases, pv is replaced by pva, which is called artificial liquid vapor pressure. For evaluation of pva, the following procedure is recommended as follows: 1. 2. 3. 4.

 alculate molar mass of the gas mixture, dissolved in the liquid. C Calculate mass fraction (wo) of the dissolved gas mixture. Calculate pseudo-critical properties of the dissolved gas mixture, if system pressure is high. Calculate specific volume of the dissolved gas mixture (VGa) at the operating conditions. Steps 1–4 can be avoided if the solubility of the gas mixture in the liquid (such as air in water) is known. 5. Calculate volume fraction of the dissolved gas (GVP) in a hypo-theoretical gas – liquid mixture. Consider one unit mass of the liquid in which the gas mixture is dissolved. If GVP is less than or equal to 2.5%, Eq. 16.26 can be safely used to calculate NPSHA using vapor pressure, pv of the liquid at the operating temperature. If higher then calculate volume fraction a, of flashed gas mixture (as pressure is lowered) over the liquid, saturated with the dissolved gas mixture, using the following [39]:

a=



1    p p 2 p    − v  1− v     po po   po   + 1  V   p   p   Ga     1 −     VL   po   po  



(16.28)

where p = liquid pressure at pump eye, kPa pv = vapor pressure of liquid at the operating temperature, kPa po = system pressure, kPa VGa = specific volume of the dissolved gas mixture, m3/kg VL = specific volume of the liquid at the operating conditions, m3/kg

Eq. 16.28 assumes that the dissolved gas mixture follows ideal gas law, Dalton’s law and Henry’s law.

6. C  alculate a for different value of p. Draw a graph of a vs. p. Read p corresponding to a = 0.025 which is called pva. Alternatively, by trial and error, calculate pva, for a = 0.025. 7. Use Eq. 16.26 and insert pva in place of pv and calculate NPSHA.

Pumps  389

Example 16.12 Carbon dioxide gas (>99.5% pure) from ammonia plant at 1.01 atm a and 40°C is washed with cooling water in a packed column before compression in a plant [28]. Cooling water from bottom of the column is pumped back to cooling tower. Solubility of carbon dioxide in water is 0.0973 kg/100 kg water at 1 atm and 40°C. Find the volume fraction of carbon dioxide over cooling water. Also calculate the artificial liquid vapor pressure.

Solution Molar mass of carbon dioxide, Mw = 44 Vapor pressure of H2O at 40°C pv = 0.07375 bar = 0.0728 atm. Mass fraction of CO2 in the liquid

wo =

0.0973 × 1.01 (100 + 0.0973)

= 9.8177 × 10−4





9.8177 × 10−4 × 0.08206 × 313.15 44.0095 × 1.01 = 5.676 × 10−4 m3/kg H 2O

VGa =



From the Steam Tables,

VL = 1.0078 m3/kg H2O at 40°C 5.676 × 10−4 × 100 (1.0078 + 5.676 × 10−4 ) = 0.0563%

GVP =

Therefore, the volume per cent of carbon dioxide is only 0.0563% (4

Francis-Vane Area D2 D1

= 1.5 to 2

Mixed Flow Area D2 D1

< 1.5

Axial Flow Area D2 D1

Rotation

=1

Figure 16.45  Impeller designs and corresponding specific speed range (by permission from Standards of the Hydraulic Institute, 10th ed.) (also see [18]. Hydraulic Institute, 13th. Ed., 1975).

Pumps  391 600

400

300

200

150

100

80

60

50

40

30

20

30

20

4000

TO TAL SU TT CT OTA ION LS HE UC AD TIO 5F N TT H EA OTA D LS UC TIO NL IFT 15 FT TO TAL SU CT ION LIF T

3500

10

CT SU TO TAL

LIF ION CT SU TO TAL

FT

TO TAL

10

SU

FT

CT

T

ION

TO TAL

LIF

SU

T

CT

2000

25

ION

FT

HE

AD

ZER O

ION

LIF T

5F

2500

20

FT

1500

SPECIFIC SPEED, NS =

RPM

H%

GPM

FOR SINGLE SUCTION OVERHUNG IMPELLER PUMPS

16

FT

3000

1000

900

800

700

400

300

200

150

100

80

60

50

40

H = TOTAL HEAD IN FEET (FIRST STAGE)

Figure 16.46  Upper limits of specific speeds for single suction overhung impeller pumps handling clear water at 85°F at sea level (by permission from Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pumps, Hydraulic Institute, 13th ed. 1975).

392  Petroleum Refining Design and Applications Handbook Volume 2 20000

50

100

40

30

20

15

10

8

7

6

5

4

10

8

7

6

5

4

SUC 15

5 FT

FT T OTA L

TOT AL

SUC

TIO N

TIO N

LIFT

LIFT

EAD NH

SUC

TIO

SUC

5F

15

T TO TAL

FT T OTA L

H% RPM

10000

9000

ZER

O

8000

TIO

NH

EAD

7000

NL

IFT

SUC

TIO

TIO NL IFT

SUC

20

FT T OTA L

10

FT T OTA L

10 5000

SUC

6000

FT T OTA L

SPECIFIC SPEED, NS =

SINGLE SUCTION MIXED FLOW AND AXIAL FLOW PUMPS

GPM

TIO N

HEA

D

15000

4000

3500 100

50

40

30

20

15

H = TOTAL HEAD IN FEET (FIRST STAGE)

Figure 16.47  Upper limits of specific speeds for single suction, mixed, and axial flow pumps handling clear water at 85°F at sea level (by permission from Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pumps, Hydraulic Institute, 13th ed., 1975).

Pumps  393 A typical “operating specific speed” curve is shown in Figure 16.48 and represents a technique for plotting the specific speed on the operating performance curve. Figure 16.48 represents a 6-in. pump operating at 1760 rpm, with maximum efficiency at 1480 gpm and 132 ft head [10]. The operating specific speed is zero at no flow and increases to infinity at the maximum flow of 2270 gpm and zero head. Stable operations beyond about 1600 1700 gpm cannot be planned from such a curve with a sharp cutoff drop for head capacity. “Type specific speed” is defined as that operating specific speed that gives the maximum efficiency for a specific pump and is the number that identifies the pump type [10]. This index number is independent of the rotative speed at which the pump is operating, because any change in speed creates a change in capacity in direct proportion and a change in head that varies as the square of the speed [10]. The specific speed of the pump is reasonably close to the

HS FOR TYPING

SPECIFIC SPEED, NS

4000 3000 2000 D

IC SPEE

SPECIF

1000

180

90

HEAD-CA

PACITY

160

80

140

70 CY IEN

60

EF FIC

100

50

BHP 80

40

60

30

40

20

20

10

0

BHP, P

TOTAL HEAD, H, IN FEET

120

POINT OF MAXIMUM EFFICIENCY

EFFICIENCY, ?, PERCENT

0

0 0

2

4

6

8

10

12

14

14

18

20

22

CAPACITY, IN 100 GPM

Figure 16.48  Typical centrifugal pump characteristic curve with auxiliary specific speed curve. Double-suction, single stage, 6-in. pump, operating at 1760 rpm constant speed (by permission, Karassik, I. and R. Carter, Centrifugal Pumps, McGraw-Hill Book Co., Inc. 1960, p. 197).

394  Petroleum Refining Design and Applications Handbook Volume 2 conditions of maximum efficiency, and Figure 16.45 illustrates the range of typical specific speed index numbers for particular types of impellers.

Example 16.13: “Type Specific Speed” In Figure 16.48, where the pump operates at 1760 rpm (a standard motor speed under load) and has maximum efficiency at 1480 gpm and 132 ft head, the “type” specific speed using Eq. 16.29 is



 1760 1480  = 1740 rpm Ns =  0.75   (132) 

In metric units,



 n Q  Ns =  0.75   (gH) 

(16.30)

where g = acceleration due to gravity, 9.81 m/s2 H = total head, m n = speed, rps Q = flow rate, m3/s Figure 16.45 indicates the general type of impeller installed. The specific speed of a given pump type must not exceed the specific speed values presented by the Hydraulic Institute [8]. This is based on a known or fixed condition of suction lift, and relates speed, head, and capacity. This index is a valuable guide in establishing the maximum suction lifts and minimum suction heads to avoid cavitation of the impeller with resultant unstable hydraulic performance and physical damage. For a given set of conditions on the suction and discharge of a pump, a slow rotative speed will operate safer at a higher suction lift than a pump of higher rotative speed.

16.17 Rotative Speed The rotative speed of a pump is dependent upon the impeller characteristics, fluid type, NPSHA and other factors for its final determination. The most direct method is by reference to manufacturer’s performance curves. When a seemingly reasonable selection has been made, the effect of this selected speed on the factors such as NPSHR, suction head or lift, fluid erosion and corrosion, and so on must be evaluated. For many systems these factors are of no concern or consequence. Normal electric motor speeds run from the standard induction speeds for direct connection of 3600, 1800, and 1200 rpm to the lower speed standards of the synchronous motors, and then to the somewhat arbitrary speeds established by V-belt or gear drives. For some cases, the pump speed is set by the type of drivers available, such as a gasoline engine. Electric motors in pump application never run at the “standard” rotative design speeds noted above, but rotate at about (with some deviation) 3450, 1750, and 1150 rpm, which are the speeds that most pump manufacturers use for their performance curves. If the higher numbers were used (motor designated or name plate) for pump performance rating, the pumps would not meet the expected performance, because the motors would not be actually rotating fast enough to provide the characteristic performance curves for the specific size of impeller.

Pumps  395

16.18 Pumping Systems and Performance It is important to recognize that a centrifugal pump will operate only along its performance curve [14, 16]. External conditions will adjust themselves, or must be adjusted in order to obtain stable operation. Each pump operates within a system, and the conditions can be anticipated if each component part is properly examined. The system consists of the friction losses of the suction and the discharge piping plus the total static head from suction to final discharge point. Figure 16.49 represents a typical system head curve superimposed on the characteristic curve for a 10 by 8-in. pump with a 12-in. diameter impeller. Depending upon the corrosive or scaling nature of the liquid in the pipe, it may be necessary to take this condition into account as indicated. Likewise, some pump impellers become worn with age due to the erosive action of the seemingly clean fluid and perform as though the impeller were slightly smaller in diameter. In erosive and other critical services this should be considered at the time of pump selection. Considering Figure 16.26 as one situation which might apply to the system curve of Figure 16.49 the total head of this system is:



H = D + hDL ( SL hSL)

(16.31)

The values of friction loss (including entrance, exit losses, pressure drop through heat exchangers, control valves, etc.) are hSL and hDL. The total static head is D − SL, or [(D + D′) − (−SL)] if siphon action is ignored, and (D + D′ ) − ( S′L )  s for worst case, good design practice. 45 10 Hp

15 Hp

40

Efficiency 70

35

75 80

12" Dia. Impeller, New Conditio n

Operating Points with New Impeller, H

Possible Operation of Worn Impeller

30

Total Head in Feet

Size Pump: 10" X 8" Speed: 860 rpm

p d”

25

Operating Points with Worn Impeller

e ip

e ge pip “A w” r e o f “N for rve ve Cu r u Suction plus Discharge Friction tem stem C Sys Sy

20

System Static Head 15

10

5

0

200

400

600

800

1000

1200

Capacity, gpm

Figure 16.49  System head curves for single pump installation.

1400

1600

1800

2000

2200

396  Petroleum Refining Design and Applications Handbook Volume 2 Procedure: 1. C  alculate the friction losses hSL and hDL for three or more arbitrarily chosen flow rates, but rates which span the area of interest of the system. 2. Add [hSL + hDL+ (D ± S)] for each value of flow calculated. These are the points for the system head curve. 3. Plot the gpm values versus the points of step 2 above. 4. The intersection of the system curve with the pump impeller characteristic curve is the operating point corresponding to the total head, H. This point will change only if the external system changes. This may be accomplished by adding resistance by partially closing valves, adding control valves, or decreasing resistance by opening valves or making pipe larger, and so on. For the system of Figure 16.26, the total pumping head requirement is



H = (D + hDL) [ SL + ( hSL)] = (D + hDL) + (SL + hSL)



(16.32)

The total static head of the system is [D − ( S)] or (D + S) and the friction loss is still hDL + hSL, which includes the heat exchanger in the system. For a system made up of the suction side as shown in Figure 16.28a and the discharge as shown in Figure 16.29a, the total head is

50 Condition

45 Impeller Operating Head Curve

Friction + 22' Static Head

40 35

Friction + 15' Static Head Operating Points for System

Head in Feet

30 25 20 15 System Friction (See Figure 5.51)

10 5 0 0

10

20

30

40

50

60

70

80

90

System Flow, gpm

Figure 16.50  System head curves for variable static head.

100

110

120

130

140

150

160

Pumps  397



H = D + hDL + P1 [+ S − hSL + P2]

(16.33)

where P2 is used to designate a pressure different than Pl. The static head is [(D + P1) − (S + P2)], and the friction head is hDL + hSL. Figure 16.50 illustrates the importance of examining the system as it is intended to operate, noting that there is a wide variation in static head, and therefore there must be a variation in the friction of the system as the gpm delivered to the tank changes. It is poor and perhaps erroneous design to select a pump which will handle only the average conditions, for example, about 32 ft total head. Many pumps might operate at a higher 70-ft head when selected for a lower gpm value; however, the flow rate might be unacceptable to the process.

Example 16.14: System Head Using Two Different Pipe Sizes in Same Line The system of Figure 16.51 consists of the pump taking suction from an atmospheric tank and 15 ft of 6-in. pipe plus valves and fittings; on the discharge there is 20 ft of 4-in. pipe in series with 75 ft of 3-in. pipe plus a control valve, block valves, fittings, and so on. The pressure of the discharge vessel (bubble cap distillation tower) is 15 psig, with water as the liquid at 40°F in a 6-in. suction pipe (using Cameron Tables—see Chapter 15 Table 15.41). To simplify calculations for greater accuracy, use detailed procedure of Chapter 15. Pipe or fitting loss Loss, ft/100 ft For 15 ft

15.0 ft

Two 90° ells, eq.

22.8

Gate valve, open

3.2

Total

41.0 ft

200 gpm

300 gpm

0.584

1.24

0.24 ft

0.51 ft

The total suction head = hs = +7 − 0.24 = +6.76 at 200 gpm

hs = +7 − 0.51 = +6.49 at 300 gpm Discharge: 4 in. pipe

3 in. pipe

200 gpm

300 gpm

200 gpm

300 gpm

Loss, ft/100 ft

4.29

9.09

16.1

34.1

For 20 ft

20.0

20.0

For 75 ft

75.0

75.0

Two, 3”, 90° ells, eq.

8

8

1.7 ft

1.7 ft

One, 4”, 90° ells, eq.

4.6

4.6

One Gate valve open Total, equivalent ft

24.6

24.6

84.7

84.7

Friction loss, ft fluid

1.06

2.23

13.6

28.8

Control valve at 60% of total, ft

1.59

3.34

20.4

43.2

Total discharge friction loss, ft

2.65

5.57

34.0

72.0

398  Petroleum Refining Design and Applications Handbook Volume 2 15 psig

Bubble cap Distillation Tower

3" – 75 feet

Total Static Head

Atmospheric Vent D = 45' Max. 20' of 4"

Min.

Control Valve

S = 7' 6" 15"

Discrepancy due to Variation in Friction Loss Data

150

100

em yst

ad

He

(Av

lS ota

)

rve

Cu

Head in Feet

T

era

d ge

3" 50

0

0

sD plu

tio

Fric

e)

arg

sch

i n (D

Su

n(

tio

c Fri

on cti

e)

arg

h isc

ischarge)

Friction (D

100

200 Gallons per minute

Figure 16.51  System head using two different pipe sizes in same line.

300

4"

Pumps  399 Total static head = 45 − 7 + 15 (2.31 ft/psi/SpGr) = 72.65ft, SpGr = 1.0 Composite head curve at 200 gpm, head = 72.65 + 0.24 + 2.65 + 34.0 = 109.54 ft at 300 gpm, head = 72.65 + 0.51 + 5.57 + 72.0 = 150.73 ft Total head on pump at 300 gpm: H = 45 + 15(2.31) + 5.57 + 72.0

7 + 0.51 = 150.73 ft

The head at 200 gpm (or any other) is developed in the same manner.

Example 16.15: System Head for Branch Piping With Different Static Lifts The system of Figure 16.52 has branch piping discharging into tanks at different levels [17]. Following the diagram, the friction in the piping from point B to point C is represented by the line B–P–C. At point C, the flow will all go to tank E unless the friction in line C–E exceeds the static lift, b, required to send the first liquid into D. The friction for the flow in line C–E is shown on the friction curve, as is the corresponding friction for flow through C–D. When liquid flows through both C–E and C–D, the combined capacity is the sum of the values of the individual curves read at constant head values, and given on curve (C–E) + (C–D). Note that for correctness the extra static head, b, required to reach tank D is shown with the friction head curves to give the total head above the “reference base.” This base is an arbitrarily but conveniently selected point. The system curves are the summation of the appropriate friction curves plus the static head a required to reach the base point. Note that the suction side friction is represented as a part of B–P–C in this example. It could be handled separately, but must be added in for any total curves. The final total system curve is the friction of (B–P–C) + (C–E) + (C–D) plus the head a. Note that liquid will rise in pipe (C–D) only to the reference base point unless the available head is greater than that required to flow through (C–E), as shown by following curve (B–P–C) + (C–E) + a. At point Y, flow starts in both pipes, at a rate corresponding to the Y value in gpm. The amounts flowing in each pipe under any head conditions can be read from the individual system curves. The principles involved here are typical and may be applied to many other system types.

16.19 Power Requirements for Pumping Through Process Lines A fluid flows of its own accord as long as its energy per unit mass decreases in the direction of flow. Alternatively, it will flow in the opposite direction only if a pump is used to supply energy, and to increase the pressure at the upstream end of the system. From the energy balance equation in Chapter 15, (i.e., neglecting the internal energy and the heat input to the system).



∆P ∆v 2 +α + g∆z + Ws + e f = 0 ρ 2

(16.34)

The work done on unit mass of fluid (−Ws) is:



(− Ws ) =

∆P ∆v 2 +α + g∆z + e f 2 ρ

(16.35)

400  Petroleum Refining Design and Applications Handbook Volume 2 k-feet of L” pipe

D

b Ref. Base

E

a

g-feet of j”

m-feet of n” pipe C

A

B

e-feet of f” pipe

–P

–C

)+

(C

–E

Head Feet

)+

a

System Curves

(B

(B

[(C

–P

–

) –C

+

(C E) +

(C

) –D

+

)] +

–D

l Tota

a

P (B –

)+

–C

a Curves developed at points of equal head when combining individual parts of system

em

Syst

γ b

Friction Curves

a C

C–

–E

(C

D

+ – E)

(C –

D)

B–P–

b

C

Gallons per minute

Figure 16.52  System head for branch piping with different static lifts.

where ΔP = difference in the pressure between points 1 and 2. Δv = difference in the velocity between points and 2. Δz = difference in the distance/elevation between points 1 and 2. (−Ws) = work done on a unit mass of fluid ef = energy dissipated by friction in the fluid per unit mass (including all thermal energy effect losses due to heat transfer or internal generation) between points 1 and 2. α = 1 or 2 for turbulent or laminar flow, respectively.

Pumps  401 The total rate at which energy must be transferred to the fluid is G(−Ws), where G is the mass flow rate, and the power supplied P is



 ∆P  ∆v 2 P = G(− Ws ) = G  +α + g∆z + e f  = Gh g 2  ρ 

(16.36)

where G = mass flow rate, kg/s h = total head, m g = acceleration due to gravity, 9.81 m/s2 The overall power requirement taking into account the pump efficiency, e is

1 P = Gh g e



(16.37)

where e = pump efficiency, fraction.

Hydraulic Power Once the flow and corresponding system resistance have been established, the pumping hydraulic power can be calculated from the following:



hydraulic , hp =

(Q )(H)(SpGr ) 3960

(16.38)

(Q )(∆P) 1714

(16.39)

where Q = flow, gpm. H = total head, ft. SpGr = specific gravity of liquid. or



hydraulic , hp =

where ΔP = differential pressure, lbf/in.2 In metric units The pump hydraulic power output PQ is

where ρ = fluid density, kg/m3 Q = flow, m3/h H = total head, m

PQ =

(ρ)(Q )(H) , kW 367 × 103

(16.40)

402  Petroleum Refining Design and Applications Handbook Volume 2 or

(Q )(∆P) , kW 36

(16.41)

PQ (ρ)(Q )(H) = , kW e 367 e × 103

(16.42)

PQ =

where ΔP = differential pressure, bar. The pump power input

P=

where e = pump efficiency, fraction.

Relations Between Head, Horsepower, Capacity, Speed Brake Horsepower (BHP) Input at Pump

BHP = (Q )(H)



(SpGr ) (3960 e)

(16.43)

where H = total head, ft. Q = flow, gpm SpGr = specific gravity of liquid. e = hydraulic power, hp/Brake horse power. The efficiency, e (fraction) is the ratio of power out to power absorbed. Water or liquid horsepower [10]

WHP = (Q )(H)



(SpGr ) (3960)

(16.44)

The difference between the brake horsepower and the water or liquid horsepower is the pump efficiency. The requirement in either case is the horsepower input to the shaft of the pump. For that reason, the brake horsepower represents the power required by the pump, which must be transmitted from the driver through the drive shaft through any coupling, gearbox, and/or belt drive mechanism to ultimately reach the driven shaft of the pump. Therefore, the losses in transmission from the driver to the pump itself must be added to the input requirement of the driven pump and are not included in the pump’s BHP requirement.



Pump efficiency [8] =



Overall efficiency [8] =

LHP (energy delivered by pump to fluid ) BHP (energy to pump shaft)

(16.45)

WHP (energy delivered by pump to fluid ) EHP (energy supplied to input side of pump ' s driver )

(16.46)

Pumps  403 where EHP = electrical horsepower WHP = liquid horsepower For the rising type characteristic curve, the maximum BHP required to drive the pump over the entire pumping range is expressed as a function of the BHP at the point of maximum efficiency for any particular impeller diameter [18].



BHP (max.) = 1.18 (BHP at max. efficiency point)

(16.47)

Unless specifically identified otherwise, the BHP values read from a manufacturer’s performance curve represent the power only for handling a fluid of viscosity about the same as water and a specific gravity the same as water; i.e., SpGr = 1.0. To obtain actual horsepower for liquids of specific gravity other than 1.0, the curve values must be multiplied by the gravity referenced to water. Viscosity corrections are discussed in another section. Good design must allow for variations in these physical properties.

Example 16.16 3.5 m3/h water at 328 K is pumped through a 2-in. Sch. 40 (ID = 52.5 mm) stainless steel pipe, through a length 200 m in a horizontal direction and up through a vertical height of 20 m. In the pipe configuration, there is a control valve equivalent to 200 pipe diameters and other pipe fittings equivalent to 80 pipe diameters. Also in the line is a heat exchanger across which there is a loss in head of 2.5 m of water. What power must be required from the pump if it is 70% efficient?

Solution Viscosity of water at 328 K:  μ = 0.511 × 10−3 Ns/m2 Flow rate = 3.5 m3/h = 9.72 × 10−4 m3/s



Area of flow =



Thus: velocity, v =

πD2 π(52.5 × 10−3 )2 = = 2.16 × 10−3 m 2 4 4 Q 9.72 × 10−4 = = 0.45 m s A 2.16 × 10−3

Reynolds number, Re:

Re =

ρvd µ

(1000)(0.45)(0.0525) (0.511 × 10−3 ) = 46233 (Turbulent) =





Friction factor: Using Chen’s explicit equation (15.35) to calculate the friction factor, fC: Pipe roughness of stainless steel, ε = 0.045 mm

404  Petroleum Refining Design and Applications Handbook Volume 2 Relative roughness is:

ε 0.045 = = 0.00857 D 52.5 ε D  6.7  A= +  3.7  Re 

0.9

 0.00087   6.7  = +  3.7   46233 

0.9

= 5.85895 × 10−4





 ε  5.02 = −4 log  − log A   3.7D Re  fC

1



 0.00087 5.02  log10 (5.85895 × 10−4 ) − = −4 log10  46233  3.7  = 12.92815 fD = 4 fC



= 4 (5.9831 × 10−3)



= 0.02393

Equivalent length of pipe = 200 + (280 × 0.0525) = 214.7 m  L  v2  L  v2  L  v2 Head loss, h f = 4 fF   : = 4fC   = fD    D  2g  D  2g  D  2g

 214.7   0.452  h f = (0.02393)  0.0525   2 × 9.81 

= 1.01 m

Total head to be developed = (1.01 + 10 + 2.5) = 13.51 m  m3 kg  Mass flow rate of water = 9.72 × 10−4 × 1000  . 3   s m  = 0.972 kg/s From Eq. 16.36, the power supplied is: Power supplied = Ghg = (0.972)(13.5)(9.81) = 129 W  100  Power to be required = 129 ×  = 184 W  70 



Pumps  405

Driver Horsepower The driver horsepower must be greater than the calculated (or value read from curves) input BHP to the shaft of the pump. The mechanical losses in the coupling, V-belt, gearbox, or other drive plus the losses in the driver must be accounted for in order that the driver-rated power output will be sufficient to handle the pump. Best practice suggests the application of a non-overloading driver to the pump. Thus a motor rated equal to or greater than the minimum required BHP of the pump, assuming no other power losses, would be non-overloading over the entire pumping range of the impeller. It is important to examine the pump characteristic curve and follow the changes in power requirements before selecting a driver. For example, referring to Figure 16.21a, if your pump were selected with a 6.in. diameter impeller for a rated normal pumping of 100 gpm, the pump would put out about 138 ft of head of any fluid (neglecting viscosity effects for the moment). The intersection of the 100-gpm vertical line with the 6-in. performance curve would indicate that 5.75 BHP would be required for water (between 5 hp and 7.5 hp). Therefore, to be non-overloading (that is, the motor driver will not overheat or lose power) at this condition would require a 7.5 hp motor (if no other losses occur between driver and pump), because there is no standard motor for direct connected service between the standard 5 and 7.5 hp. Now (1) if you know or project that you may need at some time to pump 160 gpm of any fluid with this pump at 160 ft head, then this pump could not be used because it will not physically take an impeller larger than 6.5-in. diameter. However, recognizing this, (2) if you change the external physical piping, valves, and so on, and reduce the head to fit the 6.5-in. impeller curve, at 160 gpm, you could handle 152 ft head (estimated from the curve for a 6.5-in. impeller). This condition would require a BHP from the pump curve between 7.5 and 10, that is, about 9.25 BHP for the pump’s input shaft (for water calculates at 9.03 BHP), estimating the spread between 7.5 and 10. Thus a 10 hp (next standard size motor) would be required, and this would satisfy the original condition and the second condition for water. It would still be satisfactory for any fluid with a specific gravity < 1.0, but if pumping a liquid of 1.28 SpGr (e.g., ethyl chloride), then (1), the original BHP would need to be 1.28 (5.75) = 7.36 BHP, and (2), the second condition would require 1.28(9.25) = 11.84 BHP (calculates 11.56). Whereas, a 10-hp motor would be non-overloading for the water pumping case, it would require a 15-hp (next standard above a 10 hp) motor direct drive to satisfy the ethyl chloride case under the 160 gpm condition. If you do not select a non-overloading motor, and variations in head and/or flow occur, the motor could overheat and stop operating. Study the pump-capacity curve shape to recognize the possible variations. Important note: Any specific pump impeller operating in a physical (mechanical) system will only perform along its operating characteristic curve. If there is a change in the system flow characteristics (rate or friction resistance or pressure head), the performance will be defined by the new conditions and the pump performance will “slide” along its fixed curve. Thus, the designer cannot arbitrarily pick a point and expect the pump to “jump” to that point. Refer to Figure 16.21a. Using a 6-in. impeller curve, for example, the designer cannot make this pump operate at a point of 100 gpm and 150 ft head. This would require about a 6¼-in. diameter impeller. The 6-in. curve will only put out 138 ft (approx.) at the intersection of 100 gpm and the 6-in. curve. A driver selected to just handle the power requirements of the design point (other than maximum) is usually a poor approach to economy. Of course, there are applications where the control system takes care of the possibilities of power overload.

16.20 Affinity Laws The affinity laws can be employed to estimate pump performance at off – design conditions. These relationships are based on the assumptions that pump efficiency is independent of speed n (which is mostly true for speeds greater than 50% of the maximum speed) and impeller diameter d (most true for diameters greater than 80% of the maximum diameter, dmax) and that the original pump design was close to the BEP. As the impeller diameter is reduced below 0.8dmax in the same casing, efficiency at the same speed falls off rapidly. Engineers can use the affinity laws with reasonable confidence to estimate the performance of a pump when the original impeller is trimmed < 15%, e.g., when a 12-in. impeller diameter is trimmed to 11 in. or 10.5 in based on the pump curve provided by the manufacturer at the time of purchase [35].

406  Petroleum Refining Design and Applications Handbook Volume 2 The affinity laws relate the performance of a known pump along its characteristic curve to a new performance curve when the speed is changed. This would represent the same “family” of pump curves. As an example, see Figures 16.21a–c. 1. F  or change in speed with a geometrically similar family of fixed impeller design, diameter and efficiency, the following conditions and characteristics change simultaneously [10]:



n  Q 2 = Q1  2   n1 



n  H 2 = H1  2   n1 



H2  Q 2  = H1  Q1 



Q  H 2 = H1  2   Q1 



n  (BHP)2 = (BHP)1  2   n1 

(16.52)



d  Q 2 = Q1  2   d1 

(16.53)



d  H 2 = H1  2   d1 

(16.48)

2

(16.49)

2

(16.50) 2

(16.51) 3

for a fixed speed [10]

2

(16.54) 3



d  (BHP)2 = (BHP)1  2   d1 

(16.55)

For geometrically similar impellers operating at the same specific speed, the affinity laws are [10, 14]: 3



Q2  n 2   d2  = Q1  n1   d1  2



(16.56)

2

H2  n 2   d 2  = H1  n1   d1 

(16.57)

Pumps  407 3

5

BHP2  n 2   d 2  = BHP1  n1   d1 



(16.58)

where subscript (1) represents the condition for which a set of conditions are known and subscript (2) represents the new non-cavitating or desired condition. There relations do not hold exactly if the ratio of speed change is greater than 1.5 to 2.0, nor do they hold if suction conditions become limiting, such as NPSH. Figure 16.53 illustrates the application of these performance laws to the 1750 rpm curves (capacity, BHP, and efficiency) of a particular pump to arrive at the 1450 rpm and 1150 rpm curves. Note that the key value is the constant efficiency of points (1) and (2). When the speed drops to 1450 rpm, capacity drops:

 1450  Q 2 = 204  = 169 gpm  1750 





Efficiency vs Capacity

50 40

Efficiency, %

1

2

14

175

0 rp m 50 rp 11 m 50 rp m

60

30 20 100

17

50

90

rp

m

80

14

50

60

m

50 115

40

2 0 rp m

1

30 1750

20

0

40

80

7.5

rpm

1450 rpm 1150 rpm

10 0

Head vs Capacity

1

rp

120

Brake Horsepower vs Capacity

2

160

Capacity, gpm

Figure 16.53  Relation of speed change to pump characteristics.

200

240

280

5 2.5 0

Brake Horsepower

Head in Feet

70

408  Petroleum Refining Design and Applications Handbook Volume 2 The head also drops: 2

 1450  H 2 = 64  = 44 fts  1750 





and 3



 1450  (BHP)2 = 6.75  = 3.84 BHP  1750 



d = diameter of impeller (ft, m) n = rotational speed (rpm, l/s) H = output head (ft, m) Q = volumetric discharge (gpm, m3/s) BHP = brake horse power (bhp, kW) 2. For changes (cut-down) in impeller diameter (not design) at fixed efficiency [14]



 n d  Q 2 = Q1  2   2   n1   d1 



n  d  H 2 = H1  2   2   n1   d1 



n  d  BHP2 = BHP1  2   2   n1   d1 

2

(16.59)

2

3

(16.60)

3

(16.61)

where d1 is the original impeller diameter in inches, and subscript (1) represents the condition for which a set of conditions are known and subscript (2) designates the new or desired conditions corresponding to the new impeller diameter d2. All performance changes occur simultaneously when converting from condition (1) to condition (2), no single condition can be true unless related to its corresponding other conditions. An impeller can be cut from one size down to another on a lathe, and provided the change in diameter is not greater than 20%, the conditions of new operation can be described by the type of calculations above. A cut to reach 75–80% of the original diameter may adversely affect performance by greatly lowering the efficiency [12]. Most standard pump curves illustrate the effect of changing impeller diameters on characteristic performance (Figure 16.21a). Note: change as reflected in the different impeller diameters. However, the slight change in efficiency is not recorded over the allowable range of impeller change. Recognizing the flexibility of the affinity laws, it is better to select an original pump impeller diameter that is somewhat larger than required for the range of anticipated performance, and then cut this diameter down after in-service tests to a slightly smaller diameter. This new performance can be predicted in advance. Once the impeller diameter is too small, it cannot be enlarged. The only solution is to order the required large impeller from the manufacturer.

Pumps  409

Example 16.17: Pump Parameters For a centrifugal pump handling water, its manufacturer supplied the following data at 1150 rpm. Pump output = 60 m3/h Head developed = 50 m Power requirement = 12 kW Assuming that density of water is 1000 kg/m3, determine the pump efficiency head, output and power consumed at n = 1400 rpm taking into account that efficiency remains constant.

Solution Using Eq. (16.40), the pump hydraulic power output is

(ρ)(Q )(H) , kW 367 × 103 (1000)(60)(50) PQ = = 8.17 kW 367 × 103 PQ =





Pump efficiency e is

Power sup plied PQ (ρ)(Q )(H) 8.17 = = = Power required P 12 367 × 1003 = 0.68

e=



Head, output and power: Head, H2:

H2  n 2  = H1  n1 

2

2

 1400  n  H2 = H1  2  = 50   1150   n1 



2

= 74.1 m



Output, Q2

Q2  n2  = Q1  n1 

 1400  n  Q 2 = Q1  2  = 60   1150   n1  = 73.04 m3/h





410  Petroleum Refining Design and Applications Handbook Volume 2 Power consumed, BHP2

BHP2  n 2  = BHP1  n1 

3

3

 1400   1400  BHP2 = BHP1  = 12    1150   1150 



= 21.65 kW

3



Example 16.18: Specific Speed, Flow Rate, and Power Required by a Pump A centrifugal pump is required to deliver 1600 ton/h of water against a head of 30 m while operating at its maximum operating efficiency. Determine its specific speed if its driven at 20 Hz. If the same pump is operating at maximum efficiency under these conditions delivers at a head of 50 m, what should be its speed and its rate of discharge? Determine the power requirement of the pump if its overall efficiency is 75% while operating under the same operating conditions.

Solution Density of water = 1000 kg/m3 1 ton = 1000 kg. Specific speed by Eq. 16.30

 n Q  Ns =  0.75   (gH) 

Mass rate, G = 1.6 × 106 kg/h Volume flow rate, Q =





Mass Density

Q=

1.6 × 106 = 0.44 m3 s 3 (10 × 3600)

 20 0.44  = 0.187 Hz Ns =  0.75   (9.81 × 30) 

Speed: 2

or

H2  n 2  = H1  n1 

Pumps  411

n 2  H2  = n1  H1 

0.5

H  n 2 = n1  2   H1 

0.5

 50  = 20    30 

0.5

= 25.82 Hz





Rate of discharge, Q: Also Q α n

Q2 n2 = Q1 n1  25.82  n  Q 2 = Q1  2  = 0.44   20.0   n1  = 0.5568 m3/s (2044.8 m3/h )





Power required P is calculated using Eq. 16.40

(1000)(2044.8)(50.0) (0.75 × 367 × 103 ) = 371.4 kW

PQ =



Example 16.19: Ethylene Product Pump Consider an ethylene product pump under the following process conditions [24]: Rated flow, m3/h Rated suction pressure, kPag Discharge pressure, kPag Differential pressure, kPa Specific gravity Head, m (10.2 × ∆P, bar)/Sp.Gr NPSHA, m

= 400 = 1600 = 5700 = 4100 = 0.46 = 909 = 7.2

The specific speed, nq is:



nq =

nQ 0.5 ∆Η 0.75

(16.62)

412  Petroleum Refining Design and Applications Handbook Volume 2 where nq = specific speed Q = volumetric flow rate, m3/s ∆H = head, m n = pump speed, rpm. and in English units,



Ns =

nQ 0.5 ∆Η 0.75

(16.63)

nq =

Ns 51.64

(16.64)

where Q = flow rate, gal/min. ∆H = head, ft n = pump speed, rpm The relationship between nq and Ns is:



First determine the number of stages required assuming that each stage produces the same head and that a specific speed of Ns ≈ 1,100 (nq ≈ 21.3) is desired. Assume a shaft speed of 3,600 rpm, the head per stage is:

n Q  H stg =    nq 



4 /3

0.5   400 3    3, 600 rpm  m s   3, 600    =    1100      51.64  

4 3

= 216 m stage

The number of stages is calculated by dividing the total head required, 909 m by 216 m/stage and round up to the next highest integer gives 5 stages. Each produces 181.8 m/stage (i.e., head/no. of stages). The specific speed is then:

Ns =

51.64 n Q H3 4

 400 m3  51.64 × 3, 600 rpm ×   3, 600 s  = (181.8)0.75

0.5



(16.65)

= 1252

This is sufficiently close to the desired value of 1100. The size of the impeller can be approximated based on the impeller tip speed:

Pumps  413



H≈

(r Ω)2 2g

(16.66)

r≈

2gH Ω

(16.67)

d≈

2 2gH Ω

(16.68)

or

and

where d = diameter of the impeller, m r = radius of the impeller, m Ω = angular velocity, rad/s

(

2 181.8 m × 2 × 9.81 m s 2 d=  2 π rad   3, 600 ×  60 s 

)

0.5

= 317 mm





Since an NPSH margin of at least 1 m is desired, the assume NPSHR = 6.2 m The suction specific speed is an index describing the suction capabilities of a first stage impeller and can be calculated using Eq. 16.69. Use half of the flow for double suction impellers. The suction specific speed Nss is:

N ss =

N Q 51.64 n Q = 0.75 NPSHR NPSHR0.75

 400 m 3  51.64 × 3, 600 rpm ×   3, 600 s  = (6.2 m)0.75



0.5



(16.69)

= 15, 772

This is too high; therefore the suction speed for a double-suction style pump is calculated based on one-half of the total flow:

 200 m 3  51.64 × 3, 600 rpm ×   3, 600 s  (6.2 m)0.75

This is acceptable.

0.5

= 11,152



414  Petroleum Refining Design and Applications Handbook Volume 2 A pump supplier identifies a pump with the following specifications as being suitable for this application: number of stages =5 double suction? Yes rated impeller diameter = 318 mm = 5.2m NPSHR suction specific speed, Nss = 11,657 efficiency = 79.2% minimum flow rate = 193.7 m3/h shutoff head = 997.2 m Pumps with high suction speed tend to be susceptible to vibration (which may cause seal and bearing problems), when they are operated at other than design flow rates. As a result, some users restrict suction specific speed and a widely accepted maximum is 11,000. This exercise shows the importance of close coordination between the rotating equipment engineer and the process engineer throughout the design and specification phases of a project. Understanding the concept illustrated in this example and chapter enables the designer/process engineer to take on the task of adequately selecting a pump.

c

13.5 psi

Heater EI.,

48

ft

13

Suction drum

10

psi

ft

5f 15.

El., 1-in 4-in 10

4 ft

ft

2

30

dia 8-in

c

3 ft

Discharge vessel

r ate He

ft

.

1

EI.,

2f

Orifice

t

c

∆P

si .2 p

=5

El.,

4-i

nS

12

ch

1.5

10 EI.,

12

. 40

6- i n

5 ft

Sch 15

ft

ft

ft

4-in Control valve EI.,

t

. 40

ft

ft

ion uct t 5f , 1. n io vat Ele

S 4-in 3-in discharge

c

c Pump

Figure 16.54  Piping and equipment layout for the suction and discharge lines to the process pump (source: Kern, Robert, Chem. Eng., May 26, 1975).

Pumps  415

Example 16.20: Pump Sizing of Gas–Oil A centrifugal pump having a 4 in. nozzle and a 3 in. discharge nozzle will handle gas oil at a normal flow rate of 250 gpm through a piping and component system as described below (source: Kern, Robert, Chem. Eng., May 26, 1975). What is pump power requirement from Figure 16.54? Specific gravity and density are: = 1.18 Specific gravity, S60 = 73.6 lb/ft3. Density of gas oil, ρ60 Vapor pressure at operating temperature = 4.0 psia At flowing conditions, temperature T = 555°F Specific gravity SpGr = 1.04 Density of gas oil ρ = 64.87 lb/ft3 Viscosity of gas oil = 0.6cP The data for the suction and discharge sides are: Suction condition

Discharge condition

Nominal size, in.

6

Nominal size, in.

4

Inside diameter, in.

6.065

Inside diameter, in.

4.026

Pressure at equipment, psig

13.0

Pressure at equipment, psig

13.5

Static head, psi

5.403

Static head, psi

20.94

Pipe length, ft

39

Pipe length, ft

156

5 short radius elbows, ft

75

20 short radius elbows

210

1× Gate valve, ft

6.5

4× Gate valves

18

1 Reducer, ft

4.0

1 Reducer

3

1 Strainer, ft

30.0

1 Inlet

10

1 Inlet to pipe, ft

18.0

2 Exits

40

Total equivalent length, ft

172.5

Line loss ΔP, psi

0.26

437

Line loss ΔP, psi

4.89

1× Control valve, psi

10.71

Exchanger ΔP, psi

5.2

Orifice ΔP, psi

1.52

Solution The Excel spreadsheet (Example 16.20.xlsx) is developed to determine the estimated absolute power requirement for the sizing the gas oil centrifugal pump. Figure 16.55 shows the spreadsheet results of the pump sizing calculation for example 16.20, with an estimated pump efficiency of 70%. The power requirement for the design rate of 275 gpm is 8.64 hp.

416  Petroleum Refining Design and Applications Handbook Volume 2 A.K.C. TECHNOLOGY

PUMP CALCULATION SHEET Document No. Sheet of Item No. (s) No. Working Worki k ng

Job Item Name.

UNITS 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62

Liquid Pumped Corrosion/Erosion Due To Operating Temp. (T) Specific f Gravity at T Viscosity Vapor Pressure at T Normal mass Flowrate Normal Vol. Flowrate Min. Vol. Flowrate Design Vol. Flowrate SUCTION CONDITION Pressure at Equipment (+) Static Head (+/-) Total - Lines 14 + 15 P Suction Line (-) Filter/StrainerP (-)

Gas-oil

Gas-oil

555 1.04 0.6 4 130102.51 250

555 1.04 0.6 4 143111.42

F

m3/h

gpm

barg bar bar bar bar

psi g psi psi psi psi

13 6.3 19.3 0.26

13 6.3 19.3 0.26

bar g

psi g

19.04

19.04

bar g bar

psi g psi

13.5 20.94

13.5 20.94

P

bar

psi

5.2

5.2

P

bar bar bar

psi psi psi

1.52 10.71

1.52 10.71

bar

psi

4.89

4.89

bar g bar m

psi g psi fft.. ft

56.76 37.72 83.78

56.76 37.72 83.78

bar a psi a bar a psi a bar a psi a m fft.. ft m ft. f. ft m f. ft ft. kW k hp % % k hp kW Centrifu f gal Centrifugal

33.74 4 29.74 66.06

33.74 4 29.74 66.06

P

Total Discharge Press (+). Differe f ntial Pressure Differential Differe f ntial Head Differential NPSH Total Suction Pressure Vapor Pressure NPSH= Lines 37 - 38 = Safe f ty Margin Safety NPSH = Lines 40-41 Hydraulic Power Estimated Efficiency Effici f ency Estimated Abs. Power Type of Pump Drive

Total No. off f SKETCH OF PUMP HOOK-UP

o

cP psi a lb/h gpm

Furnace (+) Orifice Orific f e (+) P Control ValveP (+) Line loss (+)

C

CASE II

cP bar a kg/h 3 m /h

Total Suction Pressure (+) DISCHARGE CONDITION Pressure at Equipment (+) Static Head (+/-) Exchanger (+)

o

CASE I

Rev.

275

NOTES 1. Pum Pump ump shutshut-ff u ff head not to exceed……… 2. Relief valve on pump discharge to be set at 3. Pum Pump ump case design pressure pressure………… u ………… design temp m eratu ture…….. temperature……..

5.5 70 7.86

6.05 70 8.64

4. Sealing/flushing Sealing/fl f ushing fl ffluid uid available: 5. Cooling medium available: 6. Insulation required:

Material - Casing - Impeller -Shaft f

7. Start-up/commissioning fl ffluid uid SG.

Sour Service Yes/No m == 10.2 10.2 x bar /SpGr m == 10 10 x kg/cm2 / SpGr ft f = 2.31 x psi / SpGr HEAD m VOLUME m3/h x SpGr x 1000 = kg/h USgpm x SpGr x 600 = lb/h 3 3 2 k kW=m /h x ba kW=m k /h x kg/cm /36.71 POWER Hp = USgpm x psi/1714 3 Date 4 Date 1 Date 2 Date Description Made/Revised by Checked by Approved Process Approved

Figure 16.55  Pump sizing calculation of Example 16.20.

HP=Usgpm*head, ft f *SpGr/3960 5 Date

Pumps  417

Example 16.21: Debutanizer Unit of Example 15.2 What is the required power of pump P1017A for the controlled reflux rate of 1235.52 tons/day (106.56 m3/h) (see Figure 15.23)? Density of condensate, ρ = 488 kg/m3. Vapor pressure at operating temperature = 14.17 bara At flowing conditions, temperature T = 57°C Specific gravity, SpGr = 0.488 Viscosity of condensate = 0.112cP The data for the suction and discharge sides are: Suction condition

Discharge condition

Pressure at Equipment, barg

13.9

Pressure at equipment, barg

13.7

Static head, bar

0.335

Static head, bar

2.057

Line loss ΔP, bar

0.0128

Line loss ΔP, bar

0.447

Filter/Strainer ΔP bar

0

Exchanger ΔP, bar Furnace ΔP, bar Orifice ΔP, bar

Solution The Excel spreadsheet (Example 16.21.xlsx) is developed to determine the estimated absolute power requirement for sizing the reflux LPG centrifugal pump P1017A/B. Figure 16.56 shows the spreadsheet results of the pump sizing calculation for Example 16.21, with an estimated pump efficiency of 70%. The absolute pump power is 8.4 kW.

16.21 Centrifugal Pump Efficiency The design engineer must use the expected pump efficiency provided in the pump performance curve to evaluate the required BHP for a centrifugal pump. In the early stages of the design, it is customary to estimate a value for the efficiency. Final values depend on the specified pump, and at the operating conditions that are encountered. Branan [19] has developed an equation to calculate the centrifugal pump efficiency and pump horsepower. The equation was based on pump efficiency curves of the Natural gas transmitting pipeline safety act (NGPSA) Engineering Data Book. These efficiency curves give good results with the vendor data (the range of developed heads, 50–300 ft, and the flow rates, 100–1000 gpm). The equation for calculating the pump efficiency is expressed as follows:

EFF = (80 − 0.2855H + 3.78 × 10−4 HQ −2.38 × 10−7 HQ 2 + 5.39 × 10−4 H 2

 1  −6.39 × 10−7 H 2 Q + 4 × 10−10 H 2 Q 2 )  100 



(16.70)

418  Petroleum Refining Design and Applications Handbook Volume 2 A.K.C. TECHNOLOGY

PUMP CALCULATION SHEET Document No. Sheet of Item No. (s) No. Working

Job Item Name.

UNITS

CASE I

1 2 Liquid Pumped 3 Corrosion/Erosion 4 Due To Operating Temp. (T) Specific Gravity at T Viscosity Vapor Pressure at T Normal mass Flowrate

56 57 58 59 60 61 62

C

F

cP bar a kg/h m3/h

cP psi a lb/h gpm

106.56

m3/h

gpm

barg bar bar bar bar

psi g psi psi psi psi

13.9 0.335 14.235 0.0128 0

13.9 0.335 14.235 0.0128 0

Total Suction Pressure (+) bar g DISCHARGE CONDITION Pressure at Equipment (+) bar g Static Head (+/-) bar

psi g

14.222

14.222

psi g psi

13.7 2.057

13.7 2.057

Design Vol. Flowrate SUCTION CONDITION Pressure at Equipment (+) Static Head (+/-) Total - Lines 14 + 15 P Suction Line (-) Filter/Strainer (-) P

Exchanger (+)

0.488 0.112 14.17 57201

117.216

P

bar

psi

0

0

P Furnace (+) P Orifice (+) Control Valve (+)

bar bar bar

psi psi psi

0 0 0

0 0 0

bar

psi

0.447

0.447

bar g bar m

psi g psi ft.

16.204 1.982 41.43

16.204 1.982 41.43

bar a psi a bar a psi a bar a psi a m ft. m ft. m ft. kW Hp % % kW Hp Centrifugal

15.235 14.17 1.065 22.26

Line loss (+)

SKETCH OF PUMP HOOK-UP

o

57 0.488 0.112 14.17 52000

10 Normal Vol. Flowrate 11 Min. Vol. Flowrate 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55

Total No. off

LPG

o

5 6 7 8 9

CASE II

Rev.

P

P

Total Discharge Press (+). Differential Pressure Differential Head NPSH Total Suction Pressure Vapor Pressure NPSH - Lines 37 - 38 = Safety Margin NPSH - Lines 40-41 Hydraulic Power Estimated Efficiency Estimated Abs. Power Type of Pump Drive

5.87 70 8.39

NOTES 15.235 1. Pump shut-ff head not to exceed……… 14.17 1.065 2. Relief valve on pump discharge to be set at …………… 22.26 3. Pump case design pressure………… de sign temperature…….. 6.45 70 4. Sealing/flushing fluid available: 9.21 5. Cooling medium available: 6. Insulation required:

Material - Casing - Impeller -Shaft

7. Start-up/commissioning fluid SG.

Sour Service Yes/No HEAD m = 10.2 x bar /SpGr m = 10 x kg/cm2 / SpGr ft = 2.31 x psi / SpGr VOLUME m3/h x SpGr x 1000 = kg/h USgpm x SpGr x 600 = lb/h kW=m3/h x bar/36.0kW=m3/h x kg/cm2 /36.71 POWER Hp = USgpm x psi/1714 1 Date 2 Date 3 Date 4 Date Description Made/Revised by Checked by Approved Process Approved

HP=USgpm*head,ft*SpGr/3960 5 Date

Figure 16.56  Pump sizing calculation (metric units) for reflux LPG centrifugal pump of Example 16.21.

Pumps  419 The actual Bhp required for pump operation is:



Bhp = Hp/EFF

(16.71)

where EFF = Pump efficiency (decimal fraction). H = Developed pump head, ft. Q = Flow rate through pump, gpm. Hp = Hydraulic brake horsepower, hp. Bhp = Actual brake horsepower required for pump operation, hp. A system resistance curve for the pump suction and discharge system configuration can be fixed by using the pump affinity laws in Eqs. 16.50 and 16.51, respectively. This procedure does not include any superimposed change in system resistance using methods such as manual valve pinching or control valve throttling. The point at which the system curve and the pump curve (pump head) is the operating point or duty point of the pump. To obtain the pump efficiency, power, and NPSH at the duty point, a vertical line is drawn at this point until it intersects these curves; horizontal lines are drawn to the vertical axis of these curves, which correspond to efficiency, power and NPSH. Using Eqs. 16.70, 16.50, and 16.51, Figure 16.57 shows typical characteristic curves for a 6-in. centrifugal pump operating at 1750 rpm. Eq. 16.70 gives results within 7% of the actual pump curves for the range of applicability (H = 50–300 ft, Q = 100–1000 gpm). For flows in the range of 25–99 gpm, an approximate efficiency can be obtained by solving Eq. 16.71 for 100 gpm and then subtracting 0.35% gpm times the difference between 100 gpm and the low flow rate in gpm. For low flow rates, near 25–30 gpm, this will give results within about 15% for the middle of the head range (pump ΔP) and 25% at the extremes. The horsepower at the 25–30 gpm level is normally below 10 [19]. The Excel spreadsheet program from the Scrivener-Wiley website (Pump-efficiency.xls) has been developed to determine the system curve, pump efficiency, hydraulic Bhp and actual Bhp for pumps at varying flow rate and developed head. Figures 16.57 and 16.58, respectively, show the plots for a 6 in. impeller at 1750 rpm and an 8 in. impeller at 1450 rpm. 180 160

Head, Eff, hp, Bhp, System curve

140 120 Pump Head, ft 100

Pump efficiency, Eff Hydraulic horsepower, hp

80

Brake horsepower, Bhp System curve

60 40 20 0 0

100

200

300

400

500

600

700

800

900

1000

Flow rate, Q (gpm)

Figure 16.57  Pump efficiency calculation at varying flow rate for a 6-in. impeller centrifugal pump at 1750 rpm.

420  Petroleum Refining Design and Applications Handbook Volume 2 200 180 160

Head ft, Eff, hp, Bhp, System curve

140 120

Pump head, H (ft) Pump efficiency, Eff

100

Hydraulic horsepower, hp Brake horsepower, Bhp

80

System curve

60 40 20 0 0

100

200

300

400

500

600

700

800

900

1000

Flow rate, Q (gpm)

Figure 16.58  Pump efficiency calculation at varying flow rate for an 8-in. impeller centrifugal pump at 1450 rpm.

Example 16.22: Reducing Impeller Diameter at Fixed RPM If you have a non-cavitating (sufficient NPSH) operating 9-in. impeller producing 125 gpm at 85 ft total head pumping kerosene of SpGr = 0.8 at 1750 rpm using 6.2 BHP (not motor nameplate), what diameter impeller should be used to make a permanent change to 85 gpm at 60 ft head, at the same speed? By using Eq. 16.53



d  85 = 125  2   9



d2 = 6.1 in. diameter (new) The expected head calculated using Eq. 16.54 is



 6.1  H 2 = 85    9 

2



= 39.0 ft (must check system new total head to determine if it will satisfy this condition.) The expected brake horsepower BHP calculated using Eq. 16.55 is

Pumps  421

 6.1  BHP2 = 6.2    9 



3



             = 1.93 BHP (use a 2- or 3-hp motor)

16.22 Effects of Viscosity When viscous liquids are handled in centrifugal pumps, the brake horsepower is increased, the head is reduced, and the capacity is reduced as compared to the performance with water. The corrections may be negligible for viscosities in the same order of magnitude as water, but become significant above 10 cSt (10 cP for SpGr = 1.0) for heavy materials. While the calculation methods are acceptably good, for exact performance charts test must be run using the pump in the service. When the performance of a pump handling water is known, the following relations are used to determine the performance with viscous liquids [8]:

Qvis = CQ(Qw)

(16.72)

Hvis = CH(Hw)

(16.73)

Evis = CE(Ew)

(16.74)

BHPvis =



(Q vis )(H vis )(SpGr ) 3960(E vis )

(16.75)

Determine the correction factors from Figures 16.59a–c and Figure 16.58, which are based on water performance because this is the basis of most manufacturer’s performance curves (except, note that the “standard” manufacturer’s performance curves of head vs. gpm reflect the head of any fluid, water, or other non-viscous). Do not extrapolate these curves! Referring to Figure 16.59a–c [8]: 1. Th  e values are averaged from tests of conventional single-stage pumps, 2–8 in., with capacity at best efficiency point (BEP) of less than 100 gpm on water performance. 2. Tests use petroleum oils. 3. The values are not exact for any specific pump. Referring to Figure 16.60 [8]: 1. T  ests were on smaller pumps, 1-in. and below. 2. The values are not exact for any specific pump. The charts are to be used on Newtonian liquids, but not for gels, slurries, paperstock, or any other non-uniform liquids [8]. Figures 16.59a–c and 16.60 are used to correct the performance to a basis consistent with the conditions of the usual pump curves. In order to use the curves, the following conversions are handy:

422  Petroleum Refining Design and Applications Handbook Volume 2 Centistokes (cSt) = centipoises (cP)/SpGr SSU = Saybolt Seconds Universal = (cSt) (4.620) at 100°F = (cSt) (4.629) at 130°F = (cSt) (4.652) at 210°F

Example 16.23: Pump Performance Correction for Viscous Liquid When the required capacity and head are specified for a viscous liquid, the equivalent capacity when pumping water needs to be determined using Figure 16.59a or 16.60 in order to rate pump selection from manufacturer’s curves. Determine proper pump selection and specifications when pumping oil with SpGr of 0.9 and viscosity of 25 cP at the pumping temperature, if the pump must deliver 125 gpm at 86 ft total head (calculated using the viscous liquid). Viscosity conversion:

cSt = 25/0.9 = 27.8

Referring to Figure 16.59a: 1. E  nter capacity at 125 gpm, follow vertically to 86 ft of head, then to right to viscosity of 27.8 cSt, and up to correction factors: Efficiency, CE = 0.80 Capacity, CQ = 0.99 = 0.96 (for 1.0 QN), Head, CH = head at best efficiency point QN Note: This represents a flow rate using water under maximum efficiency conditions [8]. 2. Calculate approximate water capacity:



Qw =

Q vis 125 = = 126.3 C Q 0.99

Hw =

H vis 86 = = 89.6 ft C H 0.96

(16.76)

3. Calculate approximate water head:



4. A  pump may now be selected using water as the equivalent fluid with capacity of 126.3 gpm and head of 89.6 ft. The selection should be made at or very near to the point (or region) of peak performance as shown on the manufacturer’s curves. 5. The pump described by the curves of Figure 16.21 fits these requirements. The peak efficiency is 71% using water. 6. Calculate the viscous fluid pumping efficiency:

Evis = Ce(ew) = (0.8)(71) = 56.8% 7. Calculate Brake Horsepower for viscous liquid

(16.74)

Pumps  423

BHPvis = =

Q visH vis (SpGr ) 3960(E vis ) (125)(86)(0.9) = 4.3 BHP 39960(0.568)



(16.75)

Example 16.24: Corrected Performance Curves for Viscosity Effect When a pump performance is defined for water, the corrected performance for a viscous fluid can be developed using Figure 16.59a or 16.60. In order to develop the curves for viscosity conditions of 100 SSU or 1,000 SSU as shown in Figure 16.61, the following general procedure is used [8]. 1. S tarting with performance curve based on pumping water: a) Read the water capacity and head at peak efficiency. This capacity is the value of (1.0 QnW). b) Using this value of gpm, calculate 0.6, 0.8, and 1.2 times this value, giving 0.6, 0.8, and 1.2 QnW, respectively, and read the corresponding heads and water efficiencies. 2. Using Figure 16.59 or 16.60 enter gpm at value corresponding to peak efficiency, 1.0 QnW, and follow up to the corresponding head value, Hw, then move to the viscosity value of the liquid, and up to the correction factors CE, CQ, CH. 3. Repeat step 2 using gpm and head values of step (lb). 4. Correct head values:

Hvis = HwCH

(16.73)

5. Correct efficiency values:

Evis = ewCE

(16.74)

6. Correct capacity values:

Qvis = Qw CQ

(16.72)

7. C  alculate the viscous BHP as indicated in the previous example. 8. Plot values as generally indicated on Figure 16.61 and obtain the performance curves corresponding to the viscous liquid conditions.

Example 16.25 Figure 16.62 shows the performance curve of a centrifugal pump operated on water [28]. If the same pump is used for handling oil with a specific gravity of 0.9 and a viscosity of 1000SSU (220cSt) at the pumping temperature, develop the performance curve of the same pump for oil.

Solution Using Figure 16.62 for water, locate the best efficiency point (BEP), it is 170 m3/h. For water with 170m3/h capacity, the pump efficiency is a maximum at 86%. Tabulate capacity, head, and efficiency for 0.6 × 170, 0.8 × 170, and 1.2 × 170 m3/h. From Figure 16.60, at 170 m3/h, the head developed by the pump is 31 m. Using Figure 16.59c, the viscosity correction factor at 170 m3/h capacity is obtained as follows: Draw a vertical line until it intercepts 31 m head. Then a horizontal line along the capacity axis until it intercepts 1000 SSU (220cSt) viscosity parallel lines.

424  Petroleum Refining Design and Applications Handbook Volume 2 PERFORMANCE CORRECTION CHART 100

C H

80 HEAD

0.6 × Qn 0.8 × Qn 1.0 × Qn 1.2 × Qn

60

CORRECTION FACTORS

CQ

80

60

CE

CAPACITY AND EFFICIENCY

100

40

20 00 33 00 22 0 6 17 20 13

8 88 0 66 0 44 0 33

0 22 6 17 2

13

43

88 65

32

20 15

10

CENTISTOKES

HEAD IN FEET

(FIRST STAGE)

600 400 300 200 150 100 80 60 40

10

15

20

0 00 15 0 00 10 0 0 80 00 60 00 40 00 30 00 20 00 15 00 10 0 80 0 60

8

0 40 0 30

6

0

4

0 20 0 15

2

10 80

1

60

VISCOSITY-SSU

40

600 400 300 200 150 100 80 60 40 30 20 15

40

60

80 100

CAPACITY IN 100 GPM

Figure 16.59a  Viscosity performance correction chart for centrifugal pumps. Note: Do not extrapolate. For centrifugal pumps only, not for axial or mixed flow. NPSH must be adequate. For Newtonian fluids only. For multistage pumps, use head per stage (by permission from Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pumps, 13th ed., Hydraulic Institute, 1975).

Pumps  425 1.00

1.00 CH

Correction Factors

–0.90

–0.90

–0.80

–0.80

–0.70

–0.70

–0.60

–0.60 CO

–0.50

–0.50

CE

–0.40

–0.40

–0.30

–0.30

–0.20

–0.20

–0.10

–0.10

–0.0

–0.0

0 220 0 176

0 132

880

660

330

440

220

176

88

66

43

32

20

15

10

7.4

4.3

132

Viscosity - Centistokes

120 90

100 80 60 50 40

70 55 45 35

30

25 .5 20 17 5 1 12.5 9 7

10 8 6

5 5 4 3.5 3

2.2 2

00

10,0 8,00 0

120 90 70 55 45 35

0 0 4,00

25 20 7.5 1 15 12.5 10 9 8 1

2.5

2

0 2,00

5 4

0

6 4.5 3.5

3,00

Head, m

6,00

100 80 60 50 40 30

3

0

1,50

0

1,00

80 0

60 0

400

300

200

150

10 0

80

60

50

40

Viscosity - SSU

2.5

3

4

5

6

7

8

Capacity, m3/h

Figure 16.59b  Viscosity correction chart (source: Hydraulic Institute, USA).

9

10 11

12 13 14 15

18

20

22

426  Petroleum Refining Design and Applications Handbook Volume 2 100

C H

80 Head

0.6 × QN 0.8 × QN 1.0 × QN 1.2 × QN

60

80

CO

Correction Factors Capacity and Efficiency

100

60 CE

40

20

00 33 00 22 0 6 17 0 2 13 0 88 0 36

0 44 0 33

0 22 6 17 2

88 65

43

32

20 15

10

13

Viscosity - Centistokes

Head, m (first stage)

180 150 125 100 80 60 50 40 28 24 20 16 12

Figure 16.59c  Performance correction chart (source: The Hydraulic Institute, USA).

50

0 00 15 00 100 0 800 0 600

Capacity, qv × 10 m3/h

0 400 0 300

8 9 10 11 13 15 17 19 22 25 30 35 40

0 200 0 150 0

7

100 800 600

6

400 300

3 3.5 4 4.5 5

200 150

2.5

100 80

40

Viscosity - SSU

60

180 150 125 100 80 60 50 40 28 24 20 16 12 10 8 6 5

60 70 80 90 110 130 170190220

Pumps  427 1.00

CH

.90 .80

.60 CQ

.50

CE

CORRECTION FACTORS

.70

.40 Reproduced with permission of

.30

INGERSOLL-RAND COMPANY .20 .10 .0 0 220 0 176

0

880

660

440

330

220

132

176

88

66

43

22

15

20

10

7.4

4.3

132

CENTISTOKES

400 300 200 150 100 80 60 40 30 20 15 10 8 6 000

10, 8,0 00

400 300

6,0 00

200 150 4,0 3,0

40 30

00

HEAD IN FEET

00

100 80 60

20 2,0

15

00

10 8 6

80

90

00 1,5

70

00 1,0 800

600

60

400

50

300

200

40

150

30

80

25

100

20

60

15

50

10

40

VISCOSITY-SSU

100

CAPACITY, GALLONS PER MINUTE (at bep)

Figure 16.60  Viscosity performance correction chart for small centrifugal pumps with capacity at best efficiency point of less than 100 gpm (water performance). Note: Do not extrapolate. For small centrifugal pumps only, not for axial or mixed flow. NPSH must be adequate. For Newtonian fluids only. For multistage pumps, used head per stage (by permission from Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pumps, 13th ed., Hydraulic Institute, 1975).

428  Petroleum Refining Design and Applications Handbook Volume 2 200

15 10 5 0

90

180

80

160

Eff. Water

70

140

Eff. 100 S.S.U

60

120

50

100

40 30

Head in Feet

Brake Horsepower

20

Efficiency, %

100

Head, Water Head, 100 S.S.U Head, 1,000 S.S.U. Eff. 1,000 S.S.U

80

BHP 1,000 S.S.U. at 1.0 sp gr BHP 100 S.S.U. at 1.0 sp gr

60

20

40

10

20

0

BHP Water S.S.U. = Saybolt Sec. Univ.

0 0

100

200

300

400

500

Capacity, gpm

Figure 16.61  Typical curves showing the effect on a pump designed for water when pumping viscous fluids (by permission from Pic-aPump, 1959, Allis-Chalmers Mfg. Co.).

30 25 20

Brake Power Water

15 10 5

36

kW

0.90 SP 1000.SSU

0

1000.S

He

SU

30

ad

Wa ter

100

ter Wa

20

80 Efficiency

70 60

1000 SSU

50 40

10

30 20 10 0

0 0

50

100

150 Capacity, m3/h

Figure 16.62  Sample performance curve.

200

250

Efficiency

Head, m

90

Pumps  429 Then draw a vertical line to the correction factors scale on Figure 16.59c, and read the correction factors at CE, CQ and CH (0.6 × QN, 0.8 × QN, 1.0 × QN, and 1.2 × QN), respectively. CE

= 0.645

CQ

= 0.95

CH

= 0.96 (for 0.6 × QN)

CH

= 0.94 (for 0.8 × QN)

CH

= 0.92 (for 1 × QN)

CH

= 0.895 (for 1.2 × QN)

For 0.6 × QNW calculations QNW = 170 m3/h 0.6 × QNW = 0.6 × 170 = 102 m3/h Using 102 m3/h from Figure 16.62, The head Hw (from head vs. capacity curve for water) = 34.62 m The efficiency ηW (from efficiency vs. capacity curve for water) = 0.76 Viscosity of oil, µ = 220 cSt The corresponding capacity, head, and efficiency are:

Qoil = CQ × QW = 0.95 × 102 = 96.9 m3/h

Hoil = CH × HW = 0.96 × 34.62 = 33.235 m

ηoil = CE × ηW = 0.645 × 0.76 = 0.4902 The power required by the pump when it handles the oil is:



P=

Hoil × Q oil × ρoil 33.235 × 96.9 × 900 = = 16.11 kW 5 (3.67 × 10 × ηoil ) (3.67 × 105 × 0.4902)

Table 16.8 shows the results of the calculations for obtaining the performance curve for oil using Figure 16.59c. Microsoft Excel spreadsheet Example 16.25.xlsx gives the calculations of the revised performance of centrifugal pump for handling oil.

Example 16.26 A 20 in. (508 mm, 10-mm wall thickness) commercial steel pipe is used to transport LPG from a refinery to a storage tank 20 km away. Neglecting any difference in elevations, calculate the friction factor and pressure loss due to friction (kPa/km) at 1000 m3/h. Assume an internal pipe roughness of 0.05 mm. A delivery pressure of 2000 kPa must be maintained at the delivery point, and the storage tank is at an elevation of 250 m above that of the refinery. Calculate the pump pressure required at the refinery to transport the given volume of LPG to the storage tank location. Specific gravity of LPG = 0.5 and viscosity = 0.3 cSt.

430  Petroleum Refining Design and Applications Handbook Volume 2 Table 16.8  Revised performance calculations of centrifugal pump for handling oil (using Figure 16.57c). Capacity

0.6 × QNW

0.8 × QNW

1.0 × QNW

1.2 × QNW

Q, m3/h

102

136

170

204

H, m

34.62

33.21

31

27.3

W

0.76

0.84

0.86

0.85

CQ

0.95

0.95

0.95

0.95

CH

0.96

0.94

0.92

0.895

CE

0.645

0.645

0.645

0.645

Qoil = CQ × QW, m3/h

96.9

129.2

161.5

193.8

Hoil = CH × QW, m

33.325

31.217

28.52

24.434

0.4902

0.5418

0.5547

0.5483

16.11

18.26

20.363

21.18

oil

= CE ×

W

P, kW

Solution

ID = 508 − (2 × 10) = 488 mm

Reynolds number, Re = 1, 273, 000

ρq q = 1273 × 106 × dµ dν

where q = flow rate, m3/s ID = pipe internal diameter, mm ν = fluid viscosity, cSt. µ = fluid viscosity, cP ρ = fluid density, kg/m3 µ = cP = 10-3Pa.s The specific gravity, SpGr :



SpGr =

ρLPG ρH2O



The density of LPG, ρLPG = 0.5 × 1000 = 500 kg/m3 µ(cP) The viscosity, υ(cSt ) = ρLPG

µ = υρLPG = 0.3 × 500 = 150 cP



 1000    × 500 3600 Re = 1, 273, 000 488 × 150 × 1000 6 = 2.42 × 10



Pumps  431 or

Re = 1273 × 106 ×

1000 1 1 × × 3600 488 0.3

= 2.415 × 106





Therefore, the flow is turbulent. Relative pipe roughness, ε/ID = 0.05/488 = 0.000102 Chen’s friction factor, f

 ε  5.02 = −4 log  − log A   3.7 D Re  fC

1



where

A=

ε ID  6.7  +  3.7  Re 

0.9

0.0001  6.7  A= +  2.42 × 106  3.7

0.9

= 3.764 × 10−5





 ε  5.02 = −4 log  − log A  fC  3.7 ID Re 

1



 0.0001  5.02 − log(3.764 × 10−5 ) = −4 log  6 2.42 × 10  3.7  = 17.76 fC = 0.00316 The Darcy friction factor, fD = 4 × Chen friction factor

fD = 4 fC = 0.01267 The pressure drop per 100 m of pipe, ∆p100 is:

∆p100 = 81055 × 107

f D ρ q 2 bar , (ID)5 100m

 1000  0.01267 × 500   3600  = 81055 × 107 (488)5 = 0.01436 bar /100 m

= 1.436 kPa /100 m

2





432  Petroleum Refining Design and Applications Handbook Volume 2 For a one km pipe, the pressure drop is 14.36 kPa. The pressure required at the pumping facility is calculated by adding the pressure drop due to the friction, the delivery pressure required and the static elevation head between the pumping facility and storage tank (all expressed in the same units). Pressure drop due to friction in the 20 km of pipe, Pf = 20 × 14.32 = 286.4 kPa The static head difference is 250 m, therefore the pressure due to elevation, Pelev is:

h(m) × Sp.Gr 10.2 250 × 0.5 = = 12.2549 bar 10.2 = 12225.5 kPa

P( bar ) =





The minimum pressure at the delivery point, Pdel = 2000 kPa Therefore the total pressure required at the refinery PTotal is:

PTotal = Pf + Pelev + Pdel where PTotal = total pressure require at refinery pump Pf = frictional pressure drop Pelev = pressure head due to elevation difference Pdel = delivery pressure at storage tank destination PTotal = 286.4 + 1225.5 + 2000 = 3512 kPa Therefore the pump pressure required at the refinery is 3512 kPa.

Example 16.27 Crude dichlorobenzene is being pumped from a storage tank to a distillation column. The tank is blanketed with nitrogen and the pressure above the liquid surface is held constant at 0.15 barg. The minimum depth of the liquid in the tank is 1.5 m. The distillation column operates at a pressure at 550 Torra. The feed point to that column is 15 m above the base of the tank. The tank and column are connected by a 2 in. (OD = 60.3 mm, 5 mm thickness) diameter commercial steel pipe, 250 m long. The pipe running from that tank to the column contains the following valves and fittings: 25 number of standard radius 90° elbows, two gate valves (fully open), an orifice plate and a flow control valve. If the maximum flow rate required is 25,000 kg/h, calculate the power required by the pump. Pump efficiency is 65%. Pressure drops across the control valve is 0.5 bar. The physical properties of dichlorobenzene are: Viscosity, mPas Density, kg/m3

1.4 1300

Flow meter/valve/elbows 25, Standard radius 90° elbows 2, Gate valves (Fully open) Orifice meter

Equivalent number of velocity heads, K 0.75 0.17 10

Pumps  433

Solution Power required by the pump is:

P=



HQ ρ , kW 3.67 × 105 × e ff

The volumetric flow rate in m3/h is:

Q=



25, 000 m3 = 19.23 1300 h

eff = 0.65 Pump differential head, H is:



H = hd – hs = (p + Zd + hfd) – (p + Zs – hfs) hd = discharge head hs = suction head p = operating pressure in distillation column Zd = static height of discharge hfd = total frictional loss in the discharge line p = pressure at the suction above the liquid surface Zs = static height at suction hfs = total frictional loss in the suction line



1 Torra = 1 mm Hg = 133.32 N/m2 (Pa) The operating pressure in the distillation column, p is:

p = 550 Torra = 73326.0 N/m2 (Pa) In liquid column h (m) is:



h=

10.2 P( bar ) 10.2 × 0.733 = Sp.Gr 1.3

= 5.75 m. LC

Zs = 1.5 m hfs = Assume negligible frictional loss in the suction line ≈ 0 m

h fd =

10.2 ∆PTotal disch arg e ( bar ) ,m Sp.Gr

434  Petroleum Refining Design and Applications Handbook Volume 2 where

 ∆p  ∆PTotal =   L + (∆p)cont . valve + (∆p)elbows+gate valve+orifice  L  frictional loss



The Reynolds number, Re

Re = 354

W 25, 000 = 354 dµ 50.3 × 1.4

= 1.25 × 105 (Turbulent flow)

Relative pipe roughness =

ε 0.045 = = 8.9 × 10−4 d 50.3

Chen friction factor, fC is:

 ε  5.02 = −4 log  − log A  fC  3.7 ID Re 

1 where

ε ID  6.7  A= +  3.7  Re 

0.9

0.00089  6.7  A= +  1.26 × 105  3.7

0.9

= 3.825 × 10−4





 ε  5.02 log A  = −4 log  −  3.7 D Re  fC

1



 0.00089  5.02 − log(3.825 × 10−4 ) = −4 log  5 1.26 × 10  3.7  = 13.6967 fC = 0.0053 The Darcy friction factor, fD = 4 × Chen friction factor

fD = 4 fC = 0.0213 The pressure drop per 100 m of pipe, ∆p100 is:

∆p100 = 62530

f D W 2 bar , (ID)5 ρ 100m

62530 × 0.0213 × 25, 0002 (50.3)5 × 1300 = 1.988 bar /100m =





Pumps  435 For 200 m length of pipe, ∆p = 2 × 1.988 = 3.976 bar = 397,600 N/m2 (Pa)



Pipe area, A =

=            

π(ID)2 , m2 4

π(0.0503)2 = 0.001987 m 2 4

Fluid velocity, v is:

 kg W 25, 000 1 1 h 1 1  = × × × × 2  × ρ A 3600 1300 0.001987  h 3600s kg m    3 m   = 2.688 m/s

v=





2

ρv N , 2 m2 Using the 3-K method of Darby to calculate the resistance coefficient K of the fittings: The pressure drop of fittings, ∆p f (fittings) = K Total

0.3   25.4   Kl  K f = + K i 1 + K d  Re  Dn , mm   





Fitting types

Number

Kl

nKl

Ki

nKi

Kd

Kf

90° elbows

25

800

20,000

0.071

1.775

4.2

7.686

Gave valve

2

300

600

0.037

0.074

3.9

0.3015

Globe valve

1

1500

1500

1.70

1.70

3.6

6.432

Orifice

10.000

Total

24.4195

2             Velocity head = ρv , N2

2

m

1300 × 2.6882 N = = 4696.47 2 2 m ρv 2 N ∆p f (fittings) = K Total , 2 m2

= 24.419 × 4696.47 = 114685.449

N m2



436  Petroleum Refining Design and Applications Handbook Volume 2 The total pressure drop, ΔpTotal is:

ΔpTotal = (Δp)fric.loss + (Δp)fittings

= 397600 + 114685.449



= 512285.449 N/m2 (5.123 bar) Pressure drop in liquid height is:

h=



= Pump differential head, H is:

10.2 ∆pTotal ( bar ) ,m SpGr 10.2 × 5.123 = 40.195 m 1.3

H = h d − h s = ( p′ + Z d + h fd ) − ( p + Z s − h fs ) = (5.75 + 15 + 40.195)) − (9.127 + 1.5 + 0.) = 50.311 m (LC ) Power =



50.311 × 19.23 × 1300 = 5.27 kW 3.67 × 105 × 0.65



16.23 Temperature Rise and Minimum Flow When a pump operates near shut-off (low flow) capacity and head, or is handling a hot material at suction, it may become overheated and create serious suction as well as mechanical problems. To avoid overheating due to low flow, a minimum rate (gpm) should be recognized as necessary for proper heat dissipation. However, it is not necessarily impossible to operate at near shutoff conditions, provided (1) it does not operate long under these conditions, as temperature rises per minute vary from less than 1°F to 30–40°F, or (2) a by-pass is routed or recycled from the discharge through a cooling arrangement and back to suction to artificially keep a minimum safe flow through the pump while actually withdrawing a quantity below the minimum, yet keeping the flowing temperature down [20]. 1. Temperature rise in average pump during operation [21].



∆Tr =

42.4Pso , °F / min[25] W1c p

(16.77)

where [10] Tr = temperature rise, °F /min. Pso = brake horsepower at shutoff or no flow. W1 = weight of liquid in pump, lb. cp = specific heat of liquid in pump (Btu/lb °F) or, alternate procedure [21, 22]. For low capacity:



∆Tr =

H so (1 − e) 778(c p )(e)

(16.78)

Pumps  437 where Hso = total head of pump at no flow or shutoff or at any flow rate with corresponding efficiency from pump curve, ft. e = pump efficiency at the flow capacity involved (low flow), decimal. Another alternative procedure [16] is as follows:

∆Tr =



(gpm)(H so )(SpGr ) 3960

(16.79)

The following equation is used to estimate the temperature rise through the pump [42]:

∆t = CPshaft



(1 − e) cp q ρ

(16.80)

where ∆t = temperature rise through the pump, °F or °C C = conversion factor: C = 1 for SI units; C = 317 for US units. Pshaft = brake power to the pump, kw or hp e = pump efficiency, evaluated at the flow and head where the pump is operating cp = heat capacity of pumped fluid, Btu/lb °F, kJ/kg °C q = volumetric flow rate, gal/min, m3/s ρ = fluid density, lb/ft3, kg/m3 The absolute minimum flow through the pump is such that the fluid does not vaporize in the pump head. Use Eq. 16.80 to check that the boiling point (at suction pressure) is not reached. See Figure 16.63 and Figure 16.64 for a graphical solution to the equation above for temperature rise. Figure 16.63 illustrates the characteristics of a boiler feed water pump set to handle 500 gpm water at 220°F for a total of 2600 ft head. The temperature rise curve has been superimposed on the performance chart for the pump, and values of Tr are calculated for each flow–head relationship. Note how rapidly the temperature rises at the lower flows. This heating of the fluid at low flow or no flow (discharge valve shut, no liquid flowing through the pump) can be quite rapid and can cause major mechanical problems in the pump’s mechanical components. The maximum temperature rise recommended for any fluid is 15°F (can be a bit higher at times for the average process condition) except when handling cold fluids or using a special pump designed to handle hot fluid, such as a boiler feed water pump of several manufacturers.



∆Tr =

(BHP at shutoff )(42.4 ) , °F/ min ( weight of liquid in pump)(c p )

(16.81)

(BHP − WHP)(2545) , °F/ min ( pump capacity )

(16.82)

or



∆Tr =

where BHP = brake horsepower. WHP = Water or liquid horsepower.

438  Petroleum Refining Design and Applications Handbook Volume 2 36

100

34

45

90 B

40

32

35

30

HEAD CA PACITY

80

800

70

700

28

60

600

26

50

D

EFFICIENCY

15

24

R, sp

E POW ORSE AKE H

A BR

22

10

20

5

18

0

16

40

55

gr 0.9

30

P

ER H WAT

E

400 300

20

200

10

100

C

0 0

500 BRAKE HORSEPOWER

20

EFFICIENCY, PERCENT

WATER TEMPERATURE RISE, °F

25

TOTAL DYNAMIC HEAD, 100 FT

TEMPERATURE RISE 30

100

200

300

400

500

0

600

CAPACITY, GPM

Figure 16.63  Typical temperature rise for boiler feed water pump (by permission from Transamerica Delaval Engineering Handbook, 4th ed., H.J. Welch, ed. 1983. Transamerica Deleval, Inc., IMO Industries, Inc. Div.).

2. Minimum Flow (Estimate) [21] The validity of the method has not been completely established, although it has been used rather widely in setting approximate values for proper operation [16]. For multistage pumps use only the head per stage in temperature limit by this method. a) Determine NPSHA available at pump suction. b) Add the NPSH value to the vapor pressure of the liquid at suction conditions. This represents the vapor pressure corresponding to the temperature of the liquid at the flash point. Read temperature, t2, value from vapor pressure chart of liquid. c) Allowable temperature rise = t2 − (actual pumping temperature). Boiler feed water practice uses 15°F rise for average conditions [16]. d) Approximate minimum safe continuous flow efficiency:



eM =

H so , at shutoff from curve 778(∆Tr )c p + H so , at shutoff

where eM = minimum safe flowing efficiency, overall pump, fraction. Hso = head at no flow or shutoff, ft.

(16.83)

Pumps  439 50 40

PE

R

CE NT

30

CE NT

2

20

PE

R

MAXIMUM RECOMMENDED CE NT R

R

PE

R

PE

R NT

PE R

CE

25

20

PE

R

CE

CE

8

NT

NT

15

10

15

PE

6

R

CE

40

NT

PE

R

CE

NT

30

TEMPERATURE, IN °F

CE

CE

NT CE PE

R

10

NT

NT

PE 5

4

PE

R

CE NT

3

15

CE

NT

PU

M

P

EF

FI

CI

60

EN

PE

CY

3

R

CE

NT

50

PE

4

80

PE

R

CE

NT

70

PE

R

2

1 200

300

500

1,000

2,000

3,000

5,000

TOTAL HEAD, IN FEET

Figure 16.64  Temperature rise in centrifugal pumps in terms of total head and pump efficiency (by permission from Karrasik, I and R. Carter, Centrifugal Pumps, McGraw-Hill Book Co. Inc., 1960, p. 438).

cp = specific heat of liquid, Btu/lb °F. Tr = temperature rise in liquid, °F. e) Read minimum safe flow in gpm from pump performance curve at value of minimum efficiency calculated in (d).

440  Petroleum Refining Design and Applications Handbook Volume 2 The Hydraulic Institute [8] offers guidance for determining the minimum flow through a centrifugal pump: • Temperature rise of the liquid. This is usually established at 50°F (10°C) and results in a very low minimum flow limit. • Radial hydraulic thrust on impellers. This is most serious with single volute pumps, and even at a flow rate that is 50% of Best Efficiency Point (BEP) (see Figure 16.18), could be reduced bearing life, excessive shaft deflection seal failure, impeller rubbing, and shaft breakage. • Flow recirculation in the pump impeller. This can also occur below 50% of the BEP causing noise, vibration and cavitation, and mechanical damage. • Total head characteristic curve. Some curves droop toward shutoff. Operation in such a region should be avoided.

Example 16.28: Maximum Temperature Rise Using Boiler Feed Water Using the example of [23], assume a pump with characteristic curve and added temperature rise data as shown on Figure 16.63 is to handle boiler feed water at 220°F, with a system available NPSHA = 18.8 ft. The vapor pressure of water at 220°F is 17.19 psia from steam tables and the SpGr = 0.957. Correcting the 18.8 ft NPSHA: psia = 18.8 (1/[2.31/0.957]) = 7.79 psia at 220°F. The vapor pressure to which the water may rise before it flashes is 17.19 psia +7.79 psia = 24.98 psia. From steam tables (or fluid vapor pressure tables), read at 24.98 psia (for water of this example), temperature = 240°F. Therefore, allowable temperature rise of the water (this example) = 240° − 220°F = 20°F. A plotted curve as shown on Figure 16.63 [22] shows that at point A, a rise of 20°F on the temperature rise curve corresponds to a minimum of 47 gpm safe for the pump handling 220°F, with NPSHA of 18.8 ft. An alternate estimate for minimum flow [14]: Minimum flow (for water) through pump,

QM = 0.3 Pso, gpm

(16.84)

where Pso = shutoff horsepower For cold liquids, general service can often handle Tr of up to 100°F, a rule with approximately 20% factor of safety:



QM =

6Pso , gpm ∆Tr

(16.85)

Tr = permissible temperature rise, °F

The NPSHR at the higher temperature may become the controlling factor in order to avoid cavitation. The minimum flow simply means that this flow must circulate through the pump casing (not recirculation with no cooling) back to at least the initial temperature of the feed, if excessive temperatures are not to develop. The best practice is to request the manufacturer to state this value for the fluid handled and the calculated NPSHA condition. For NPSHR refer to corrections discussed earlier.

16.24 Centrifugal Pump Specifications Figures 16.65a and 16.65b present specifications and calculation for a centrifugal pump, respectively. Although the process engineer cannot or should not specify each item indicated, he/she must give the pertinent data to allow the pump manufacturer to select a pump and then identify its features. Pumps are selected for performance from

Pumps  441 the specific characteristic curves covering the casing size and impeller style and diameter. Often the process fluids are not well known to the pump manufacturer, therefore the materials of construction, or at least any limitations as to composition, must be specified by the engineer.

Example 16.29: Pump Specifications The pump specified identifies the design data, key portions of the construction materials and driver data as required information for the pump manufacturer (Figures 16.65a and b). If the pump is to be inquired to several manufacturers this is all that is necessary. The individual manufacturers will identify their particular pump selection, details of construction materials, and driver data. From this information a pump can be selected with performance, materials of construction, and driver requirements specified. In the example (Figure 16.65a) the manufacturer has been specified from available performance curves and the details of construction must be obtained. The pump is selected to operate at 22 gpm and 196–200 ft head of fluid, and must also perform at good efficiency at 18 gpm and a head which has not been calculated, but which will be close to 196–200 ft, say about 185 ft. Ordinarily, the pump is rated as shown on the specification sheet. This insures adequate capacity and head at conditions somewhat in excess of normal. In this case, the design gpm was determined by adding 10% to the capacity and allowing for operation at 90% of the rated efficiency. Often this latter condition is not considered, although factors of safety of 20% are not unusual. However, the efficiency must be noted and the increase in horsepower recognized as factors which are mounted onto normal operating conditions. Sometimes the speed of the pump is specified by the purchaser. However, this should not be done unless there is experience to indicate the value of this, such as packing life, corrosion/erosion at high speeds, and suspended particles; as the limitation on speed may prevent the manufacturer from selecting a smaller pump. In some cases it must be recognized that high heads cannot be reached at low speeds in single stage pumps. Table 16.9 presents suggestions for materials of construction for pump parts in the services indicated. The effect of impurities, temperature, analysis variations and many other properties make it important to obtain specific corrosion service data in the specific fluid being pumped. Sometimes this is not possible, and generalized corrosion tables and experience of other users must be relied on as the best information for the selection of materials.

Steps in Pump Sizing In order to size a pump, engineers need to estimate the temperature, density, viscosity, and vapor pressure of the fluid being pumped. Pump sizing can be accomplished as follows [32]: 1. F  ind the total dynamic head, which is a function of the four key components of a pumping system, such as suction and discharge elevation; fluid velocity, friction loss and dynamic head; and tank pressure. 2. Correct for the viscosity of the fluid being pumped, since pump charts and data are given for water with a viscosity of 1cP. Viscosity of other process fluids can differ greatly. 3. Calculate the net positive suction head (NPSH) to select a pump that will not undergo cavitation. 4. Check the value of suction specific speed to see if a commercial pump is readily available. 5. Check the potential suitable pumps using a composite performance curve and an individual pump performance curve. 6. Compare the energy consumption and lifecycle cost of operating the selected pump.

16.25 Number of Pumping Units A single pump is the cheapest first-cost installation. However, if downtime has any value such as in lost production, in hazards created in the rest of the process, and so on, then a standby duplicate unit should be considered. A spare or standby can be installed adjacent to the operating unit, and switched into service on very short notice, provided it is properly maintained. Spare pumps which do not operate often should be placed in service on a regular schedule just to be certain they are in working order.

442  Petroleum Refining Design and Applications Handbook Volume 2

Figure 16.65a  Centrifugal pump specification.

Pumps  443

Figure 16.65b  Centrifugal pump calculation sheet.

Cast iron Misco C

Ni-resist*

Casing; C Steel-rings: C.I.

Cast iron

Misco C

Nickel

Cast iron

Brine (sodium chloride)

Butadiene

Carbon tetrachloride

Caustic, 50% (max. temp. 200oF)

Caustic, 50% (over 200oF)

Caustic, 10% (with some sodium chloride)

23% Cr 52% Ni Stainless steel

Nickel

Impeller: C.I.-rings C. steel

Ni-resist*

Cast iron

Cast iron

Benzene

Cast iron

Impeller and wearing rings

Cast iron

Casing and wearing rings

Ammonia, anhydrous and aqua

Liquid

Table 16.9  Pump materials of construction.

23% Cr 52% Ni stainless steel

Nickel or 18-8 stainless steel

18-8 stainless steel

Carbon steel

23% Cr 52% Ni Stainless steel

Nickel

Misco C

Carbon steel

13% Chrome steel

K Monel

K Monel

Carbon steel

Nickel moly. steel

Carbon steel

Shaft sleeves

Carbon steel

Carbon steel

Shaft

Ring packing

Ring packing

Ring packing

Cast iron

Nickel

Misco C

−

−

Mechanical

Mechanical

Ni-resist**

Cast iron

Ring packing Ring packing

−

Seal cage

Mechanical

Type of seal

−

Nickel

Carbon steel

Mall. iron

Carbon steel

Ni-resist**

Mall. iron

Mall. iron

Gland

(Continued)

Specifications for 50% Caustic (Max. Temp. 200oF) also used.

Misco C manufactured by Michigan Steel Casting Company. 29 Cr-9 Ni Stainless Steel or equal.

*Cast iron acceptable. **Mall. Iron acceptable.

NOTE: Materials of Construction shown will be revised for some jobs.

Remarks

444  Petroleum Refining Design and Applications Handbook Volume 2

Carbon Steel

Bronze

Impregnated carbon

Cast steel

Cast iron

Bronze

Impregnated carbon

Rubber lined C. iron Cast iron

Casing: C. Steel Rings: C.I.

Hard rubber Lined C.I.

Cast Si-iron

Cast iron

Cat iron

Casing, 1–2% Ni, Cr 3–0.5% cast iron rings: Ni-resist, 2B

Ethylene

Ethylene dichloride

Ethylene glycol

Hydrochloric acid, 32%

Hydrochloric acid, 32% (alternate) methyl chloride

Propylene

Sulfuric acid, Below 55%

Sulfuric acid, 55% to 95%

Sulfuric acid, Above 95%

Water, river

Water, sea

K Monel or Alloy 20 SS

K Monel (aged)

Ring packing

Mechanical

Bronze

18-8 Stainless steel

Ring packing

Ring packing

Mechanical

Ring packing

Mechanical

Ring packing

Si-iron

Hastelloy C

Carbon steel

Rubber or plastic

Impregnated carbon

Ring packing

Mechanical

Mechanical

Type of seal

13% Chrome steel bronze

Carbon steel

Type 316 Stn. Stl.

Carbon steel

Carbon steel

Carbon steel

18-8 Stainless steel

18-8 Stainless steel

K Monel

Steel 18-8 Stainless steel

Carbon Steel

Shaft sleeves

Carbon steel

Shaft

Note: Table materials are for general use, specific service experience is preferred when available.

Impeller: Monel Rings: S-Monel

Bronze

Cast iron

Si-iron

Special rubber

Imp.: C.I. rings C. Stl

Hard rubber

Cast iron

Impeller and wearing rings

Casing and wearing rings

Liquid

Table 16.9  Pump materials of construction. (Continued)

Monel or Alloy 20 SS

Cast Iron

Cast iron

Teflon

Special rubber

−

Rubber

−

−

−

Cast iron

Seal cage

Monel or Alloy 20 SS

Mall. iron

Mall. iron

Si-iron

Special rubber

Mall. iron

Rubber

Impregnated carbon

Bronze

K Monel

Mall. iron

Gland

Remarks

Pumps  445

446  Petroleum Refining Design and Applications Handbook Volume 2 If solids are carried in the fluid, this can present a difficult problem if they are not properly flushed from the pump on shutdown. Some spare or second pumps are selected for 100% spare; others are selected so that each of two pumps operate in parallel on 50% of the flow, with each being capable of handling 67–75% of total load if one pump should fall off the line. This then only reduces production by about 25% for a short period, and is acceptable in many situations. These pumps are usually somewhat smaller than the full size spares. When it is necessary to plan several pumps in parallel, the pump manufacturer must be advised, and care must be taken in arranging suction piping for the pumps, otherwise each may not carry its share of the flow. There are many flow conditions, and pumps should be selected to operate as efficiently as possible over the widest range of capacity. If the flow is expected to vary during the system operation, the high and low gpm (and corresponding heads) should be given to allow proper evaluation.

Fluid Conditions The manufacturer must be told the conditions of the liquid, percent suspended solids, physical properties, corrosive nature and maximum and minimum temperature ranges. For extremely hot liquids, special hot pumps must be used, and temperature effects taken into account.

System Conditions The manufacturer must know if the suction side of the pump is associated with vacuum equipment, or is to lift the liquid. This can make a difference as to the type of impeller suction opening he provides. If the system operates intermittently it should be noted. A piping diagram is often helpful in obtaining full benefit of the manufacturer’s special knowledge.

Type of Pump If there is a preference as to horizontal or vertical split casing, it should be stated. Also the suction and discharge connections should be stated as to top or end, or special, together with the preference as to flanged (rating) or screwed. Small pumps are commonly furnished with screwed connections unless otherwise specified.

Type of Driver Pumps are usually driven by electric motors, steam or gas turbine or gas (or gasoline) engines either direct or through V-belts or gears. The pump manufacturer should know the preferred type of drive. If the manufacturer is to furnish the driver, the data on the specification sheet under Driver [see Process Data Sheet (Appendix D)] should be completed as far as applicable. If a gas or gasoline engine is to be used, the type of fuel and its condition must be stated. Engine cooling water (if air not used) must be specified.

Sump Design for Vertical Lift The proper design of sumps for the use of vertical lift pumps or horizontal pumps taking suction from a sump is important to good suction conditions at the pump [23–25]. The arrangement and dimensions indicated in Figures 16.66 and 16.67 are satisfactory for single or multiple pump installations. (For more details, refer to [8]). A few key points in sump-pump relationships for good non-vortexing operation are as follows: 1. A  void sudden changes in direction or elevation of flow closer than five bell diameters to pump. 2. Avoid sump openings or projections in water path close to pump. 3. Have water flowing parallel to sump walls as it enters pump. Water should enter pump suction with as low turbulence as possible. 4. Water velocity in sump must be low, 1.5 ft/s is good practice.

Pumps  447

Entering Water < 1 ft/s V=

S

S

Motor

Discharge Pump

Water Level

Submergence, Sb Bottom Level or 7° Max. Grade for 5Bd

Bd/2 Bd Bell Diameter

Water Depth in Pump, /

Bd/3 to Bd/2

Figure 16.66  Sump design. Note: S = (1.5 − 2)Bd.

5. I nlet channel width to each pump is considered optimum to 2 Bd to prevent secondary turbulence effects [24]. 6. Avoid placing several pumps in one open channel removing water in series fashion. If this must be done, velocity at each pump must be kept at same value as for a single pump. The channel width at each pump would be taken from [8]. A suction bell on the inlet of a vertical pump (or the inlet pipe of the suction side of a horizontal pump) is not necessary as far as pump or sump operation is concerned. If a bell is omitted, the entrance losses due to flow will be higher with only a straight pipe, and this must be considered in pump operation. An economic comparison will help decide the value of the bell. Strainers should not be placed on suction bells unless this is the only arrangement. Inlet water should be screened with trash racks, bars, and screens to keep the sump free of debris. Submergence of the inlet pipe column or bell inlet below the water level is necessary for good operation and to prevent vortexes and entrained air. The minimum submergence as recommended by the manufacturer must be maintained at all times. Generally, for 70°F (21.1°C) water, each 1000 ft (304.8 m) of elevation above sea level adds 14 in. (355.6 mm) to the required submergence. If the water is at 100°F (37.8°C) at sea level, approximately 17 in. (431.8 mm) must be added to the 70°F (21.1°C) submergence value [25].

448  Petroleum Refining Design and Applications Handbook Volume 2

Vertical Pumps Water Flow

d = Bd/3

Partition (see Ref. [17])

Figure 16.67  Acceptable sump arrangement for multiple pumps.

16.26 Rotary Pumps There are many different types of positive displacement rotary pumps [26] as illustrated in Figure 16.68 and Figures 16.69a–c. The majority of these types are capable of handling only a clean solution essentially free of solids. The designs using rubber or plastic parts for the pressure device can handle some suspended particles. In general, these pumps handle materials of a wide range of viscosity (up to 500,000 SSU), and can develop quite high pressures (over 1000 psi [69bar]). Additionally, the units can handle some vapor or dissolved gases mixed with the liquid being pumped. The capacity is generally low per unit, and at times, they are used for metering. For specific performance characteristics of any type consult the appropriate manufacturer. These pumps are low in cost, require small space, and are self priming. Some can be rotated in either direction, have close clearances, require overpressure relief protection on discharge due to positive displacement action; and have low volumetric efficiency [27].

Performance Characteristics of Rotary Pumps 1.



 low proportional to speed and almost independent of pressure differential. F a) Internal slip reduces efficiency, and increases with pressure and decreasing viscosity. b) Entrained gases reduce liquid capacity and cause pulsations. c) Liquid displacement [21]

d′ =

d ′′(1 − E n ) , ft 3/ min (1 − E n ) + E n ( P P1 )

(16.86)

Pumps  449 Suction

Discharge

Discharge

Gear

Discharge Gear

Suction

Discharge

Suction

Three-Lobe Roter

Internal Gear

Gear

Crescent

External Gear Pump

Rotor Sliding Vanes

Suction

Four-Lobe Pump

Internal Gear Pump

Discharge

Suction

Discharge

Three-Lobe Pump

Driving Gear

Rotor

Sliding Vane Pump

Inlet Discharge Discharge

Discharge

Shaft

Seal Key

Suction Suction

Eccentric

Swinging Vanes

Single Screw Pump

Swinging Vane Pump

Roller

Power Rotor

Discharge Shuttle Block

Shaft

Rotor

Piston

Eccentric Squeeze Ring

Discharge

Three-Screw Pump

Cam-and-Piston Pump

Flexible Rubber Tube

Suction Idle Rotors

Eccentric

Cam or Roller Pump

Suction

Rotor Sleeve

Piston

Fluid Flow

Suction

Shuttle Block Pump

Squeegee Pump

Flexible Vane

Figure 16.68  Rotary pumps (by permission from Dolman, R. E., Chem. Eng., Mar. 1952, p. 159).

where P = the atmospheric pressure, and P1 is the inlet absolute pressure to the pump. dʺ = theoretical displacement, ft3/min dʹ = liquid displacement, ft3/min En = percent entrained gas by volume at atmospheric pressure 2. Volume displaced [8]

Q′ =



D′′ n − S′′ , gpm 231

(for no vapor or gas present)

where Q′ = capacity of rotary pump, fluid plus dissolved gases/entrained gases, at operating conditions, gpm. Dʺ = displacement (theoretical) volume displaced per revolution(s) of driving rotor, in.3/rev n = speed, revolutions per minute of rotor(s), rpm Sʺ = slip, quantity of fluid that leaks through internal clearances of pump per unit time, gpm

(16.87)

450  Petroleum Refining Design and Applications Handbook Volume 2 Disc Diaphragm

FLOW TO 1480 gph, PRESSURES TO 5000 psl

SUCTION

DISCHARGE

Figure 16.69a  Diaphragm metering pump, “Pulsa” series. One of several styles/types (by permission from Pulsafeeder Inc.).

Positive-lock thrust control for precision rotor and shaft positioning to maintain original performance and minimize wear for extended pump life.

Choice of leak-resistant packing or standard mechanical seals (illustrated). Special mechanical seals available to fit equipment. Integral safety relief value works to protect system against excessive pressure.

Cushioned, positive-flow action of rotor and idler combination provides non-pulsating, low-shear transmission of liquid.

Figure 16.69b  Typical rotary gear pump (by permission from Viking Pump, Inc., Unit of Idex Corp.).

Specially designed and machined revolvable casing provides eight port positions to suit application.

Pumps  451

FULL FLOW

PARTIAL FLOW

NEUTRAL OR NO FLOW

REVERSE FLOW

The liner (grey area) is in full-capacity position with the seal point at the top and the pumping chamber at the bottom. All liquid coming into the pump at the left is moving outt of it at the right.

Now the liner has been rotated counterclockwise, which opens the seal point at the top. This allows part of the liquid to be recirculated, reducing the net flow by a proportionate amount.

Rotating the liner still further, a point is reached where displacement volumes above and below the rotor are equalized. This causes as much liquid to be returned over the top as is brought forward across the bottom, resulting in zero flow.

When the liner is rotated past the “no flow” point, the volume above the rotor exceeds that below, and net flow reverses direction even though pump speed and rotation have not changed. (Limited to approx. 30% of full forward flow on all models.)

Figure 16.69c  Sliding vane rotary pump (by permission from Blackmer Pump, Dover Resources Co.).

3. Pump power output (whp) [8]



whp1 =

(Q′Ptd ) 1714

where Ptd = differential pressure between absolute pressures at the outlet and inlet to pump, psi whp1 = power imparted by the pump to the fluid discharged (also liquid hp) Ev = volumetric efficiency, ratio of actual pump capacity to the volume displaced/unit time

(16.88)

452  Petroleum Refining Design and Applications Handbook Volume 2

Ev =



231Q′(100) (D′′n)

(16.89)

4. B  hp varies directly with pressure and speed. 5. For speed and pressure constant, Bhp varies directly with viscosity.

Selection Suction and discharge heads are determined the same as for centrifugal pumps. Total head and capacity are used in selecting the proper rotary pump from a manufacturer’s data or curves. Since viscosity is quite important in the selection of these pumps, it is sometimes better to select a larger pump running at low speeds than a smaller pump at high speeds when dealing with viscous materials. As a general guide, speed is reduced 25–35% below rating for each tenfold increase in viscosity above 1000 SSU. Generally, the mechanical efficiency of the pump is decreased 10% for each tenfold increase in viscosity above 1000 SSU, and referenced to a maximum efficiency of 55 % at this point [28].

16.27 Reciprocating Pumps Reciprocating pumps are positive displacement piston units driven by a direct connected steam cylinder or by an external power source connected to the crankshaft of the pump piston. Being positive displacement, these pumps can develop very high pressures (10,000 psi [689.5 bar] and higher) for very low or high capacities (up to 1000 gpm [378.5 l/min]).

Significant Features in Reciprocating Pump Arrangements I. Liquid pump end A. Pump Pressure Component 1. Piston. 2. Plunger. B. Types 1.  Simplex, one piston. 2.  Duplex, two piston (Figure 16.70). 3.  Triplex, three piston (not used as steam driven). C. Piston or plunger action 1.  Single acting, one stroke per rpm. 2.  Double acting, two strokes per rpm, cylinder fills and discharges each stroke (Figure 16.71). D. Packing for piston or plunger 1. Piston packed: packing mounted on piston and moves with piston; applied to comparatively low pressures. 2. Cylinder packed: packing stationary; plunger moves; applied to high pressures; more expensive than piston packed. II. Drive end: Steam A. Steam Cylinders 1.  Simple: single cylinder per cylinder of liquid pump; uses more steam than compound. 2. Tandem Compound; high and low pressure cylinder on same centerline; usually requires 80 psi (5.5 bar) or greater steam to be economical. 3. Cross Compound: high and low pressure cylinder arranged side-by-side with cranks 90° apart. Need for crank and flywheel arrangement only; usually requires 80 psi or greater steam to be economical.

Pumps  453 Removable steam chest cover, permitting quick access to steam valves D type slide valves most simple and reliable

Rigid cast iron cradle of semicircular section, assuring strength and alignment

Stuffing boxes extra deep

Hammered iron piston rings self-adjusting assuring tightness and reducing friction

Disc type valve service

Drop forged steel valve-motion parts

Box type steam pistons

Piston rods divided at crossheads

Removable liners held in place by cylinder heads

Twin liquid cylinders machined in duplex boring mill assuring correct centers

Soft packing or hammered iron piston rings

Liquid pistons removable follower type

Figure 16.70  General service duplex steam-driven piston pump (courtesy of Worthington Corp.). Totally-Enclosed Dust-Proof Oil-Tight Power End Roller Main and Pinion-Shaft Bearings

Double Helical Gears Marine Type Connecting Rods Positive Flood Lubrication Provided by Oil Distributing Pump

Solid Forged Steel Cylinder–no Gaskets Under Discharge Pressure Wing Guided Valves

Figure 16.71  Duplex double-acting plunger pump, power driven (courtesy of Worthington Corp.).

Deep Stuffing Box Equipped for Packing Lubrication Flange and Screw Type Gland – Even Take-up on Packing

454  Petroleum Refining Design and Applications Handbook Volume 2 Percentage gain in compounding steam cylinders varies from 25–35% for non-­condensing, and 25–40% for condensing [29]. B. Cylinder action 1.  Direct: steam piston direct connected to liquid piston or plunger through piston rod. 2.  Crank and Flywheel: flywheel mounted on crank shaft driven by steam cylinder. III. Drive end: Power General features same as steam, except drive always through crankshaft; speed gear increasers or reducers; V-belts, or direct coupling connection to drive shaft. IV. Designation Units are identified as steam cylinder diameter, inches; liquid cylinder diameter, inches; length of stroke, inches.

Application

Piston Type: used for low pressure light duty or intermittent service. Less expensive than the plunger design, but cannot handle gritty liquids.



Plunger Type: used for high pressure heavy duty or continuous service. Suitable for gritty and foreign material service, and more expensive than the piston design.

Performance The performance of reciprocating pumps provides for ease of operation and control. Depending upon the type of piston action, the fluid may be subjected to pulsations unless accumulator or surge drums are provided. The slip of a pump is fraction or percent loss of capacity relative to theoretical. Slip is (1 − evol), where evol is the volumetric efficiency. Volumetric efficiency is the actual liquid pumped (usually considered water) relative to that which should theoretically be pumped based on piston displacement. The NPSHR is approximately 3–5 psi of liquid above the vapor pressure of the liquid. The capacity of a pump is given in manufacturers’ tables as actual, after deducting for volume occupied by piston rod and slippage. Slip varies from 2–10% of displacement, with 3% being a fair average. Capacity: actual, for single acting pumps, single cylinder

Q=



(12a t )(e vol ) = 0.0204 d 2p te vol , gpm (231)(2)

(16.90)

For double acting pumps, single cylinder



Q = ( two times value for single acting ) − 0.0204 d r2 t , gpm

(16.91)

For multiple cylinders, multiply the capacities just obtained by the number of cylinders. If the piston rod does not replace pumping volume as in some arrangements, the last term of the double acting capacity equation is omitted.

Discharge Flow Patterns Figure 16.72 shows the discharge flow patterns for several reciprocating power pump actions which are essentially the same for steam pumps. The variations above and below theoretical mean discharge indicate the magnitude of the pulsations to be expected. Although not shown, the simplex double-acting discharge would follow the action of one piston on the duplex double acting curve from 0 to 360°. Its variation or pulsing is obvious by inspection, and

Pumps  455 QUINTUPLEX SINGLE-ACTING PUMP

Variation Above Mean, 1.8% Variation Below Mean, 5.2% Total Variation,

7.0% 8.5851 0°

72°

144°

216°

288°

360°

SEXTUPLEX SINGLE-ACTING PUMP

A 30572

Variation Above Mean, 4.82% Variation Below Mean, 9.22% Total Variation,

14.04%

0°

60°

120°

180°

300°

240°

360°

TRIPLEX SINGLE-ACTING PUMP Variation Above Mean, 6.1% Variation Below Mean, 16.9% Total Variation,

8.5852

23.0% 0°

120°

360°

240°

QUADRUPLEX SINGLE-ACTING PUMP

Variation Above Mean, 11.0% Variation Below Mean, 21.5% Total Variation,

32.5%

0°

90°

180°

270°

360°

DUPLEX DOUBLE-ACTING PUMP FORWARD STROKE

RETURN STROKE

Variation Above Mean, 24.1% Variation Below Mean, 21.5% Total Variation,

45.6%

8.8853

0°

90°

180°

Figure 16.72  Reciprocating pump discharge flow pattern (courtesy of the Aldrich Pump Co.).

270°

360°

456  Petroleum Refining Design and Applications Handbook Volume 2 accumulator bottles would be required to smooth the flow. The simplex single acting discharge would be one pumping stroke from 0 to 180°, then no pumping from 180° to 360°; and here again the pulse action is obvious.

Horsepower Hydraulic

HHP =



(Q actual )(H) 3960

(16.92)

HHP e

(16.93)

Brake

BHP =

where e represents the total overall efficiency, and is



e = em(evol),

and em is the mechanical efficiency and evol is the volumetric efficiency, fraction. Mechanical efficiencies of steam pumps vary with the types of pump, stroke and the pressure differential. Some representative values are 55–80% for piston pumps with strokes of 3 and 24 in., and pressure differential up to 300 psi. For the same strokes a plunger design varies from 50 to 78%, and at over 300 psi differential the efficiencies are 41.67% [30]. Steam required is approximately 120 lb/h per BHP.

16.28 Pump Selection Reciprocating pump selection follows the fundamentals of centrifugal pumps: 1. 2. 3. 4. 5. 6. 7.

 valuate suction side head loss. E Evaluate discharge side head loss. Determine system static pressure. Determine total differential head across pump. Determine the NPSHA available on suction of pump. From manufacturer’s performance tables, select pump nearest to gpm and head requirements. Contact manufacturer for final recommendations, give complete system requirements, and physical properties of liquid. Figure 16.73 will serve this purpose.

16.29 Selection Rules-of-Thumb Every pump has a specific curve that relates flow, head, power, NPSHR, and efficiency for specific impeller diameters for that particular unit. This allows correct selection of the impeller diameter. Therefore, during specification, the objective is to select a pump with a rated or design point as close as possible to the best efficiency point (BEP), as determined by the pump manufacturer [31]. The following are general guidelines for proper selection [31]: 1. S elect the pump based on rated conditions. 2. The BEP should be between the rated point and the normal operating point.

Pumps  457

Figure 16.73  Horizontal direct-acting steam pump or power pump.

458  Petroleum Refining Design and Applications Handbook Volume 2 3. Th  e head/capacity characteristic curve should continuously rise as flow is reduced to shutoff (or zero flow). 4. The pump should be capable of a head increase at rated conditions by installing a larger impeller. 5. The pump should not be operated below the manufacturer’s minimum continuous flow rate. The pump has a specific NPSHR, which varies, depending on the head and flow. Once the specific pump model and size have been determined from the basic process information, the materials of construction must be chosen. Selection depends on fluid properties (e.g., viscosity, corrosiveness, and erosiveness) and the presence of dissolved gases. In general, adequate knowledge of the chemical composition of the fluid helps to ensure proper material selection of the pump and its shaft seal. The following guide to pump types provides a better understanding and specifications for the selection of pumps [37]: • American Petroleum Institute (API) process pumps: Designed to meet the 610 Standard set by the API. • Boiler feed pumps: Built to control the amount of water that enters a boiler. They are centrifugal pumps and most are multistage. • Chemical pumps: Build to handle abrasive and corrosive industrial materials. They can be either centrifugal or positive displacement type. • Circulatory pumps: Used to circulate fluid through a closed or looped system. They are usually centrifugal pumps, but a few use positive displacement technologies. • Dewatering pumps: A dewatering process involves using a centrifugal pump (submersible or vertical turbine) to remove water from a construction site, pond, mine shaft or any other area. • Fire pumps: A type of centrifugal pump used for firefighting. They are generally horizontal split case, end suction or vertical turbine. • High-pressure pumps: Used in many applications including water blast, hydromining, and jet cutting. They can be a wide variety of pump types including positive displacement pumps, rotary pumps, and reciprocating pumps or centrifugal pumps. • Industrial pumps: Used in industrial applications such as slurry, wastewater, industrial chemicals, oil and gas. There are dozens of different industrial pumps both in positive displacement and centrifugal pump types. • Marine pumps: Built to pump seawater. They are often used in large saltwater tanks to continuously circulated water so it stays fresh. • Mixed flow pumps: Incorporate the features of both axial flow and radial flow pumps. Axial flow pumps operate on a vertical plane and radial flow pumps operate on a horizontal plane to the flow direction of water. • Mud pumps: Built to transfer heavy sludge or mud. They are sometimes used on oil rigs to pressure and circulate fluid. • Petrochemical pumps: Made to transfer petroleum products that are often very viscous and corrosive. They can be magnetic drive pumps, diaphragm pumps, piston pumps, and so on. • Pneumatic pumps: Use compressed air to pressure liquid through the piping system. • Pressure pumps: Used to create either high or low pressure. They can be metering pumps and sometimes booster pumps. • Process pumps: Are many times centrifugal pumps or positive displacement pumps used in process applications. The type of pump and construction details varies depending on the application in which these pumps are used. • Slurry pumps: A heavy-duty pump that is made to handle thick, abrasive slurries. They are made of durable materials and capable of handling abrasive fluids for long periods of time. • Solar pumps: Powered by the sun. They can be positive displacement or centrifugal pumps. • Water pumps: A type of equipment used to move water through a piping system. They rely upon principles of displacement, gravity, suction and vacuums to move water. They can be either positive displacement or centrifugal pumps. • Well pumps: Designed to draw water to the surface from an underground water source. Depending on the well depth and configuration, these pump types can be jet, centrifugal or submersible.

Pumps  459 In general, the final pump selection is influenced by several factors: • • • • •

Pump capacity (size) that is a function of the flow rate to be pumped. Fluid properties, both physical and chemical. Operating conditions. Type of power supply. Type of flow distribution.

16.30 Case Studies Case Study 1 Pump Simulation on a PFD A pump operation is used to increase the pressure of a fluid stream that is flowing from one process unit to another in a process flowsheet. Power (energy/time) in the form of electric energy drives a motor coupled to a steel drive shaft. The drive shaft connected to impellers imparts energy to the liquid in order to increase its pressure. The temperature of the liquid increases slightly, because of the effects of fluid friction. The conceptual model for the pump operation is given below for a steady state system. The system is a fluid mixture of chemical compounds (or components) passing into, through and from the pump. The mathematical model for the pump operation balances the material and energy flows of the system. This adiabatic unit operation occurs at steady state with no chemical reaction, and the kinetic and potential energy changes are negligible. The fluid is considered incompressible (i.e., at constant density); a good assumption for any fluid well removed from its critical point. The independent set of equations in the mathematical model contains the total and component material balances, the energy balance, the molar enthalpies of the two process streams, the adiabatic efficiency, the ideal work based on the mechanical-energy balance for a frictionless fluid, the pressure change, and the inlet mixture density and molecular weight. The adiabatic efficiency relates the ideal to the actual work and has a typical value of 75 % for most liquids. To solve this set of equations (nc + 5) variables must be specified, as indicated by the degrees-of-freedom analysis (DOF) in the model [33]. From this mathematical model, many mathematical algorithms can be derived for performing the process simulation calculations. These algorithms differ in their given variables and their solution procedures. To such algorithms are shown below for knowing the process state of the inlet stream and two additional variables. The unknown variables are calculated using the solution procedure define in the algorithm. The process state of material stream is its temperature, pressure, total flow rate and composition. Other possible simulation algorithms supported are summarized below.

Conceptual model

Model assumptions

WA Exit TI PI nI ZI

Inlet Pump

TE PE nE ZE

1. 2. 3. 4. 5. 6.

Continuous process Steady state No chemical reaction Negligible KE and PE changes Adiabatic Incompressible fluid

460  Petroleum Refining Design and Applications Handbook Volume 2

Mathematical Model 1

nI – nE = 0

2

nIZI,j – nEZE,j = 0

3

nI. HI – nE HE + WA= 0

4

Hl = hmix [TI, PI, ZI]

5

HE = hmix [TE, PE, ZE]

6

ε = 100. WI/WA

7

WI = ΔP.nI.MI/ρI

8

ΔP = PE − PI

9

ρI = liqden [TI, PI, ZI]

for j = 1, 2,…., nc

10 MI = mol wt [ ZI] vars = 2.nc + 14 eqns = nc + 9 DOF = 1.nc + 5

Variables Descriptions Ti Pi ni nc Zi zi,j Hi WA ε WI ΔP Mi ρi

Temperature of process stream, i, °C Pressure of process stream, i, kPa Bulk molar flow rate of process stream i, kg mol/h Number of chemical components or compounds in the mixture Bulk mole fractions of all nc-components or compounds in the mixture Bulk mole fractions of component j in process stream i; vector Zi means all elements zi,1, zi, 2,…….zi, nc Bulk molar enthalpy of process stream i, kJ/kg mol The actual work or power of the pump, kJ/h The adiabatic efficiency of the pump (0 to 100) percent The ideal work or power of the pump (ε = 100%), kJ/h The pressure drop between the exit and inlet streams, kPa Molecular weight of process stream i, kg/kg mol Liquid density of process stream i, kg/m3

Simulation Algorithm If the process state of the inlet stream is fully defined (i.e., TI, PI, nI, ZI are known) only two additional variables are required to calculate all unknowns as shown in the simulation algorithms below [33]:

Pumps  461 [TE, ∆P, nE, ZE, WA] [TE, PE, nE, ZE, WA] [TE, PE, nE, ZE, ∆P]

= = =

Pump A[TI PInI ZI, ε, PE] Pump B [TI, PI, nI, ZI, ε, PE] Pump C [TI, PI, nI, ZI, ε, WA]

[PE, nE, ZE, WA, ε] [∆P , nE, ZE, WA, ε]

= =

Pump D[TI, PI, nI, ZI, TE, ∆P] Pump E [TI, PI, nI, ZI, TE, PE]

[TE, PE, nE, ZE, ε] [TE, ∆P, nE, ZE, ε]

= =

Pump F [TI, PI, nI, ZI, WA, ∆P] Pump G [TI, PI, nI, ZI, WA, PE]

If the process state of the exit stream is fully defined (i.e., TE, PE, nE, ZE are known), only two additional variables are required to calculate all unknowns as shown in the UniSim simulation algorithms: [TI, PI, nI, ZI, WA] [TI, ∆P, nI, ZI, WA] [TI, PI, nI, ZI, ∆P]

= = =

Pump H[TE, PE, nE, ZE, ε, ∆P] Pump I [TE , PE, nE, ZE, ε, PI] Pump J [TE, PE , nE, ZE, ε, WA]

[PI, nI, ZI, WA, ε] [∆P , nI, ZI, WA, ε]

= =

Pump K [TE, PE, nE, ZE, TI, ∆P] Pump L [TE, PI, nE, ZE, TI, PI]

[TI, PI, nI, ZI, ε] [TI, ∆P, nI, ZI, ε]

= =

Pump M [TE, PE, nE, ZE, WA, ∆P] Pump N [TE, PE, nE, ZE, WA, PI]

Problem An equimolar mixture of n-hexane and n-octane at 25°C is pumped via P-100 from 1 atm to 4 atm. The liquid mixture is flowing at 100 lb-moles/h and its adiabatic efficiency is 70%. The conceptual diagram is shown in Figure 16.74. WA = ?

Exit

TE = ? PE = 4 atm nE = ? ZE, HX = ?

TI = 25°C PI = 1 atm nI = 100lb mol/h

ZE, OC = ? Hydroc. Feed

ZI, HX = 0.5

P- 100

ZI, OC = 0.5 ε = 70%

Figure 16.74  A conceptual diagram of P-100 with the variables.

462  Petroleum Refining Design and Applications Handbook Volume 2 The following procedures in constructing the simulation using UniSim software are as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.

Start the UniSim software, load your preferences, and open your file Pump-Simulation-akc.usc. Enter the Basic Environment, complete the component list and note the fluid package. Return to the Simulation Environment, open the process stream and rename it HydrocFeed. Specify its process state; i.e., its temperature, pressure, flow rate, and composition. Add a pump to the process flow diagram (PFD) and name it P-100 Connect its Inlet stream, name its Exit material stream, and name its Wa energy stream. Specify its adiabatic efficiency to be 70% and its exit pressure to be 4 atm. Open the Workbook window using its icon in the UniSim button bar View the values in the Material Streams page of the Workbook window. Note that specified values appear in blue, while calculated values appear in black. View the Compositions, Component Flows, and Energy Streams pages in the Workbook.

After specifying the state of the inlet stream, the pump efficiency and the exit pressure, UniSim immediately calculates all of the other properties of the material streams (such as mass flow rate, volumetric flow rate, vapor fraction, heat flow, etc), using the Peng–Robinson (PR) equation of state. Also the pump power is calculated to be 804.4 W. A positive value for the pump power shows that energy must be added to the process stream to increase its pressure.

Discussion Figures 16.75 and 16.78 show process flow diagrams of the simulation exercise with an equimolar mixture of n-heptane and n-octane and water, respectively. Pumping of fluids increases their temperature and Figure 16.75 shows the pump was 70% efficient, and the outlet temperature is 25.15°C. Correspondingly, Figure 16.78 shows the pump was 75% efficient, and the outlet temperature is 25.02°C, which is negligible. Generally, the less efficient a pump, the greater the increase in the temperature of the fluid being pumped. This arises because in a low efficient pump, more energy is required to pump the fluid to obtain the same outlet pressure of a more efficient pump as the extra energy is transferred to the fluid. Figures 16.76 and 16.77 show plots of head vs. flow rate and efficiency vs. flow rate of the centrifugal pump respectively, and Figure 16.78 illustrates the process flow diagram of the pump for case study 1.

Exit Hydrc. Feed Temperature 25.00 C 101.3 kPa Pressure Molar Flow 45.36 kgmole/h

P-100 Exit

Hydrc. Feed

Temperature Pressure Molar Flow

25.15 C 405.3 kPa 45.36 kgmole/h

Wa P-100 Speed Energy Actual Vol. Flow Feed Pressure Product Pressure Product Temperature

3500 2896 6.668 101.3 405.3 25.15

rpm kJ/h m3/h kPa kPa C

Figure 16.75  PFD of a centrifugal pump (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

Pumps  463 Head Curves 3500 Pump Curve-1

3000

CummOperating Points Pump Curve-2 Pump Curve-3

2500

Head (m)

2000

1500

1000

500.0

0.0000 0.0000

2.000

4.000

6.000

8.000

10.00

12.00

14.00

16.00

18.00

20.00

Flow (m3/h)

Figure 16.76  Head vs. flow rate of a centrifugal pump (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

Efficiency Curves

70.00 Pump Curve-1 CummOperating Points

69.00

Pump Curve-2 Pump Curve-3

68.00

Efficiency

67.00

66.00

65.00

64.00

63.00 0.0000

2.000

4.000

6.000

8.000

10.00

12.00

14.00

16.00

18.00

20.00

Flow (m3/h)

Figure 16.77  Efficiency vs. flow rate of a centrifugal pump (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

464  Petroleum Refining Design and Applications Handbook Volume 2

S3 Temperature 25.02 C 356.3 kPa Pressure Molar Flow 443.3 kgmole/h Pipe-100 S1

PIPESYS-UniSim

S1 Temperature 25.00 C Pressure 202.6 kPa Molar Flow 444.1 kgmole/h

Pipe-101 PIPESYS-UniSim

Pump-100 S3

S2

Q-101

E-100 Q-100

S2 Temperature 25.00 C 202.6 kPa Pressure Molar Flow 443.3 kgmole/h

Pump-100 Speed

Energy 1642 Actual Vol. Flow 8.011 Feed Pressure 202.6 Product Pressure 356.3 Product Temperature 25.02

rpm kJ/h m3/h kPa kPa C

S4 S4 Temperature 25.02 C 353.9 kPa Pressure Molar Flow 443.3 kgmole/h

Figure 16.78  PFD of a centrifugal pump (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

The UniSim Design R460.2 simulation software (Pump Simulation-akc.usc) shows the results of case study 1. Figures 16.79 to 16.81 show the simulation results of PFD of Figure 16.75.

Case Study 2 Figure 16.82 shows a pumping network of 800 U.S gpm of water from a supply tank at atmospheric pressure (0 psig) having the suction size of 4 in. of carbon steel (CS) to the inlet of an N-S centrifugal pump. The discharge side of 3-in. from the pump is connected to a recycle line to the supply tank via pipe and fittings and a restriction orifice. The other discharge line consists of a filter, and a tee fitting in directing the flow to two tanks at the north and south of HGF-1 building. The total dynamic head is 245.2 ft. Figure 16.83 shows the piping isometric with results using Darcy–Weisbach method in calculating the pressure drop in the various sections of the piping segments, the filter, and the throttle valves. Figure 16.84 shows the pump characteristics with 8.125 in. impeller and at a Best Efficiency Point (BEP) of 70.6% corresponding to 710 US gpm. From Figure 16.85, the pump head is 261 ft, power is 66.5 hp, and NPSHR is 23.3 ft. Figure 16.85 shows the results from the calculations and gives the shutoff head of 295 ft. UniSim Design R471 (Pipeline-deltaP.usc) shows the simulation of Case Study 2.

16.31 Pump Cavitations We shall review some studies of pump cavitations in the process plants. Pumps cavitate for three reasons [27]. 1. L  acking sufficient NPSHA to satisfy the conversion of pressure to velocity in the eye of the impeller (running NPSH). 2. Lacking sufficient NPSHA to satisfy the conversion of pressure to acceleration in the suction line as the pump is started (starting NPSH). 3. Lacking sufficient NPSHA to overcome the frictional losses in the suction piping and the drain or draw nozzle. 4. Partial plugging of drawoff nozzle. The case study is due to item 4 as illustrated from the experience of Lieberman. Figure 16.86 shows the side draw­ off from a fractionator. Slowly opening the pump’s discharge control valve increases flow up to a point. Beyond this

Pumps  465

Figure 16.79  Simulation results of centrifugal pump P-100 (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

466  Petroleum Refining Design and Applications Handbook Volume 2

Figure 16.80  Simulation results of centrifugal pump P-100 (Continued) (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

Pumps  467

Figure 16.81  Simulation results of centrifugal pump P-100 (Continued) (UniSim Design R443, Honeywell® and UniSim® are registered trademarks for Honeywell Inc. All rights reserved).

468  Petroleum Refining Design and Applications Handbook Volume 2 Building HGF-1

CS-05 Flow: 500 US gpm

Recirc 2

Recirc 1

CS-01 Flow: 800 US gpm

Supply Tank P Set: 0 psi g Level: 10 ft CS-04 Flow: 800 US gpm

Filter Flow: 800 US gpm dP: 10 psi

CS-02 CS-03 Flow: 800 US gpm N-01 Flow: 800 US gpm P: 116.6 psi g

N-02 P: 68.85 psi g CS-06 Flow: 300 US gpm

Recirc Orifice

CS-07 N-Throttle Valve Flow: 500 US gpm North Tank FCV @ 500 US gpm P Set: 20 psi g dP: 20.81 psi Level: 5 ft

N-S Pump TH: (245.2) ft

CS-08 Flow: 300 US gpm S-Throttle Valve South Tank FCV @ 300 US gpm P Set: 25 psi g dP: 14.33 psi Level: 3.002 ft

Lineup: System: FOF US tutorial Date: 28/03/18 9:42 pm Company: A.K.C TECHNOLOGY Project: XYZ PROJECT by: A.K. Coker

Darcy-Weisbach Flow of Fluids Premium 2009 Flow: US gpm Pressure: psi g Size: in Elevation: ft Velocity: ft/sec Length: ft Volume: gallons

Figure 16.82  Process flow diagram of the piping network from the supply tank via N-S centrifugal pump to the north and south tanks (source: Engineered Software, Inc.).

point, the pump’s discharge pressure and discharge flow become erratically low. This implies that the pump is cavitating. The fluid being pumped is hot water, and at the desired flow rate of 110 gpm, the manufacturer’s pump curve shows that the pump requires 14ft. NPSH. The elevation difference between the draw – off nozzle and the suction of the pump is 46 ft. By reducing the flow of water by 10% to 100 gpm, the cavitation stops. With a pressure gauge on the suction of the pump, and assuming that the suction line is full of 46 ft. H2O, the suction pressure is:



46 ft + 30 psig = 50 psig 2.31 ft psi

Assuming that SpGr of H2O = 1.0 However, the observed pressure is not 50 psig; it is only 47 psig indicating that 3 psig of 7 ft liquid is missing. i.e.,



(50 psig − 47 psig) × 2.31 ft/psig = 7 ft

The likely explanation for this head loss of 7 ft is frictional loss in the suction line. This reduces the NPSHA from 46 to 39 ft. But this is still a lot more NPSHA than the 14ft. of the NPSHR needed to pump 110 gpm. In opening the discharge flow-control valve sufficient to increase the flow from 100 to 110 gpm or by 10%, this would increase the frictional loss in the suction piping by 21%, or about 0.5 psi (∆P varies with Q2). However, this was not observed as the pressure in Figure 16.86 slips slowly down from 47 to 34 psig, at which point the pump begins to cavitate. How could a 10% increase in the flow rate through the pump cause a 400% increase in the pressure drop in the suction line? What has happened to the lost 13 psig (i.e., 47–36 psig) of suction pressure?

Pumps  469 ISOMETRIC EXAMPLE This example shows the completed US Tutorial example laid out on an isometric grid. To change your grid layout to isometric format, go to System / Settings and click on the Drawing Options tab. Under the Grid Options section, check the box next to Isometric, and click OK. You can change the grid layout at any time during the modeling of a PIPE-FLO system.

pm Sg -07 0 U CS : 50 w Flo lve Va gpm ttle US hro 500 psi T N V @ :81 FC : 20 dP

CS-01 Flow: 800 US gpm

Supply Tank P Set: 0 psi g Level: 10 ft

Fil CS Flo ter Flo -04 dP w: 8 w: : 10 0 0 80 0U psi US g Sg pm p

: 11

6.6

1 circ Re

psi

g

pm Sg 0U

-08 CS : 30 w Flo lve m Va S gp e l U tt hro 300 si S-T V @ :33 p FC : 14 P d

Re Flo circ 2 w: 0U Sg pm

NCS Flo -02 TH S Pu : (2 mp w: 800 U 45 Sg pm .2) Nft P 01

k Tan si g rth 0 p No et: 2 5 ft P S vel: Le

e ific Or circ i R e : 0 ps P d

CS Flo -03 w: 80 0

m NP: 6 02 8.8 5

k Tan si g uth 5 p ft So et: 2 3.002 S P vel: Le

pm Sg -05 0 U CS w: 50 Flo

psi

g

CS Flo -06 w: 30 0U Sg pm

US gp m Lineup: System: FOF US tutorial-isometric Date: 28/03/18 9:49 pm Company: A.K.C TECHNOLOGY Project: XYZ by: A.K. Coker

Darcy-Weisbach Flow of Fluids Premium 2009 Flow: US gpm Pressure: psi g Size: in Elevation: ft Velocity: ft/sec Length: ft Volume: gallons

Figure 16.83  Isometric diagram of the piping network from the supply tank via N-S centrifugal pump to the north and south tanks (source: Engineered Software, Inc.).

The boiling point pressure of the water is equal to 30 psig (the pressure in the tower shown in Figure 16.86); that can be assumed that the water drawoff is at its bubble point pressure. At 36 psig pump suction pressure, the NPSHA is:



(36 psig − 30 psig) × 2.31 = 14 ft

This matches the NPSHR at a flow of 110 gpm, such that the pump cavitates. Half of the 46 ft of liquid head to the pump is missing, and where could it be? Figure 16.87 illustrates the true situation. If 110 gpm is being pumped at the discharge, but only 109 gpm can be drain through the drawoff nozzle. If the water level in the suction line is slowly lowered, the water level would creep down as would the pump’s suction pressure. When the water level in the suction line dropped to 14 ft, the pump would cavitate or slip. The flow rate from the pump would drop, and the water level in the suction line to the pump would partially refill. The pump’s NPSHR would then be temporarily satisfied. Normal pump operation would be restored, but only temporarily. Although, it may seem that the draw-off nozzle is undersized as this may be determined by calculating the velocity, (v, ft/s) through the nozzle:



∆H = 0.34 v2

(16.94)

Head - ft

NPSHr - ft

0

100

0 200

25

50 50

100

150

200

250

7 in

300 8.125 in

350

400

10 in

100

100

100

200

200

200

300

300

300

500

500

500

600

600

600

65

60 Hz Centrifugal Demo Catalog Catalog: , Vers ESP - 3600

400

400

400

60

60

700

US gpm

700

700

70.6

70

Figure 16.84  Centrifugal pump characteristics (source: Pump-FLOTM, Engineered Software Inc.).

Company: A.K.C TECHNOLOGY Name: A.K. Coker 3/28/2018

Power - hp

450

800

800

800

73

65

1000

1000

1000

Size: 4×3-13 Speed: 3550 rpm Dia: 8.125 in Curve: ABC1062-1

900

900

900

74

1100

1100

1100

74

1200

1200

1200

73

1300

1300

1300

70

1400

1400

1400

470  Petroleum Refining Design and Applications Handbook Volume 2

Pumps  471 Pump Data Sheet - 60Hz Centrifugal Demo Catalog

Company: A.K.C TECHNOLOGY Name: A.K. Coker Date: 3/28/2018

Pump:

Operating Point:

Size: 4×3-13 Type: ESP Synch speed: 3600 rpm Curve: ABC1062-1

Flow: --Speed: 3550 rpm Dia: 8.125 in Impeller:

Specific Speeds:

Ns: 1190 Nss: 9700

Dimensions:

Suction: 4 in Discharge: 3 in

Pumps Limits: Temperature: 300 °F Pressure: 375 psi g Sphere size: 0.157 in

Fluid: Water Density: 62.37 lb/ft 3 Viscosity: 1.105 cP NPSHA: ---

Temperature: 60 °F Vapor pressure: 0.2563 psi a Atm pressure: 14.7 psi a

Motor: Power: --Eye area: ---

Flow:

710 US gpm

Head:

261 ft

Eff:

70.6%

Power:

66.5 hp

NPSHr:

23.3 ft

Shutoff dP:

128 psi

Min flow:

350 US gpm

65

70

73

74 74

400

73 350

Head - ft

295 ft

60

450

---- Design Curve ---Shutoff head:

Size: 100 hp Speed: 3600 Frame: 405TS

10 in

---- Data Point ----

BEP:

Head: ---

Preferred Operating Region: 70% – 120% BEP

70.6% @ 710 US gpm

300 8.125 in

70.6

250 200

NOL power: 81.7 hp @ 1048 US gpm

70

7 in

65 60

150

-- Max Curve -Max power: 165 hp @ 1336 US gpm

100

NPSHr - ft

50 50

500

750

1000

1250

250

500

750

1000

1250

250

500

750

1000

1250

25

0 200

Power - hp

250

100

0

US gpm

Figure 16.85  Pump data sheet of N-S centrifugal pump (source: Pump-FLOTM, Engineered Software Inc.).

472  Petroleum Refining Design and Applications Handbook Volume 2

30 psig 18 in

46 ft

Hot water

Figure 16.86  Partly plugged drawoff nozzle [27].

Partly plugged nozzle

18 in

32 ft

14 ft

Figure 16.87  Most common cause of cavitation [27].

Pumps  473 Where ∆H is the hydraulic head in inches of liquid required to push 110 gpm of liquid through the draw-off nozzle. Lieberman [27] found ∆H to be 9 in. of H2O; there is twice as much pressure loss through the nozzle than intended, indicating that the draw-off nozzle must be partly plugged. It has been shown that many draw nozzles and especially those in the bottom of vessels plug because of the presence of vortex breakers. Many designers routinely add complex vortex breakers to prevent cavitation in pumps. However, these are only required in nozzles operating with high velocities and low liquid levels. Corrosion products, debris, and products of chemical degradation can more easily foul and restrict nozzle equipped with vortex breakers. Furthermore, lack of NPSHA may be caused by high frictional loss in the suction piping. In this instance, a small reduction in flow will increase the pressure at the suction of the pump. A properly designed suction line to a centrifugal pump should have a frictional head loss of only a few feet of liquid. A large diameter suction line and a relatively small draw-off nozzle can result in excessive loss of NPSHA.

Case Study 3. Low NPSHA at Main Column Bottoms (MCB) An FCC main column bottoms (MCB) pump was specified with an NPSHA of 8 ft. Therefore a low NPSHR was selected and installed. When equipment reliability was poor, the contractor and operator blamed the original equipment manufacturer (OEM). However, the root cause was the design engineer’s ultra-conservative specification of the NPSHA. New pumps are frequently installed during revamps where they must fit into an existing process system and operate within constraints. The designer must ensure cost effective solutions working with the existing equipment, and when trying to install new pumps, plot space will often determine location rather than ideals such as minimum suction piping run. Figure 16.88 shows a typical FCC main column bottoms (MCB) system. Reactor effluent enters the column at temperature of 980–1015°F (527–546°C) where the MCB system must remove up to 35% of the heat so the reactor

Boiler feed water preheat

Reactor effluent

FRC R

690

Main column bottom pump

Figure 16.88  Main column bottom system [34].

Debutaniser reboiler

600 psig steam Temperature, °F

474  Petroleum Refining Design and Applications Handbook Volume 2 products can be fractionated. Fluid mixed with catalyst and coke fines is withdrawn from the bottom of the main column and pumped through heat exchangers, then back to the column as sub-cooled pump around return (PAR) and quenched. PAR liquid flows down the column through internals such as shed trays or grid where heat is transferred from reactor effluent to the PAR liquid. To prevent coke formation, must refiners maintain a constant temperature in the bottom of the main column by varying quench flow rate. The MCB circulation rate depends on the system design, and the operating philosophy can cause large flow variability from the start-of-run (SOR) to end-of-return (EOR). Before detail pump hydraulic calculations, the process engineer determines the total (PAR plus quench) heat removal requirements from the design basis heat and material balance around the column. Then, the MCB circulating rate is calculated based on the exchanger configuration and its tendency to foul. The pump design point matches the real operation, but the system design requires the flexibility to meet realistic process variability. Furthermore, operating philosophy influences SOR and EOR conditions, which determine maximum and minimum flow. If the main column bottoms temperature is held constant from SOR to EOR, then flow rate will be low at SOR when exchangers are clean and increase as the exchangers foul. The rate of exchanger fouling depends on velocity through the exchanger tubes and fluid temperature throughout the main column bottoms pool.

16.32 Pump Fundamentals As illustrated in the text, the selected pump requires a certain amount of NPSHR to operate properly and the NPSHA needs to be higher than NPSHR for stable and reliable pump performance through the run. NPSHA is the amount of head available at the pump suction above the fluid vapor pressure. Liquid level, suction piping pressure loss, and fluid vapor pressure determine the NPSHA. When the designer specifies the NPSHA, this value plays a critical role in the pump selection and it determines stable operating range for the MCB pump. Pump impeller eye design is characterized by:

Nss =



N Q NPSH0R.75

(16.69)

and NPSHR is equal to the inlet velocity head:



NPSHR =

v2 2g

(16.95)

At the pump inlet, the velocity is a function of the volumetric flow rate and inlet area:



v=

Q A

(16.96)

where A = inlet area of pump, ft2 Nss = suction specific speed (dimensionless) n  = pump speed, rpm Q = flow at the best efficiency point (BEP), gpm A high value of Nss corresponds to a low NPSHR; it would be assumed that a higher suction specific speed is better. Eqs. 16.69 and 16.95 show that the easiest way to reduce the NPSHR for a particular flow is to increase the inlet

Pumps  475 area; however, this is not a good practice because it increases the minimum flow rate for the pump. The minimum continuous stable flow (MCSF) is the lowest flow rate at which the pump can operate without exceeding the vibration limits imposed by API 610. The BEP is the flow/head combination that corresponds to the highest efficiency. As the flow rate drops below that of the BEP, the NPSHR by the pump initially decreases until it reaches a minimum before beginning a steady increase (Figure 16.18). Pumps with high suction specific speed will have correspondingly high minimum flow requirements that will likely require a recirculation line to provide satisfactory operation. Common practice is to keep NSS between 7,000 and 12,000 depending on the fluid. When a pump cannot be found that meets the suction specific speed criteria for a particular project, a recirculation line can be added to meet the minimum flow requirement [24]. Another important parameter is the minimum continuous thermal flow (MCTF) and as defined by API 610: the lowest flow rate at which the pump can operate without being impaired by the temperature increase of the pumped liquid. MCSF refers to recirculation of the fluid that can result in cavitation and vibration; MCTF is concerned with temperature rise. From Figure 16.18, the efficiency drops corresponding to a decrease in flow below the best efficiency point (BEP). This decrease in efficiency is characterized by an increase in temperature. MCTF is the point at which this rate of temperature rise obstructs the operation of the pump. The minimum operating flow is the higher of MCTF and MCSF. Generally, MCSF occurs at a higher flow rate than MCTF and becomes the defining variable. For very-low flow pumps, MCTF may be prevalent.

NPSHA In Figure 16.88, the pump of the MCB was initially specified with an NPSHA of 8 ft. Therefore, a low NPSHR pump was selected and installed. However, when equipment reliability was poor, the contractor and operator blamed original equipment manufacturers (OEM). However, the root cause was the design engineer’s ultra-conservative specifications of the NPSHA [34]. NPSHA is based on the pump system configuration, the fluid flow rate and properties. Liquid level above pump centerline, fluid vapor pressure and system pressure drop all influence NPSHA. Once the plot space for the pump is selected and pipe routing set by pipe stress considerations, system ∆P cannot be materially lowered by the designer. First the designer requires defining the minimum acceptable level. It is the bottom of the head, vessel tangent line or low liquid level? Figure 16.89 illustrates how there can be a 6 ft (1.8 m) difference between the most conservative method, which uses the bottom of the head, and least that uses the low liquid level. This is the difference of between 8 ft and 14 ft (2.4 m and 4.3 m) NPSHA, and more importantly, allows the refiner to select a pump that turns down to 65–70% BEP flow rate rather than one that turns down to only 80–85% of BEP flow [34]. Furthermore, the fluid vapor pressure can be reduced by 5 ft (1.5 m) for every 10°F reduction in the main column bottoms pool liquid temperature. Reducing pool temperature from the 690°F to 680°F (366°C to 360°C) increases NPSHA from 14 ft to 19 ft (4.3–5.8m) (Figure 16.90).

16.33 Operating Philosophy Instead of maintaining constant MCB temperature, the exchanger velocity should be controlled by allowing the temperature in the bottom of the main column to vary from start-of-run (SOR) to end-of-run (EOR) by adjusting the quench flow rate. As the exchanger fouls, the PAR rate increases and the quench flow decreases so that exchanger velocity is maintained. Using this approach, the exchanger fouling is reduced, MCB pump erosion decreases, and the rate of coke formation in the bottom of the main column reduces. Furthermore, the MCB exchanger tube velocity should be maintained between 10 and 13 ft/s (3–3.9 m/s) to minimize fouling. When MCB system operates to maximize exchanger velocity at SOR, the NPSHA is very high because the main column temperature is low resulting in low fluid vapor pressure [34].

476  Petroleum Refining Design and Applications Handbook Volume 2

Reactor effluent

Normal liquid level

Quench

LC

Low liquid level Vessel tangent line

25'–0" 22'–0" 19'–0" Main column bottoms pumps

Figure 16.89  Main column bottom pump level [34].

Boiler feed water preheat

Reactor effluent

FRC R Quench distributor

680

Main column bottom pump

Figure 16.90  Main column bottom quench system [34].

Debutaniser reboiler

600 psig steam Temperature, °F

Pumps  477

Main Column Bottoms (MCB) Pump Specification MCB pump reliability is an important part of FCC unit profitability. Therefore, the process engineer should review opportunities to improve MCB system performance before selecting a MCB pump. Selecting a pump that operates as close as possible to the BEP flow minimizes pump erosion and maximizes operating flexibility. Furthermore, MCB pump specification should not use an ultra-conservative NPSHA. Since NPSHR value decreases in Eq. 16.69, suction specific speed increases, and consequently, pump stable flow range also decreases. When constant MCB temperature is the operating objective, MCB flow rate can be less than 60% of design flow rate at SOR when MCB exchangers are clean. A pump selected to operate with only 8 ft of NPSHA will not turn down to 60% of BEP. Process designs that permit higher quench flow rates at SOR minimize pump flow variation and maximize exchanger velocity. Operating philosophy should be changed from constant main column bottoms temperature to constant MCB recirculation rate by varying quench flow from SOR to EOR. Also, lowering bottoms temperature reduces the vapor pressure and subsequently increases NPSHA without significant changes in pump flow rate or the heat exchanger performance. Therefore, a more reliable lower Nss pump can be selected with better turndown [34].

Frequent Loss of Suction of Vacuum Residue Pumps at Vacuum Column Bottom A set of two pumps located in the vacuum column bottom in the fuel-type vacuum unit of a refinery were losing suction frequently [44]. They were vertical-split, multistage pumps with four stages in each. The suction line to each pump entered the pump vertically. A new set of pumps with a newer mechanical seal design was purchased to solve the problem and installed, but the loss of suction of the pump in the vacuum unit still continued. The supplier of the pump, along with the supplier of the mechanical seal and other pump experts inspected the unit but could not come to an agreement on what was causing the loss of suction, so the problem continued. To identify the root cause, a pressure survey was carried out with a compound gauge during the operation of the pump (see Figure 16.91). An equation can be written as P2 = P1 + h − DPf. The pressure was noted as P1 and P2 and the height h between points P1 and P2 was measured. The pressure drop due to flow (DPf value) was calculated using the above equation and found to be almost negligible, indicating that there was no choking in the suction line or the column bottom coke trap. The pressure at point 4 (P4 at the pump suction strainer downstream) was found to be 2 meters of liquid column (mLC), which is lower than the NPSHR of 3.5 mLC for the pump. Thus, it was concluded that lower NPSHA was causing the pump to lose suction. The lower NPSHA was attributed to higher pressure drop across the strainer. But no muck was found in the strainer to cause the pressure drop. The inlet and outlet pressures were measured again with a calibrated compound gauge. The openings of the strainer were also checked and found to be around five times the cross-sectional area of the suction pipe, which was acceptable. The reason for the higher pressure drop across the suction strainer continued

P1

Coke P4

P3

h

trap

P2

Suction strainer

Figure 16.91  Pressure survey of the pump suction line [44].

Suction valve

478  Petroleum Refining Design and Applications Handbook Volume 2

Coke PI

PI

Suction strainer

To pump

trap

Suction block valve

PI – Pressure indicator

Figure 16.92  Pressure survey of the pump suction line across strainer [44].

to be a mystery. The suction line oil-soaked insulation was removed by the maintenance group, possibly for a change of insulation, and the bare suction pipe section became visible. It was discovered that the strainer was too close to the reducer in the suction line. It was suspected that the convex part of the strainer may be leaving very low clearance for the flow due to its proximity to the reducer (Figure 16.92). The suction pool was taken out and a modification was carried out to move the reducer away from the suction strainer and toward the suction of the pump (a distance of more than five times the diameter of the pipe). The new spool was fabricated and fitted and the pump tested. The pressure drop disappeared across the strainer and the strainer downstream pressure was found almost equal to the strainer upstream pressure and higher than the NPSHR by the pump. The problem totally disappeared and performance of the pump became normal.

Failure of Pumps in a Hydrocracker In a newly commissioned hydrocracker, the bottom pumps of the stripper and the main fractionator as well as some other pumps were repeatedly losing suction, making the unit unstable [44]. The pumps had a suction line arrangement as illustrated in Figure 16.93. The strainers were installed from the side and the line to the pump suction was taken through a tee pipe below the strainer. It was decided to replace the pumps with new pumps with a lower suction NPSHR. A pressure survey was carried out in the suction line as shown by the points P1 and P2. The height between P1 and P2 is indicated by h. The calculation is: P2 = P1 + h x ρ − DPf. The pressure drop due to flow (DPf ) was calculated from the measured data and was found to be negligible, confirming no choking in the lines or column outlet nozzles. The strainer could not be inspected as the pump isolation could not be achieved because the suction valves were not holding properly. The drawing of the strainer was found, which showed that the strainer was similar to a straight pipe with perforations indicating that the design was incorrect. This is because the perforations on the straight portion of the strainer would provide less flow area through the perforations (lower than the cross-sectional area of the suction pipe). The strainer design was modified with a curved surface facing the pump suction to provide more holes in the curved surface and consequently greater flow area (Figure 16.94). The unit was replaced with the modified strainer arrangement and the problem was resolved. The performance of all the pumps became normal.

Oil Refinery Fire and Explosion at Ciniza Oil Refinery, New Mexico, USA A fire and explosion occurred at the Giant Industries’ Ciniza oil refinery in Jamestown, New Mexico, on April 8, 2004. The incident occurred in the refinery’s hydrofluoric acid (HF) alkylation unit. Alkylation is a standard oil refinery process that

Pumps  479 P1

h

P2

Figure 16.93  Column outlet piping scheme and pressure survey.

Original strainer

Fluid

Strainer

To Pump

Modified strainer

Fluid

Strainer

To Pump

Figure 16.94  Original and modified strainer.

combines olefins with isobutane using a catalyst HF to produce alkylate. Alkylate is a highly flammable gasoline blending component used to boost the octane of gasoline. It forms explosive vapor/air mixtures at above-ambient temperatures. The day before the incident, alkylation unit operators performed a regularly scheduled switch of the alkylate recirculation pumps in the iso-stripper section of the alkylation unit. The primary electric pump would be taken out of service and the spare steam-driven pump started up. The switch was scheduled because of recurring problems with the spare pump’s mechanical seal leaking. Mechanical seals are used to keep the contents of rotating equipment from escaping. This is done by sealing the shaft that protrudes from the casing. When operators attempted to put the spare pump in service, they discovered that it would not rotate. The next morning, an operator prepared a work permit that outlined the work to be done and the safeguards required for a safe repair*. The valve used to isolate the pump for maintenance was a ¼ turn plug valve. A plug valve is used primarily for on/off, and some throttling services. It controls the flow by a cylinder or tapered plug with a hole in the center that lines up with the flow path of the valve to permit flow. The valve is opened or closed with the use of a valve wrench as illustrated in Figure 16.95. During the preparation for maintenance, the operator relied on the valve wrench to determine that the suction valve was open. He moved the wrench to determine that the suction valve was open. He moved the wrench to what he believed was the closed position with the wrench perpendicular to the flow of product. The pump required to be

480  Petroleum Refining Design and Applications Handbook Volume 2

Valve Wrench

Valve Wrench Collar

Position Indicator

Figure 16.95  Suction valve and position indicator as found after the incident (source: www.csb.gov).

disassembled, and the rear pump housing assembly and impeller moved to the shop for repair. The mechanic noticed that the valve position indicator on the suction valve body showed that the valve was open (Figure 16.95). However, he did not relate this information to his co-workers. The plant operator placed tags on locks on the suction and discharge valves to prevent inadvertent opening and to indicate that the valves had been closed. The mechanic specialist then placed tags and locks on the suction and discharge valves. When the mechanic returned, the mechanic specialist told him that the valves had been closed, secured, tagged and locked per the facility’s lockout/tagout (LOTO) procedure, and that they could remove the pump. Neither mechanic observed the operator closing the valve as both mechanics believed the task had been completed because the wrench used to open and close the valve was positioned perpendicular to the flow, and the operator had affixed his tags (Figure 16.95). The operator then disconnected the pump’s vent hose to verify that no pressure was in the pump case. The low point drain plug was not used because it was not equipped with a valve to isolate it from the line used for depressuring the pump (Figure 16.96). After uncoupling the hose at the connection to the flare line, a stream of alkylate flowed from the pump housing through the hose and subsided after a few seconds. The operator and the maintenance mechanics believed the pump had been de-pressured and was ready for removal. However, the vent line was plugged, and the pump was not depressured. The pump shaft coupling and the flange connecting the pump to the pump case were unbolted (Figure 16.97). As the pump case flange was separated, alkylate was suddenly released at about 150 psig and 350°F. The release produced a loud roaring sound that could be heard throughout the refinery. The mechanic was blown over an adjacent pump and suffered broken ribs. Material was blown into the mechanic’s eyes and had to make his way to an eyewash station. Alkylate, which covered the plant operator’s clothing, quickly ignited seriously burning the operator in the ensuring fire. About 30–45 s after the initial release, the first of several explosions occurred. * The work permit is issued by the operator and contains information on hazards involved in the maintenance operation, the appropriate personal protective equipment to be worn, and lock-out–tag-out (LOTO) information. Lock out/tagout refers to a program to control hazardous energy during the servicing and maintenance of machinery and equipment. Lock out refers to the replacement of a locking mechanism on an energy – isolating device, such as a valve, so that the equipment cannot be operated until the mechanism is removed. Tagout refers to the secure placement of a tag on an energy-isolating device to indicate that the equipment cannot be operated until the tag is removed.

Pumps  481

Vent Hose

Low Point Bleeder

Figure 16.96  Depressurizing hose (source: www.csb.gov).

Rear Pump Assembly

Pump Case Flange

Figure 16.97  Damage to area of the pump (source: www.csb.gov).

The U.S. Chemical Safety and Hazard Investigation Board (CSB) findings related to this explosion are:

Mechanical Integrity Giant’s mechanical integrity program did not effectively prevent repeated failures of the pump seals. Problems were addressed when equipment broke down, not in a preventive manner. The design of the valve wrench made it easy to remove and reposition onto the valve stem in different directions, and this led to a potential hazard because operators sometimes determined whether the valve was open by its wrench position, rather than the valve position

482  Petroleum Refining Design and Applications Handbook Volume 2 indicator. In this incident, the valve wrench collar was installed in the wrong position. Operators depended on the wrench position and mistakenly determined the valve was closed. Plugging material was found in the pump discharge line, the depressuring line, pump housing, and the impeller (Figure 16.98). Giant’s approach to these frequent pump seal problems was an example of break down maintenance. Pump failures were addressed when the equipment finally broke down instead of identifying causes of breakdowns and preventing them before they occurred again. The Center for Chemical Process Safety (CCPS) recommends that maintenance program, troubleshoot and search for possible hidden or multiple reasons for frequent occurring problems [45]. An effective mechanical integrity program would have investigated and resolved the problems that were repeatedly causing the recirculation pump seals to fail.

Corrosion and Scale Formation At Giant, the isostripper pumps frequently had plugging problems. A number of factors contribute to the formation of corrosion, scale, and deposits, which in turn can lead to the fouling or scoring of pump seals. Although, the failure of the seals is not often caused by corrosion of the seal faces, but by the scoring/erosion (galling) of the seal faces from a solid fouling material. Carbon seal faces such as those used for the pump involved in this incident are prone to contaminant scoring. Some corrosion and scale products occur because of operating temperatures and pressures at which hydrofluoric acid (HF) alkylation unit is run. Many HF alkylation units operate at about 125 psig or lower. The isostripper column at the Giant refinery is normally operated at about 150 psig. Operation at higher pressures requires much higher temperatures, which can result in accelerated corrosion of equipment. Plugging and fouling material can also occur as soft iron fluoride scale develops and forms in the tower overhead and domes when preparing to shut down the unit for maintenance/cleanup activities. Some of this soft, water – laden scale comes off when the unit is running. The rest creates a site for extremely fast and extensive corrosion, resulting in a large amount of scale being added into the process. Scale many accumulate and settle at low points and orifices in equipment such as spare pumps. Management did not investigate why excessive iron fluoride generation in the process caused the mechanical seals on the alkylate recirculation pump to fail repeatedly.

Valve Design Examination of the 6 in., ¼ turn, plug valve after the incident determined that it was originally designed to be opened and closed by a gear-operated actuator. The gear-driver was removed and was replaced by a valve wrench. The wrench was a two-foot-long bar inserted into a collar. Because it had a square shape, the collar could be easily removed and repositioned on the valve stem in different directions (Figure 16.99). Giant did not consider the design or engineering safety implications of changing from a gear-operated valve actuator to using a wrench as a valve handle. Interviews with operators revealed that they would sometimes determine whether the valve was opened or closed by the valve wrench position. If the wrench was perpendicular to flow through the valve, it was considered closed. If the wrench was aligned parallel to the flow, the valve was thought to be open. There are instances where set screws would be loosened, and the wrench would be removed and placed on the pump based to provide better clearance for personnel walking nearby. When the valve was to be opened or closed, the wrench would be replaced on the valve stem. In the Ciniza oil refinery incident, the valve wrench collar was installed in the wrong position. Figure 16.100 illustrates a drawing of the plug valve in the open position with the wrench in the perpendicular or perceived “closed” position. Both the plant operator who attached the locks and the mechanics who removed the pump mistakenly believed the suction valve had been closed, in part because the valve wrench was perpendicular to the normal pipe flow. After he returned from obtaining materials needed for pump removal, the mechanic who earlier observed the position indicator in the open position began working on the opposite side of the pump, not realizing that the valve position indicator still indicated the valve was open. From his position, he observed the valve wrench in a perpendicular orientation and believed the valve was closed. The wrench was not intended to indicate valve position because the valve was equipped with the position indicator, which was located on the valve stem as shown in Figure 16.101.

Pumps  483

Figure 16.98  Plugging material found in discharge valve (source: www.csb.gov).

Figure 16.99  Spare pump valve wrench collar (source: www.csb.gov).

484  Petroleum Refining Design and Applications Handbook Volume 2

Figure 16.100  Plug valve in the open position (source: www.csb.gov).

Figure 16.101  Suction valve and position indicator (source: www.csb.gov).

Pumps  485

Management of Change The CSB urges management of change analyses for any valve modifications, effective “lock out tag out” programs to ensure equipment has been isolated, depressurized, and drained; and proper mechanical integrity programs to prevent breakdown maintenance. The study stated that Giant should have determined the cause of the frequent alkylate recirculation pump malfunctions and implemented a program to prevent them. A CSB member stated that proper mechanical integrity programs and effective management of change analyses are essential components of safe operations at any refinery. Occupational Safety and Health Administration (OSHA) Process Safety Management standard (1910.119) states that any change that may affect a process covered by that standard should trigger a management of change (MOC) analysis. The only exception to this is when the change is a “replacement in kind” [46].

16.34 Piping Pump requirements, nozzle size, type of fluid, temperature, pressure and economics determine materials and size of piping. Suction lines should be designed to keep friction losses to a minimum. This is accomplished by using an adequate line size, long radius elbows, full bore valves, and so on. Pockets where air or vapor can accumulate should be avoided. Suction lines should be sloped, where possible toward the pump when it is below the source and toward the source when it is below the pump. Vertical downward section pipes require special care to avoid pulsation and vibrations and could result in air or vapor entrainment. Adequate liquid height above the suction piping inlet, or a vortex breaker should be provided to avoid vortex formation which may result in vapors entering the pump. Furthermore, suction vessel tangential inlets and centrifugal pumps may induce a vortex in the vessel and pump suction line thereby opening a vapor core that feeds into the pump suction. All these can be eliminated with a straightening cross known as a vortex breaker, installed at the vessel outlet nozzle. For discharge piping, sizing is determined by the available head and economic considerations. Velocities range from 3–15 ft/s. A check valve should be installed between the discharge nozzle and the block valve to prevent backflow [30].

16.35 Troubleshooting Checklist for Centrifugal Pumps Centrifugal: Good practice: head-capacity curve should not be too flat if pump capacity is controlled by valve positioned. Select pump such that a larger diameter impeller could be installed later. An increase in flow rate causes an increase in NPSHR and a decrease in NPSHA [29]. Loss of prime is one of the common problems that will be encountered during daily trouble shooting. This may be caused by incomplete venting, a blocked suction line or entrained gases in the liquid. Entrainment can result from a number of situations including: 1. 2. 3. 4.

 aving incoming lines in the suction vessel above the liquid’s surface. h vortexing in the suction vessel. air leaks through joints valve packing or pump packing. flashing of low boiling points.

The reason a centrifugal pump stops pumping liquid when the impeller becomes filled with air is that its output pressure in psi (bar) is drastically reduced. The impeller may be creating about the same head in feet of fluid but the specific gravity of the fluid has changed from that of liquid (1.0 for water at 20°C) to that of air (0.00123). Therefore, a water pump generating 100 ft of head or 43.3 psi (i.e., psi = (ft. of fluid) (Sp.Gr.)/2.31)) will only generate about 0.053 psi when it becomes “air bound”. As the liquid in the discharge line requires a given pressure to move it at a certain velocity, the sudden reduced pressure allows flow to stop.

486  Petroleum Refining Design and Applications Handbook Volume 2 The following problems associated with centrifugal pumps and corrective modes of action should be taken. Symptoms

Possible causes

No liquid delivery

Instrument error Not primed Cavitation Supply tank empty

Liquid flow rate low

Instrument error Cavitation Non-condensibles in liquid Inlet strained clogged

Intermittent operation

Cavitation Not primed Non-condensibles in liquid

Discharge pressure low

Instrument error Non-condensibles in liquid Speed too low Wrong direction of rotation (or impeller in backwards if double suction)

Power demand excessive

Speed too high High liquid density Required system head lower than expected High viscosity

Peripheral: No liquid delivery

Instrument error Pump suction problems Suction valve closed Impeller plugged

Liquid flow rate low

Instrument error Speed too low Incorrect impeller trim Loose impeller

Discharge pressure low

Instrument error Speed too low Incorrect impeller trim Loose impeller

Power demand excessive

Speed too high Improper impeller adjustment Impeller trim error

Cavitation

Liquid too hot Non-condensibles in liquid Air leakage into suction line Vortex entraining gas Decrease in density of the liquid Blockage or excessive ∆p on suction Suction velocity too high Increase in rpm

Pumps  487 Table 16.10 shows the various problems that often occur in the operation of centrifugal pumps and means of detecting and rectifying these occurrences [30].

Pump Installation Check List Production operators should be trained in pump fundamentals as this ensures good operation and low maintenance costs. Often some operators are accused after incidents of being careless with equipment when in truth; they have never had proper training. The specialist can be used to provide training sessions for plant operators. Furthermore, an individual or team in either maintenance or the engineering department should be assigned to perform trouble shooting as indicated in Table 16.10. A summary of the installation checkpoints is presented in Table 16.11.

Factors in Pump Selection The selection of a pump depends on several factors, which include the properties of the pumped fluids, the required capacity, and the desired location of the pump. Generally, high viscosity liquids are pumped with positive displacement pumps. Centrifugal pumps are not only very inefficient when pumping high viscosity liquids but their performance is very sensitive to changes in liquid viscosity. A high viscosity liquid also results in high frictional head losses and a reduced NPSHA. Since the latter must be greater than NPSHR by the pump, a low NPSHA imposes a severe limitation on the choice of a pump. Liquids with a high vapor pressure also reduce the NPSHA. If these liquids are pumped at a high temperature, this may cause the gears to seize in a close clearance gear pump. Correspondingly, if the liquid being pumped is shear thinning, its apparent viscosity will decrease with an increase in shear rate and thus the pumping rate. It is therefore an advantage to use high speed pumps to pump shear thinning liquids and in fact centrifugal pumps are frequently employed. In contrast, the apparent viscosity of a shear thickening liquid will increase with an increase in shear rate and thus the pumping rate. Therefore, it is advantageous to use large cavity positive displacement pumps with a low cycle speed to pump shear thickening liquids [37]. Some liquids can be permanently damaged by subjecting them to high shear in a high speed pump. For example, certain liquid detergents can be broken down into two phases if subject to too much shear; although these detergents may exhibit shear thinning characteristics, they should be pumped with relatively low speed pumps. Positive displacement pumps are more susceptible to wear than with centrifugal pumps. Liquids with poor lubricating qualities increase the wear on a pump. Furthermore, wear is a result of liquids containing suspended solids that are abrasive and by corrosion. In general, centrifugal pumps are less expensive, last longer and are more robust than positive displacement pumps. However, they are unsuitable for pumping high viscosity liquids and when changes in viscosity occur (see Table 16.5).

Pump Reliability Pumps are essential to the daily operation of refinery and industrial chemical processes, as they are the workhorses of the plant, and require constant maintenance to ensure the availability of the business. Pumps start to degrade the day they start up, and the challenge is to know when and how to intervene before they contribute to a critical plant shutdown or slowdown, impacting the company’s bottom line. A typical pump failure can result in a very high cost in thousands of dollars and a bigger incident could draw media attention. This can negatively impact public image as well as increase the possibility of fines and government involvement. Worse, serious problems may affect the safety of plant personnel and the environment. Few pumps that are critical to operation may have on-line condition based monitoring as these systems minimize unnecessary maintenance common with preventive (time-based) maintenance while avoiding catastrophic failures that result in expensive repairs, fire and plant downtime. In a typical refinery, these may account for approximately 10% of pumps. That leaves about 90% of pumps subject to manual rounds of a technician/operator to acquire data and assess pump condition, preventive maintenance tasks, or running-to-failure.

488  Petroleum Refining Design and Applications Handbook Volume 2 Table 16.10  Troubleshooting centrifugal pumps. Symptoms

Possible causes

Failure to deliver liquid

1. 2. 3. 4. 5. 6. 7. 8.

Pump does not deliver rated capacity

1. Wrong direction of rotation. 2. Suction line not filled with liquid. 3. Air or vapor pocket in suction line. 4. Air leaks in suction line or stuffing boxes. 5. Inlet to suction pipe not sufficiently submerged. 6. NPSHA not sufficient. 7. Pump not up to rated speed. 8. Total head greater than head for which pump designed. 9. Foot valve too small. 10. Foot valve clogged with trash. 11. Viscosity of liquid greater than that for which pump designed. 12. Mechanical problems. (a) Wearing ring worn. (b) Impeller damaged or worn out. (c) Internal leakage resulting from defective or damaged gaskets. 13. Discharge valve not fully opened.

Pump does not develop rated discharge pressure

1. Gas or vapor in liquid. 2. Pump not up to rated speed. 3. Viscosity of liquid greater than that for which pump designed. 4. Wrong direction of rotation. 5. Mechanical problems: (a) Wearing rings worn. (b) Impeller damaged or worn out. (c) Internal leakage resulting from defective or damaged gaskets.

Pump loses liquid after starting

1. 2. 3. 4. 5. 6. 7. 8.

Pump over loads driver

1. 2. 3. 4.

 rong direction of rotation W Pump not primed Suction line not filled with liquid Air or vapor pocket in suction line. Inlet to suction pipe not sufficiently submerged. NPSHA not sufficient. Pump not up to rated speed. Total head required greater than head which pump is capable of delivering.

S uction line not filled with liquid. Air leaks in suction line or stuffing boxes. Gas or vapor in liquid. Air or vapor pocket in suction line. Inlet to suction pipe not sufficiently submerged. NPSHA not sufficient. Liquid seal piping to lantern ring plugged. Lantern ring not properly located in stuffing box.

S peed to high. Developed head greater than rated head. Excessive recirculation. Either or both the specific gravity and viscosity of liquid different from that for which pump is rated. 5. Mechanical problems: (a) Misalignment. (b) Shaft bent. (c) Rotating element dragging. (d) Packing too tight. (Continued)

Pumps  489 Table 16.10  Troubleshooting centrifugal pumps. (Continued) Symptoms

Possible causes

Excessive vibration

1. Starved suction. (a) Gas or vapor in liquid. (b) NPSHA not sufficient. (c) Inlet to suction pipe not sufficiently submerged. (d) Gas or vapor pockets in suction line. 2. Misalignment. 3. Worn or loose bearings. 4. Rotor out of balance. (a) Impeller plugged. (b) Impeller damaged. 5. Shaft bent. 6. Improper location of control valve in discharge line. 7. Foundation not rigid.

Stuffing boxes overheat

1. 2. 3. 4. 5. 6. 7.

Bearings overheat

1. Oil level too low. 2. Improper or poor grade of oil. 3. Dirt in bearings. 4. Dirt in oil. 5. Moisture contamination in oil. 6. Oil cooler clogged or scaled. 7. Failure of oiling system. 8. Insufficient cooling water circulation. 9. Insufficient cooling air. 10. Bearing too tight. 11. Bearing over-lubrication (when grease lubricants are used). 12. Misalignment.

Bearings wear rapidly

1. 2. 3. 4. 5. 6. 7. 8. 9.

 acking too tight. P Packing not lubricated. Wrong grade of packing Insufficient cooling water to jackets. Packing provided improperly. Mechanical seal hydraulic balance improper. Uneven torquing of gland nuts.

 isalignment. M Shaft bent. Vibration. Lack of lubrication. Bearings improperly installed. Dirt in bearings. Moisture contamination in oil. Excessive or insufficient cooling of bearings. Oil/lubricant viscosity not maintained as recommended.

It is estimated that pumps account for 7% of the total maintenance cost of a plant or refinery, and pump failures are responsible for 0.2% of lost production. These avoidable costs could be significantly reduced if the unmonitored pumps had online condition monitoring. This can be decided upon by reviewing those pumps that are at risk to cause process upsets and downtime, often taking hours or days to recover normal operations. Basic pump maintenance is normally performed either by manual rounds or online conditioned-based monitoring (CBM). The aim is to prevent failures that require expensive repairs and cause process slowdowns or shutdowns. However, the former is typically very expensive. Preventive maintenance and manual rounds are not always adequate

490  Petroleum Refining Design and Applications Handbook Volume 2 Table 16.11  Pump installation check list [31]. 1.

The foundation should be substantial to support the pump rigidly and absorb vibration.

2.

The base plate must be leveled on the foundation so the oil in the pump bearing housing will be at the correct level and the oil on the housing will feed properly.

3.

There are two types of coupling misalignment—angular and parallel. Wedges, feeler gauges, or dial indicators are generally used to check alignment.

4.

Factory alignment of the pump and driver must be checked after the complete unit has been leveled on the foundation, and again after the grout has set and the foundation bolts tightened.

5.

Suction piping is especially critical for proper pump operation and should not have pockets that may collect air or have sharp turns at the suction nozzle, which could cause an uneven flow to the impeller.

6.

Very little pipe loading should be imposed on the pump. Expansion joints and pipe supports should be used judiciously.

7.

The direction of rotation should be checked by jogging the motor before the coupling are joined.

8.

A final alignment should be made after the pump has run long enough for temperatures to stabilize. Some manufacturers’ manuals give cold alignment data that indicate the amount of misalignment the couplings should have when cold in order to be correctly aligned at the normal running temperature.

to identify degrading performance in time to act. Most pumps do not operate at optimal efficiency, as processes were not designed for the pump to run at its best efficiency pump (BEP). Some pumps may be over-sized to accommodate design contingencies and planned increase in throughput capacity or have been stretched beyond their design and capacity limits due to production demands. This introduces higher stress on pump system components, leading to higher maintenance requirements. Installing dedicated online monitoring systems as well as overfilled cable trays in highly congested areas has prevented online condition monitoring from being expanded beyond the most critical pumps. However, the relative ease of adding online pump condition monitoring with today’s technology, services now include [40]: 1. 2. 3. 4. 5.

 umps without spares. P Pumps that can cause a fire or environmental incident. Pumps with repeat failures. Pumps that can lead to a significant process disturbance, process shutdown or slowdown. Any pumps that previously were not considered critical enough to have wired monitoring systems in place.

Plants may not have initially invested in online monitoring for pumps that have an installed spare. However, the reason for including an installed spare is that the pump will require maintenance before the next overall turnaround maintenance shutdown. If the operating pump runs-to-failure, it could make the condition worse by increasing maintenance time and cost to repair the damage. The spare pump may take time to start up, which can prevent an operator from making a transfer to a backup pump. This could create a process upset from which hours or days are required to return to normal operation, in addition to the costs of repairing the pump that was run-to-failure. Furthermore, it is more difficult to take a failed pump out of service and commission the spare pump if the failed pump is leaking process material or burning. Figure 16.102 shows typical root causes of pump failures and resulting impacts. Many pump failures can be predicted using modern monitoring techniques such as innovative reliability-centered practices for pump monitoring such as pump seal leaks, cavitation, and vibration related failures. These allow customers to minimize environmental and business impacts. Appendix D shows construction commissioning start-up checklists of rotary equipment such as pumps, compressors and others such as blower, fans and mixers.

Pumps  491 Process Change

Root Cause

Equipment Impact

Environmental Impact

Business Impact

Bad installation Shaft misalignment

Excessive vibration

Bearing wear

Premature bearing ware Reduced unit throughput

Pump failure

Restricted discharge flow

Restricted Suction flow/ Plugged suction strainer Undetected Conditions

Process upsets Excessive maintenance

High discharge pressure

Seal failure

Leaks

Cavitation

Impeller/shaft damage

Hazardous releases

Fires Evening news

Low suction pressure

Rebuild costs

Fires

Human impact Abnormal Situations

Avoidable Consequences

Figure 16.102  Typical root causes of pump failures and resulting impacts [40].

The following three innovative methods of increasing pump availability using predictive technologies and reliability-centered maintenance best practices are as follows [40]: Pump seal monitoring The latest edition of API Standard 682 now shows a preference for level and pressure transmitters instead of level and pressure switches in order to provide the signal to annunciate the level or pressure alarms. The use of transmitters provides an improved view of the pump seal flush reservoirs. A level signal also allows for monitoring the rate of change of a reservoir level for earlier indication of potential seal failure. Cavitation monitoring For high head multistage pumps that cannot tolerate cavitation even for a brief moment, users monitor discharge flow and pressure, the integrity of the level instrument on the suction vessel, and the differential pressure across the suction strainer to help prevent cavitation from occurring. Vibration monitoring Vibration monitoring allows for the detection of the presence of any one of many common causes of pump failure, such as worn bearings, worn shaft coupling, misalignment, impeller damage, cavitation, foundation, or frame faults.

Bloch [41] has provided reliability tips for centrifugal pumps and these are as follows: • Greater spacers lengths reduce angles of misalignment in case of the unavoidable differential temperature-related parallel offset between the centerlines of pump and driver. Greater-length spacers may be more expensive by reducing bearing loads, and vibration severity, they beneficially affect the likely cost of future maintenance.

492  Petroleum Refining Design and Applications Handbook Volume 2 • Pipe elbows located too close to the pump inlet nozzle may save money initially but they often create flow disturbances, which tend to reduce pump life. • The higher the peripheral impeller velocity, the greater the rate of erosion in solid-containing pumps. High-tip velocity pumps manage with fewer impellers than would be needed for equivalent-head lowtip velocity pumps, but lowest installed cost today usually equates with higher maintenance outlays later. • Operation at locations too far from BEP comes at a price. Inefficient operation increases power consumption or maintenance frequency or both. • Some non-hydrocarbon process fluids have properties that make it advisable to provide an NPSHA well in excess of the published NPSHR. Investigation of the applicable process experience is advised. • Operation at zero flow is not allowed and if over a minute’s duration, could cause temperature rise and internal recirculation effects that might destroy many pumps. • Occasional, high efficiencies are alluded to in the manufacturer’s literature when bearing, seal and coupling losses are not included in the vendor’s test reports. Ensure to install a large-enough motor. • Pump manufacturers often use modular casing construction. A given casing size may, however, accommodate several different impeller sizes or geometries. Once an existing plant has determined actual operating flows and heads, it may be cost-effective to purchase custom-built, optimized “upgrade” impellers from knowledgeable manufacturers. • Operation outside the design range will have some repercussions. There are no exceptions to this immutable rule. Pump internal recirculation can cause surging and cavitation, even when the NPSHA exceeds the manufacturer’s published NPSHR by considerable margins. Also, extensive damage to the pressure side of the impeller vanes has been observed in pumps operating at reduced flow rates.

New Technology With Screw Pumps Screw pumps classified as rotary pumps are positive displacement pumps and are increasingly employed to strip out even highly viscous media. When emptying an oil or fuel tank, quite often residual product of highly viscous media is retained. Tanks farms are storage tanks for storing media that are volatile, potentially hazardous or have to be protected from contamination. They are often used for oil products from diesel and petrol and other petrochemical products. However, all these materials could pose problems when being emptied such as when medium is pumped to the next step in the production chain. This may be due to comparatively high viscosity or a low vapor pressure. If a conventional centrifugal pump is used, the poor intake often retains the residual product that cannot be utilized resulting in a significant cost factor with diesel prices of $1,200 per m3. The wrong pump types can cause cavitation which could interrupt the flow resulting in pump failure on the long term. Screw pumps are therefore used as an alternative to centrifugal pumps because they have low NPSHR values, and therefore significantly better intake behavior, and are able to completely strip out a tank. The pumped fluid is moving axially without turbulence which eliminates foaming that would otherwise occur in viscous fluids. Furthermore, they are able to pump fluids of higher viscosity without losing the flow rate; changes in the pressure difference have little impact on the positive displacement pumps compared to centrifugal pumps. Screw pumps have self-priming property and therefore do not require any special arrangements for suction. However, because of this, they are suitable for pumping liquid as well as gases without any loss of suction. All types of rotary pumps continue to force fluid into the system regardless of the opposition to the transfer. Owing to this reason, additional protection to these pump types is required or else the pump will continue to build pressure, which could result in rupture or damage of the pump. This happens due to the building up of excessive pressure in the pump. This is avoided by fitting relief valves in the pumps. These relief valves are capable of bypassing entire throughput of the pump. The relief valves should operate only for short interval of time otherwise they would lead to increase in liquid and pump temperature. Screw pumps have several advantages as compared to centrifugal pumps: • They allow a wide range of flows and pressures. • They can also accommodate a wide range of liquid and viscosities.

Pumps  493 • • • •

They have high speed capability and this allows the freedom to driver selection. They have low internal velocities. They are self-priming which allows them to have a good suction characteristics. Due to the close arrangement of rotating parts, a high tolerance for entrained air and other gases is produced.

The disadvantages are: • Cost of manufacturing is high because of close tolerances and running clearances. • Any changes in the viscosity of the fluid results in high fluctuations in the performance. • A screw pump with high pressure capability will require high pumping elements which increase the overall size of the pump.

Nomenclature a B d BHP (BHP)vis CE CH CQ cp D D’ D” d dp dr d’ d” EHP E En Ev Ew Evis e ew evis evol eM g H H Hso Hvis Hw hd

= Area of piston or plunger, in.2 = Bell diameter of vertical sump pump, ft = Brake horsepower = Brake horsepower when handling viscous material = Viscosity correction for efficiency to convert to water performance = Viscosity correction for head, to convert to water performance = Viscosity correction for capacity, to convert to water performance = Specific heat of liquid, BTU/lb °F = Height of liquid (static) above (+) or below (−) the centerline of the pump on discharge side, ft = Incremental height of liquid (static) above normal D level, to establish “worst case” condition, ft. = Theoretical displacement volume displaced per revolution(s) of driving rotors, in3/rev = Impeller diameter, in. = Diameter of piston or plunger, in. = Diameter of piston rod, in. = Liquid displacement, ft3/min = Theoretical displacement, ft3/min = Electrical horsepower = Efficiency, % = Fraction entrained gas by volume at atmospheric pressure = Volumetric efficiency ratio of actual pump capacity to volume displaced per unit of time = Pump efficiency with water, % = Pump efficiency with viscous fluid, % = Pump efficiency, fraction = Pump efficiency with water, fraction = Pump efficiency with viscous fluid, fraction = Volumetric efficiency, fraction = Maximum safe flowing efficiency, overall pump fraction = Acceleration of gravity, 32 ft/s2 (9.81 m/s2) = Total head developed by a pump ft (m) of fluid; or total head/stage, ft, or, = Static head discharge ft (m) = Head at no flow, or shutoff, ft = Head of viscous fluid, ft = Water equivalent head, ft = Discharge head on a pump, ft of fluid

494  Petroleum Refining Design and Applications Handbook Volume 2 hs hSL, hDL hv L=S I Ns Np n P Pa Pso Ptd Pvp p’ p’a p′vp Q Q’ QM QN Qvis Qw S S S′L S” SpGr s t Tr t V v W W1 whp whp1

= Suction head (or suction lift) on a pump, ft of fluid = Friction losses in pipe and fittings: subscript SL for suction line; and DL for discharge line, ft of fluid = Velocity head, ft of fluid = Static head, suction side, ft = Water depth in sump, ft = Specific speed, dimensionless = Number of pumps = Rotative speed, revolutions per minute = RPM = rpm = Positive external pressure on surface of liquid (+) or partial vacuum on surface of liquid (−) = Atmospheric pressure or absolute pressure in vessel, psia = Brake horsepower at shutoff or no flow = Differential pressure between absolute pressures at outlet and inlet to pump, psi = Vapor pressure of liquid at pumping temperature, psia = Absolute pressure, in. Hg abs = Atmospheric pressure or absolute pressure in vessel expressed as ft of fluid = Vapor pressure of liquid at pumping temperature expressed as ft of fluid = Flow rate, gpm = Capacity of rotary pump, fluid plus dissolved gases/entrained gases at operating conditions, gpm = Minimum flow, gpm = Head at best efficiency point on pump curve, ft = Viscous liquid capacity, gpm = Water capacity, gpm = Suction static head, ft, or height of liquid (static) above (+) or below ( ) the center line of the pump on suction side, ft, or, = Suction lift, negative suction head, ft = Worst case suction side static lift, ft = Slip, quantity of fluid that leaks through internal clearances of rotary pump per unit time, gpm = Specific gravity of liquid at pumping temperature referred to water = 1.0 = Stroke, in. = Temperature rise, °F = Temperature rise, °F/min = Piston speed or travel, ft/min = Liquid velocity, ft/s = Average velocity, ft/s = Width of channel with series pump, ft = Weight of liquid in pump, lb = Water or liquid horsepower = Power imparted by pump to fluid discharged (also liquid horsepower)

Subscripts 1,2 A L d d1 s1 R s

= Refer to first and second condition, respectively = Available from pump system (NPSH) = Liquid = Discharge side of pump = Friction losses for pipe fittings and related items on discharge side of pump = Friction losses for pipe valves and other system losses, suction side of pump = Required by pump (NPSH) = Suction side of pump

Pumps  495

Greek Symbols

= Fluid mass gravity, lb/ft3

References

1. Yeddidah, A., Multistage Centrifugal Pump, Chem. Eng., Vol. 91, No. 24, p. 81, 1984. 2. Dufour, J. W., Revised API Pump Standard, Chem. Eng., Vol. 96, No. 7, p. 101, 1989. 3. Lahr, P. T., Better Standards: Better Pumps, Chem. Eng., Vol. 96, No. 7, p. 96, 1989. 4. Taylor, I., Cameron, B., and B. Wong., A Users Guide to Mechanical Seals, Chem. Eng., Vol. 95, No. 12, p. 81, 1988. 5. Adams, W. V., Troubleshooting Mechanical Seals, Chem. Eng., Vol. 90, No. 3, p. 48, 1983. 6. Sniffen, T. J., Mechanical Seals From A to Z, Power and Fluids, Winter, Worthington Corp., Harrison, NJ, 1958. 7. Fischer, E. E., Seals and Packings Selection Criteria., Chem. Proc., p. 60, Oct. 1983. 8. Hydraulic Institute Standards for Centrifugal, Rotary and Reciprocating Pump, 13th. Ed., 1975 and Engineering Data Book, 1st ed., 1979, Hydraulic Institute. Also see 14th. Ed., 1983, and 2nd. Ed. 1991 respectively. 9. Mann, M. S., Horizontal and Vertical Pumps, Pet. Ref., Vol. 32, No. 12, p. 111, 1953. 10. Karassik, I., and R. Carter, Centrifugal Pumps, McGraw-Hill Book Co, 1960. 11. Centrifugal Pump Fundamentals, Form 7287, Ingersoll-Rand Co., Cameron Pump Division, P. O. Box 636, Woodcliff Lake, NJ. 07657. 12. Carter, R. and I. J. Karassik, Basic Factors in Centrifugal Pump Application and Basic Factors in Preparing a Centrifugal Pump Inquiry, Reprint RP – 477, Worthington Corp., Harrison, NJ, reprinted from Water and Sewage Works magazine. 13. Kern, R., How Discharge Piping Affects Pump Performance, Hydroc. Proc., Vol. 51, No. 3, p. 89, 1972. 14. Karassik, I. J., Krutzsch, W. C., Fraser, W. H., and J. P. Messina, Pump Handbook, McGraw – Hill Book Co., NJ, 1976. 15. Karassik, I. J., Are You Short on NPSH?, Combustion, p. 37, July 1980. 16. Karassik, I. J, and T. W. Edwards, Centrifugal Pumps on Closed Discharge Industry and Power, No. 6, p. 54, 1955. 17. Mann, M., How to Use System-Head Curves, Chem. Eng., No. 2, p. 162, 1953. 18. Dean Brothers Pumps, Engineering Catalog Circular No. 190, Mar. Indianapolis, IN, 1958. 19. Branan, C. R., Pocket Guide to Chemical Engineering, Gulf Publishing Co., Houston, TX, 1999. 20. Taylor, L, Pump Bypass Now More Important, Chem. Eng., Vol. 94, No. 7, p. 53, 1987. 21. Church, A. H., and H. Gartmann, eds., DeLaval Handbook, 2nd ed., DeLaval Steam Turbine Co., Trenton, NJ, 1955. 22. Welch, H. J., ed., Transamerica DeLaval Engineering Handbook, 4th. Ed., McGraw-Hill Book, Co. Inc., 1970 and 1983 by Transamerica Delaval, Inc., IMO Industries Div. 23. Branan, Carl, Rules of Thumb for Chemical Engineers, 4th ed., Gulf Publishing Professional, 2005. 24. Kelly, J. Howard, Understand the Fundamentals of Centrifugal Pumps, CEP, pp. 22–28, Oct. 2010. 25. Durand, Alejandro Anaya, Charting NPSH Values of Pumps, Calculation & Shortcut Deskbook, Chemical Engineering, p. 100, Mc. Graw-Hill Co., 2018 26. Kern, R., How to Design Piping for Pump-Suction Conditions, Chem. Eng., April 28, 1975. 27. Lieberman, Norman, P. and E. T. Lieberman, A working Guide To Process Equipment, 3rd. ed., Mc Graw-Hill Co., 2008. 28. Thakore, Shchen B., and Bharat I. Bhatt, Introduction to Process Engineering and Design, 2nd. Ed., McGraw-Hill India, 2015. 29. Woods, Donald, R., Successful Trouble Shooting for Process Engineers—A Complete Course in Case Studies, Wiley-VCH, 2006. 30. Gas Processors Suppliers Association (GPSA) Engineering Databook, 12th Ed., 2004. 31. Reynolds, John, A., Pump Installation and Maintenance, Chem. Eng., Oct, 11, 1971. 32. Sarver, Joseph, Finkenauer, Blake and Y.A. Liu, Pump Sizing and Selection Made Easy, Chemical Engineering, www. CHEMENGONLINE.COM, p. 34, January 2018. 33. Hanyak, Jr. M. E., “Chemical Process Simulation and the Aspen Hysys Software, MEH, 1998 to 2012. 34. White, S., and S. Fulton, “Specifications—importance of getting them right”, www.digitalrefining.com/article/1000320, Petroleum Technology Quarterly (PTQ), pp 1–9, Q4, 2003. 35. Kumana, Jimmy D, and Maneul, R. Suarez, “Analyzing the Performance of Pump Networks: Part 2: Improving Pump Efficiency, CEP, pp 32–41, February, 2018. 36. American Petroleum Institute, “Centrifugal Pumps for Petroleum, Petrochemical and Natural Gas Industries”, 10th ed., API Standard 610 (ISO 13709), API, Washington, D.C., 2004.

496  Petroleum Refining Design and Applications Handbook Volume 2 37. Hydraulic Institute, http://www.pumps.org/, retrieved on May 25, 2011. 38. Holland, F. A., and R. Bragg, Fluid Flow for Chemical Engineers, 2nd ed., Edward Arnold, 1995. 39. Tsai, M. J., Chem. Eng., 75 (13), June 17, p. 190, 1968. 40. White paper – 3 Innovative Ways to Improve Pump Reliability, Emerson Process Management, www.emersonprocess. com/pumps. 41. Bloch, H. P., “Reliability tips for centrifugal process pumps, http://www.hydrocarbonprocessing.com/Article/3337288/, May 2014. 42. Hall, Stephen., “Rules of Thumb for Chemical Engineers, 5th ed., Butterworth-Heinemann, imprint of ButterworthHeinemann, imprint of Elsevier, 2012. 43. Tom Baxter, Energy Saviours—Ways for operations and design engineers to boost efficiencies, The Chemical Engineer, p 43, September, 2018. 44. Ashis Nag., Distillation & Hydrocarbon Processing Practices, PennWell Corporation, 2016. 45. Center for Chemical Process Safety, Guidelines for Safe Process Operations and Maintenance, 1995. 46. Occupational Safety and Health Administration (OSHA), Process Management Standard.

17 Compression Equipment

17.1 Introduction A compression system is a simple arrangement of equipment designed to produce clean, dry compressed gas or air for industrial applications. These equipment types are used to transfer or compress light hydrocarbon gases, hydrogen, nitrogen, carbon dioxide, chlorine, and a variety of specialty gases. Compressors are used at pipeline lift stations to add energy to compressed feed stocks. A compression system comprises: process piping, valves, a compressor, a receiver, heat exchangers, dryers, back pressure regulators, gages, and moisture removal equipment. In a refinery or petrochemical plant, compressors are employed to compress gases such as nitrogen, hydrogen, carbon dioxide, and chlorine. These gases are sent to headers from which they are distributed to a variety of applications. When compressors are used in a process system, various supporting equipment types are used, such as safety valves, motor, lubricating systems, control instruments, regulators, demisters, and pipe header. The primary purpose of a compressor is to compress gases to create energy to transfer the gas from one place to another. The compression of gases and vapors forms an important operation in refineries, chemical and petrochemical plants, as it is necessary to be able to specify the proper equipment type by its characteristic performance. The compression step is conveniently identified for the process design engineer by the principal operation of the equipment: 1. 2. 3. 4.

 eciprocating R Centrifugal Rotary displacement Axial flow

Compression may be from below atmospheric pressure, as in a vacuum pump or above atmospheric as for the majority of process applications. The word done by Scheel [1–3] is useful. This chapter presents the process and mechanical engineer with the basic details of reciprocating, centrifugal, and other major types of process compressors. The chapter provides equations for determining the work done, power requirements for adiabatic and polytropic compression processes, specifies the required process performance and mechanical requirements, including the corrosive and hazardous nature and the moisture content of the fluids (gases/vapors) to be compressed. Finally, the chapter lists troubleshooting options for both reciprocating and centrifugal compressors, the comparison between these compression types, and their applications in the refinery and chemical process industries.

A. Kayode Coker Petroleum Refining Design and Applications Handbook Volume 2, (497–836) © 2021 Scrivener Publishing LLC

497

498  Petroleum Refining Design and Applications Handbook Volume 2

17.2 General Application Guide Figures 17.1A, 17.1B, 17.1C, and 17.1D present a general view of the usual ranges of capacity and speed operation for the types of compression equipment listed. For pressure conversions of Figure 17.1B, 1000 psi = 6.8947 mpa. Figure 17.1E presents a classification of various compressor types.

Compressor Speed, rpm

105

104

103

102 10

102

103 104 Compressor Inlet Capacity, cfm

105

106 3×106

Axial Flow

Centrifugal

Reciprocating

Blowers and Fans

Vane Rotary Compressor

Lobe and Screw Rotary Displacement

Figure 17.1A  General areas of compressing equipment application (source: De Jardins, P. R. Chemical Engineering, V. 63, No. 6, © 1956. McGraw-Hill, Inc., New York, All rights reserved).

1,000

Discharge Pressure, MPA

100

Piston Compressors

10

Centrifugal Compressors Diaphragm Compressors

1

Axial Compressors

0.1 1

10

102

103 104 Inlet Flow Actual m3/hour

105

106

10

Figure 17.1B  Approximate ranges of application for usual process reciprocating centrifugal, diaphragm, and axial flow compressors used in chemical/petrochemical processes. Note that ethylene gas reciprocating compressors in the low density, high pressure process can reach 50,000–65,000 psi; 1000 psi = 6.8947 mPa; for example, 500 mPa = 72,519 psi (used by permission: Livingston, E. H., Chemical Engineering Progress, V. 89, No.2, © 1993. American Institute of Chemical Engineers, Inc. All rights reserved).

Compression Equipment  499 1000 Centrifugal units with vertically split casing (barrel types)

500

100

50 Pressure, bar

High pressure integrally geared centrifugal compressors

10 Axial-centrifugal compressors

Centrifugal compressors with horizontally split casing

5

Axial compressors

1 0.1

0.5

0.5

1

0.5

5 10 Volume flow 5

1

10

5

50

50

10

100

50

500 m3/s

100

500

100

1000 × 1000 m3/h

500 × 1000 ft3/min

Figure 17.1C  Typical application ranges for turbocompressor capabilities extend over wide ranges of volume flow and pressures. Note: Barx 14.5 = psi (used by permission: Nissler, K. H. Chemical Engineering, V. 98, No. 3, p. 104, © 1991, McGraw-Hill, Inc., All rights reserved).

Table 17.1 outlines the compression limits for this equipment type. The value of the chart and table is to aid in establishing the probable types of equipment suitable for an operation. However, as in many other process situations, equipment is designed to handle special cases that might not be indicated by the guide. Usually inlet suction flow rate of the fluid, temperature, and pressure, as well as the outlet conditions and nature of the fluid, are all involved in identifying the equipment type best suited for the application. See Monroe [4], Huff [5], and Patton [96] for comparison. Also see Leonard [6].

17.3 Specification Guides Compressor cylinders or other pressure-developing mechanisms are never designed by the process companies involved in their operation, except in rare instances in which special know-how is available or secret process

500  Petroleum Refining Design and Applications Handbook Volume 2 Compressors Dynamic

Ejector

Displacement

Radial

Axial

Rotary One rotor

Vane

Liquid ring

Reciprocating Two rotors

Trunk Screw

Screw

Crosshead

Roots

Labyrinth Diaphragm

Figure 17.1D  Basic compressor types (used by permission: Coker, A. K. Hydrocarbon Processing, V. 73, No. 7, p 39, © 1994. Gulf Publishing Co, Houston, Texas. All rights reserved).

Compressors

Positive Displacement Type

Dynamic Type

Reciprocating

Rotary

Single-Stage Multi-Stage Integral Gas-Engine Driven Separable Balanced/Opposed

Straight Lobe Helical Lobe (Screw) Sliding Vane Liquid - Ring

Radial flow (Centrifugal)

Single-Stage Multi-Stage Horizontally Split Vertically Split (Barrel) Integral Gear

Diaphragm

Mixed Flow

Figure 17.1E  Types of compressors.

Thermal Type

Axial Flow

Ejectors

Multi-Stage Fixed Stator Vanes Variable Stator Vanes

Single-Stage Multi-Stage

Compression Equipment  501 Table 17.1  General compression and vacuum limits. Compressor type

Approx. max. commercially used disch. press., psia

Approx. max. compression ratio per stage

Approx. max. compression ratio per case or machine

Reciprocating

35,000–50,000

10

As required

Centrifugal

3000–5,000

3–4.5

8–10

Rotary displacement

100–130

4

4

Axial flow

80–130

1.2–1.5

5–6.5

Vacuum pump type

Approx, suction pressure attainable, mm Hg abs

Centrifugal

6

Reciprocating

0.3

Steam jet ejector

0.05

Rotary displacement

10−5

Oil diffusion

10−7 (or 10−4 micron)

Mercury or oil diffusion plus rotary

Less than 10−7

Used by permission and compiled in part from: Dobrowolski, Z. Chemical Engineering, V. 63, p. 181, ©1956 and Des Jardins, P. R. Chemical Engineering, V. 63, p. 178, ©1956. McGraw-Hill, Inc. All rights reserved.

information is involved. In the latter case, the process company might have the compressor cylinders (or compression components) built in accordance with special plans, purchase standard frames or housings, and then assemble the driver, cylinder, and packing at the plant site. Usually the selection of the basic type of compression equipment for the operation can be determined prior to consulting the manufacturers. However, when in doubt or where multiple types may be considered, enquiries should be sent to all manufacturers offering the equipment. Preparation of complete and appropriate specifications is of paramount importance in obtaining the proper performance rating as well as price considerations. Preliminary design rating calculations are usually prepared as guides or checks. The final and firm performance information is obtained from the manufacturer of the specific equipment. No standards of design exist among manufacturers; therefore, the performance will vary according to the details of the specific equipment. All performance will be close to the requirement, but none may be exact. This is the point where knowledge of compressor types and details is important to the engineer. Bid evaluations must include detailed analysis of performance, power drivers, and materials of construction.

17.4 General Considerations for Any Type of Compressor Flow Conditions In establishing specifications, the first important items to identify from the plant process material balance are normal, maximum, and minimum intake or suction flow rates together with corresponding conditions of temperature and pressure. The required discharge pressure must be established. If it is necessary or important to be able to operate at reduced or over-normal flow rates, these should be identified for the manufacturer, together with the length of time of such expected condition; e.g., full time at one-half rate, 20 min out of every hour at 10% over normal, and so on. These operating requirements may separate the types of equipment. Because it is uneconomical to purchase horsepower that cannot be used by the fluid system, ask that the manufacturer state the maximum load and/or conditions that will fully load the available horsepower of the compressor-driver unit.

17.4.1 Fluid Properties Fluid properties are important in establishing the performance of compression equipment. Whenever possible, fluid analysis should be given, and where this is not available due to lack of complete information or secrecy, close

502  Petroleum Refining Design and Applications Handbook Volume 2 approximations are necessary. Under these last conditions, actual field performance may not agree with the design data due to the deviation in values of the ratio of specific heats and the average molecular weights. Identify, as to composition and quantity, any entrained liquids or solids in the gas stream. No manufacturer will design for entrained liquids or solids, although some machines will handle “dirty” gases. Solids are always removed ahead of any compression equipment, using suitable wet- or dry-scrubbing equipment, and liquid separators are recommended for any possibilities of liquid carry over.

17.4.2 Compressibility Gas compressibility has an important bearing on compressor capacity performance. Therefore, it is good practice to state compressibility values at several temperature and pressure points over the compression range under consideration. When possible, a compressibility curve or reference thereto is included in the inquiry. Where specific information is not available, but compressibility is anticipated as being a factor to consider, approximate values should be established and so presented for further study by the manufacturer. Compressibility is expressed as the multiplier for the perfect gas law to account for deviation from the ideal. At a given set of conditions of temperature and pressure:

where Z N R T P V

PV = ZNRT

(17.1)

= compressibility factor, usually less than 1.0 = number of lb-mol = gas constant, depends on units of pressure, volume, and temperature = 1545 lb/ft3/lbmole. °R or ft. lb/lbmole. °R, 10.73 psia. ft3/lbmole °R = 8.314 kJ/kmole.K, 8.314 kPa (abs) m3/kmole.K, 213.6 kg. m/kmole.K = absolute temperature, °R = °F + 460 (K = °C + 273.15) = pressure, absolute, psia (kPa, bara) = volume, ft3(m3) (see paragraph to follow)

Gas volumes are corrected at the intake conditions on the first and each succeeding stage of the compression step, and compressibility factors are calculated or evaluated at these individual intake conditions. Some manufacturers use the average value between intake and discharge conditions.

17.4.3 Corrosive Nature Corrosive fluids or contaminants must be identified to the manufacturer. The principal gas stream may or may not be corrosive under some set of circumstances, yet the contaminants might require considerable attention in cylinder design. For example, considerable difference exists between handling “bone-dry” pure chlorine gas and the same material with 5 ppm moisture. The corrosiveness of the gas must be considered when selecting fabrication materials for the compression parts as well as seals, lubricants, and so on.

17.4.4 Moisture Moisture in a gas stream might be water vapor from the air or a water scrubber unit, or it could be some other condensable vapor being carried in the gas stream. It is important in compressor volume calculations to know the moisture (or condensable vapor) condition of the gas.

17.4.5 Special Conditions Often the process may have conditions that control the flexibility of compression equipment selection. These might include limiting temperatures before polymer formation, chemical reaction, excess heat for lubrication materials,

Compression Equipment  503 explosive conditions greater than a certain temperature, and so on. Any limiting pressure drops between stages should be specified, in which the gas and vapors are discharged from one stage, pass through piping, cooling equipment and/or condensate knock-out equipment, and are then returned to the next higher stage of the compression process. Usually a reasonable figure of 3–5 psi (0.21–0.34 bar) can be tolerated as pressure drop between stages for most conditions. The larger this drop is, the more horsepower is required. Special situations might hold this figure to 0.5–1 psi (0.034–0.069 bar).

17.5 Reciprocating Compression Mechanical Considerations Fundamental understanding of the principles involved in reciprocating compression is important for proper application of compressors to plant problems. The reciprocating compressor is a positive displacement unit with the pressure on the fluid developed within a cylindrical chamber by the action of a moving piston. Figures 17.2A–U illustrate the assembly and arrangements of typical cylinders for various pressure ranges and types of services. Figures 17.3A and 17.3B show cross-sections of a cylinder and crankshaft arrangement for two different styles of compressors. Compressor types, components, and arrangements are designed as:

Cylinders 1. S ingle Acting: Compression of gas takes place only in one end of the cylinder. This is usually the head end (out-board end), but may be the “crank” end (inboard end or end of cylinder nearest crankshaft of driving mechanism) (see Figures 17.2A, 17.3A, and 17.4A). 2. Double Acting: Gas compression takes place in both ends of the cylinder, head end, and crank end (Figures 17.2I, 17.2J, and 17.4B). Large inspection plate

Heavy enclosed oil tight frame

Suction valve

Forged steel connecting rod

Oil wiper ring

Unloader cylinder

Suction

Breather

Discharge valve Oil gauge Grout

Discharge

Counter balanced crank shaft

Tapered roller main bearing

Box section crosshead

Frame oil head

Liberal cooling water jackets

Figure 17.2A  Sectional assembly. Worthington single stage, belt-driven air compressor showing construction of air cylinder and running gear (used by permission: Bul. L-600-B9. Dresser-Rand Company).

504  Petroleum Refining Design and Applications Handbook Volume 2 Discharge Double Deck Valves

Piston Lubrication Inlet Suction Valves To Crank

Head End Clearance Pocket Crank End of Cylinder (Next to Driving Mechanism) Head End of Cylinder

Piston Rod Packing Vent or Purge Packing Piston with Rings Outlet Gas

Figure 17.2B  Cutaway view of typical high pressure gas cylinder showing double-deck feather valves in place (used by permission: DresserRand Company).

Figure 17.2C  Dry vacuum pump cylinder for very low absolute suction pressures. Valves in heads for low clearance and high volumetric efficiency (used by permission: Bul. L-679-BIA, © 1957. Dresser-Rand Company).

Compression Equipment  505

Figure 17.2D  Standard air compressor cylinder for 125 psig discharge pressure. Suction valve unloaders for automatic capacity control (used by permission: Bul. L-679 – BIA, © 1957. Dresser-Rand Company).

Figure 17.2E  A 250 psig working pressure cylinder used in refrigeration service. Auxiliary stuffing box for added sealing on shutdown. Manual fixed volume clearance pockets for capacity control (used by permission: Bul, L-679-BIA, © 1957, Dresser-Rand Company).

Note that the crank end (Figure 17.2F) always has the piston rod running through it, while the head end usually does not, but may, if a tail rod (Figure 17.2L) is used.

Frames The cylinders are arranged on the main frame of the compressor to provide balanced crankshaft power loading (when possible), access for maintenance, piping convenience, and floor space to suit plant layout. Common designations by position of the cylinder are as follows: 1. 2. 3. 4. 5.

 orizontal. H Vertical. 90° angle, cylinders mounted both vertically and horizontally from same crankshaft, Figure 17.5A. V or Y angle, Figure 17.5A. Radial.

506  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.2F  Typical linear-type cast iron cylinder. Cylinder barrel and heads are rugged castings made from an iron composition especially selected for the particular cylinder and service involved. Heads and barrel are thoroughly water-jacketed. Water piping is included from inlet valve to outlet sight-flow indicator. Dry-type liner is of cast-iron, shrunk into the barrel, and extending for the full length of the cylinder. It is positively locked by the heads against end movement and by a threaded dowel against rotation. Piston is cast-iron, hollow for light weight, and well ribbed for strength. The piston is locked on the rod between either a taper or a solid collar and a nut. Piston rings are normally cast-iron of the single piece snap-ring type, although other materials may be used when conditions require. Piston rod is carbon steel, flame-hardened over packing travel area. The rod is packed with full-floating metallic packing, force-feed lubricated, and vented when the gas composition requires. Vented packing is illustrated. Distance piece opening provides free access to packing. All head studs and nuts are external and accessible without removal of valves to reach internal bolting. There is no possibility of hidden internal leakage. Support is provided at outer end (see sketch) to carry weight of cylinder directly to foundation. The piping need not be designed to support the cylinder. Clearance pocket shown in the head is the manual fixed volume type. Recycle and other services frequently require absolute elimination of lubricating oil contamination of the gas. The cylinder must operate with no oil (used by permission: Ingersoll-Rand Company).

6. D  uplex, cylinders mounted in parallel on two separate frames from common crankshaft, Figure 17.5B. 7. Balanced Opposed, cylinders mounted opposite (180°) and driven off same crankshaft, Figures 17.5C and 17.5E. Also see Figure 17.5F; the following results are used by permission (Bul. PROM 635/115/95II, Nuovo Pignone, S.P.A.): • Either zero or minimum unbalanced forces and moments on the foundation. • Minimum foundation size and expense. • Minimum drive-end peak torques, reducing drive train torsional stresses. • Reduce motor current pulsations and power costs. • Reduce harmonic torques on the foundation. With a bearing between each crank throw and an extra main bearing and an outboard bearing for extra support at the HHE’s drive end, the result is minimum crankshaft deflections, minimum crankshaft stress, minimum driveend bearing loads and maximum crankshaft and bearing life. For example, an HHE for a three cylinder application has three crank throws set at 120°. “Piston weights may be balanced or balance weights added to the active crossheads to obtain zero unbalanced primary forces. By comparison, a fixed angle crankshaft requires four crankthrows with either an additional compression cylinder or a balance weight dummy crosshead to obtain acceptable unbalanced forces.” The minimum number of cylinders

Compression Equipment  507

Figure 17.2G  Typical non-lubricated recycle cylinder. Cylinder barrel and heads are rugged castings and may be either cast-iron or cast steel depending upon pressure and service requirements. In each case, water jackets are supplied, and piping is included from inlet valve to outlet sight-flow indicator. Dry-type Cast-iron liner is furnished in all nodular iron or cast steel cylinders for best wearing characteristics. Full cylinder-length liner is shrunk into the barrel and securely locked against any movement. Piston is an assembly of carbon rings held between steel end-plates. The piston is locked on the rod between a solid collar and a nut. When the bottom bearing surface of the carbon piston becomes worn, a new surface is easily made available by turning the assembly through an appropriate arc. This will be infrequent; the light solid piston design ensures maximum life. Piston rings are a special carbon material, of the segmental type, held to the cylinder wall by stainless steel expanders. Piston rod is carbon steel, flame-hardened over packing travel area unless otherwise specified. Two compartment distance piece. This illustration shows a typical design for maximum protection in two directions. First, to prevent crankcase oil particles from reaching the cylinder, and second, to prevent any contamination of the crankcase oil by gas constituents. The compartment nearest the cylinder is of sufficient length to prevent any part of the rod traveling from one stuffing box into another. Furthermore, a baffle collar stops crankcase oil from creeping along the rod. Normally, in this design, the distance piece toward the cylinder is enclosed with solid covers over the access openings and has provisions for venting or purging. The section on the crankcase end is open. Full-floating packing rings in the cylinder and middle partition are of a special carbon material. Only the cylinder packing is vented, unless a positive pressure is to be held in the cylinder end compartment, in which case the partition packing is also vented. They are vented in both cases in this design. Considerable heat is generated in the cylinder packing, particularly during break-in periods. It has been found desirable to remove this heat, which might otherwise result in an overheated and warped rod. Water-cooling is used, the water being circulated through a special packing cup. Support is provided at outer end (see sketch) to carry weight of cylinder directly to foundation. The piping need not be designed to support the cylinder. The channel valve, as designed especially for non-lubricated service (used by permission: Ingersoll-Rand Company).

Figure 17.2H  Double-acting cast steel cylinder to 3500 psi pressure (used by permission: Cooper-Cameron Corporation. All rights reserved).

508  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.2I  Double-acting cast Meehanite or ductile iron cylinder to 1250 psi pressure (used by permission: Cooper-Cameron Corporation. All rights reserved).

Figure 17.2J  Double-acting Meehanite metal or ductile iron cylinder to 1000 psi pressure (used by permission: Cooper-Cameron Corporation. All rights reserved).

Figure 17.2K  Forged steel single-acting for 6000 psi pressure (used by permission: Cooper-Cameron Corporation. All rights reserved).

Compression Equipment  509 LUBRICATOR CONNECTION

WATER OUTLET

WATER OUTLET LUBRICATOR CONNECTIONS

DRAIN

VENT

VENT WATER INLET

LUBRICATOR CONNECTION

WATER INLET

WATER INLET

VENT

Figure 17.2L  Typical forged steel cylinder with tail-rod. Construction of forged steel, tail-rod cylinders (other than circulators) as shown here. Cylinderbarrel with integral packing boxes is a single steel forging or a material especially selected for the design, pressure, and service requirements of each case. There are no heads as such; the forged steel nose-pieces of the piston and tail-rod packing act as closures. Both cylinder barrel and stuffing boxes are water-jacketed. Water piping is included from inlet valve to outlet sight-flow indicator. Alignment of packing boxes and cylinder bore is ensured because all three are bored at a single machining setup. This is an important factor in packing life. Dry-type lineris a special cast-iron, full length of the cylinder, shrunk in place, and securely locked against any movement. Pistonis usually cast iron, locked on the rod between a solid collar and a nut. If a cylinder size is such that sufficient piston wall thickness is not available, the piston and rod are forged integrally as shown, and special inserted rider rings are included to improve wearing qualities. Pistonrings are of the single-piece, snap-ring type. Piston rod and tail-rodare one piece of carbon steel, flame-hardened over packing travel area. The rod is packed with full-floating metallic packing, force-feed lubricated, and vented when the gas composition requires. Vented packing is shown. Distance piece openingprovides free access to frame end packing. Packing casesare completely contained and supported in full depth boxes in cylinder. Unequal tightening of flange bolts cannot destroy the alignment. Supportis provided at outer end (see sketch) to carry weight of cylinder directly to foundation. Valvesare cushioned type valves. This design is used in 3000–15,000 psi ammonia, methanol, and hydrogenation plant services (used by permission: Ingersoll-Rand Company).

Figure 17.2M  For low compression ratios, designed for 1000 psi discharge pressure equipped with hand-operated crank and heat-end fixed clearance pockets for capacity control. Air-cooled, cast semi-steel, double-acting (used by permission: Dresser-Rand Company).

510  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.2N  Designed for working pressure up to 6500 psi. A similar design cylinder is used for pressures in excess of 6500 psi. Water cooler, forged-steel, double-acting (used by permission: Dresser-Rand Company).

Figure 17.2O  Fourth and fifth-stage cylinder assembly of 3500 psi pressure hydrogen compressor. Opposed single-acting cylinders balance frame-bearing loading and minimize torque fluctuations (used by permission: Dresser-Rand Company).

Figure 17.2P  Fifth and sixth-stage cylinder assembly of 15,000 psi gas compressor. “Bathtub” design of intermediate crosshead permits use of short opposed plungers ensuring operating alignment. A design for pressures as high as 35,000 psi (used by permission: Dresser-Rand Company).

Compression Equipment  511

Cast or nodular iron cylinders for pressures to 1,500 PSI.

Figure 17.2Q  Cast or nodular iron cylinders for pressures to 1500 psi. Note double “distance pieces” (left vented or purged, to prevent oil and process gas from leaking past the shaft; and right-end fixed clearance pocket) (used by permission: Bul 85084, © 1992. Dresser-Rand Company).

(a) Dresser-Rand Standard FRAME END

VENT

CYLINDER END

WIPER RINGS

PACKING DRAIN

Long single-compartment distance piece (sufficient length for oil slinger travel). (b)

FRAME END

VENTS

CYLINDER END

OIL SLINGER

WIPER RINGS

DRAIN

PACKING DRAIN PARTITION PACKING

Two-compartment or double distance piece arrangement (in-board distance piece of sufficient length for oil slinger travel).

Figure 17.2Q  (a) Long, single compartment distance piece (sufficient length for oil slinger travel). (b) Two-compartment or double distance piece arrangement (inboard distance piece of sufficient length for oil slinger travel) (used by permission: Bul. 85084 ©1992. Dresser-Rand Company).

512  Petroleum Refining Design and Applications Handbook Volume 2

Fabricated carbon or stainless steal cylinder for special applications.

Figure 17.2R  Fabricated carbon or stainless-steel cylinders for special applications. Note double-distance piece, no clearance pocket (used by permission: Bul. 85084, © 1992. Dresser-Rand Company).

Forged steel cylinder with tail-rod design (right) for pressures to 7,500 PSI.

Figure 17.2S  Forged steel cylinder with tail-rod design (right) for pressure to 7500 psi (used by permission: Bul. 85084, © 1992. DresserRand Company).

Figure 17.2T  Medium or high pressure, double-acting cylinder with flanged liner. The liner is locked in place by a flange between head and cylinder barrel. A step on the liner O.D. permits easy insertion. The cylinder may be made of cast-iron, nodular iron, or cast steel, depending on operating pressure. Note: Optional two compartment distance piece (type D) designed to contain flammable, hazardous, or toxic gases is illustrated (used by permission: Bul. 33640, June 1985. © Dresser-Rand Company).

Compression Equipment  513

Figure 17.2U  High pressure, circulator-type cylinder, double-acting. The steel cylinder and packing box are forged in one piece, and the one-piece piston and rod ensure positive alignment. The packing boxes are water cooled, and the packing is additionally cooled by internally circulated oil. Note tail-rod construction (used by permission: Bul. 3640, June 1985. © Dresser-Rand Company).

13

12

16

15

14

1

2

11

3

10

9

8

7

6

5

4

Figure 17.3A  Typical cross-section of motor-driven, single-stage compressor. 1. Valves. 2. Piston sealed by two single-piece snap rings. Rod threaded and locked into piston. 3. Cylinder head. 4. Cylinder barrel, head, and air passages water-jacketed for cooling. 5. Air passages. 6. Distance piece allows access to packing and oil-wiper rings. 7. Crosshead guide. 8. Counterweights and permanently bolted in place. 9. Foundation. 10. Screened oil suction. 11. Crankpin and main bearings. 12. Frame. 13. Die-forged steel connecting rod has rifle-drilled oil passage. 14. Crosshead pressure-lubricated through drilled passages in crosshead body. Piston rod threaded and locked into crosshead. 15. Wiper rings keep crankcase oil out of cylinder. 16. Full-floating metallic packing is self-adjusting (used by permission: Ingersoll-Rand Company. All rights reserved).

514  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.3B  Partial cross-section of balanced opposed compression cylinders. (A) Single-acting cylinder (B) Double-acting cylinder (used by permission: Bul. 85084, (c) 1992. Dresser-Rand Company. All rights reserved).

(a)

(b)

Stroke Suction Valve Cylinder Head End

End of Stroke Piston Rod

Drive

Crank End Discharge Valve Single Acting Cylinder

Stroke

Suction Valve

End of Stroke Piston Rod

Cylinder Head End

Drive

Crank End Discharge Valves Double Acting Cylinder

Figure 17.4  Cylinder action.

is not “locked” into even numbers to handle compression problems. The minimum number required is used; therefore, “balanced weight dummy crossheads are not necessary.”

8. F  our-cornered, opposed, two cylinders mounted opposite (180°) at each end of crankshaft. 9. Tandem, two or more cylinders are on the same compressor rod, or one cylinder may be steam operated as drive cylinder with second as compressing cylinder. May also be duplex or multiple tandem (Figure 17.5D). Also see Figure 17.5E.

17.6 Suction and Discharge Valves Several of the types of valves used in compressor cylinders are shown in Figure 17.6. To function properly, a valve must seat uniformly and tightly, yet must not have “snap-action” on opening or closing. Until pressure builds up to the discharge point, the valve must remain closed, open at discharge pressure, and then reseat as the pressure in the cylinder drops below the discharge value. The same type of action is required for the suction valves. Valves must be made of fatigue-resistant carbon or alloy steel or 18-8 stainless steel, depending upon the service. The 18-8 stainless and 12-14 chrome steel are often used for corrosive and/or high temperature service. Any springs,

Compression Equipment  515 (A)

(B)

Rod

Vertical Cylinder

Crank Shaft

Horizontal Cylinder Crank Shaft

Rod

90° Angle Compressor

Driver may be Located either Position

Duplex Compressor Cylinders

For Y or V-type, Angle between Compressor Rods is still 90°, however Cylinders are Rotated to be about 45° from Vertical.

(C)

Crank Shaft

Crank Shaft

(D)

Rod Rod

Rod

Balanced Opposed Compressor Cylinders Additional Groups of Two Opposing Cylinders may be Fixed to the Same Crank Shaft

Tandem Compressor Cylinders Sometimes the Inboard Cylinder is Steam Operared as the Driver Cylinder

Figure 17.5A–D  Cylinder arrangement.

as in the plate-type valves, are either carbon or nickel steel. Valve passages must be smooth, streamlined, and as large as possible. Cylinder efficiency depends to a certain extent upon the proper selection and sizing of the valves. Valves must be adequately cooled, so provision is usually made for water jackets immediately adjacent to the valves, particularly the discharge valves. Bauer [7] has studied losses in compressor cylinder performance associated with valve losses as they relate to overall efficiency. Bunn [8] examines poppet valves for retrofitting cylinders. Double-deck valves reduce valve velocities in large diameter cylinders. With these valves, high clearance volumes and clearance pockets can be added to give additional unloading of a cylinder as designed to maintain proper loading on the driver. For a typical d ­ ouble-deck valve, the theoretical indicated horsepower loss may be 6% at a ratio of compression, Rc of 3.0 and 17% at an Rc of 1.5. The valve plates, discs, and springs are mounted in a valve cage, which is inserted in the cylinder. Valve breakage occurs due to fatigue of the metal or improper action. This requires replacement and an evaluation of the materials of construction as well as the basic type of valve. Each manufacturer presents his valve design to match his equipment. Only experience can determine which type of valve works best in a given application.

Piston Rods See Figure 17.7. Piston rods are usually forged and hardened steel or alloy.

516  Petroleum Refining Design and Applications Handbook Volume 2

HHE tree-throw crankshaft arrangement vs. Fixed-angle crankshaft design.

90°

120°

HHE

HHE three-throw crank angles are each 120.

Other

Fixed 90 angles require a dummy crosshead to balance the three throws.

Figure 17.5E  Balanced arrangement for Dresser-Rand shaft system, 1–10 crank throws (used by permission: Bul. 85084, © 1992. DresserRand Company).

Figure 17.5F  Lubricated and non-lubricated balanced opposed process reciprocating compressors, designed to API 618 code. Fixed and variable speed drives using gas or diesel engines, steam or gas turbines, or electric motor. Note power drive to connect to right side of crosshead box in center (used by permission: Bul. PROM 635/115/95-II. Nuovo Pignone S.P.A. Florence, Italy; New York; Los Angeles, and Houston, Texas. All rights reserved).

Compression Equipment  517

Figure 17.6A  Double-deck feather valve (used by permission: Dresser-Rand Company. All rights reserved).

Figure 17.6B  Double-deck valve with valve cap unloader (used by permission: Cooper-Cameron Corporation).

518  Petroleum Refining Design and Applications Handbook Volume 2

VALVE STRIPS CLOSED

VALVE STRIPS BEGIN TO OPEN

VALVE STRIP FULLY OPEN

Figure 17.6C  Action of gas flow through strip-type feather valve (used by permission: Bul. S-550-B27. Dresser-Rand Company).

Ribbed Body Construction Hardened Valve Seats Fatigue Resistant Multiple Rings Valve Discs Positively Cushioned by Increasing Spring Tension as They Approach Stops Multiple Springs Assure Uniform Valve Action Valve Bodies of High Tensile Strength Semi-Steel

Figure 17.6D  Plate-type valves (used by permission: Dresser-Rand Company).

Compression Equipment  519 Stop plate

Valve springs Valve channels

Valve guides

Seat plate Valve seat Valve closed

Valve open

Figure 17.6E  Channel-type valves (used by permission: Ingersoll-Rand Company).

  Figure 17.6F  Ring channel valves (used by permission: Cooper-Cameron Corporation).

ANNUAL SAVINGS U.S. $(000)

520  Petroleum Refining Design and Applications Handbook Volume 2 kW Consumption

$.60/ kW

150

$.05/ kW $.04/ kW

100

$.03/ kW

200

50

0 50 100 150 200 250 300 350 400 450 500 VALVE LOSS HP SAVED

Fully machined 1141 steel, ductile iron or stainless steel seats and guards Poppets — available in PEEK® materials or fully machined nylon. Durable, self-seating, lightweight, low cost Springs — variable rate 17-7PH stainless steel. Custom-match rated. API-618 design. A broken stud can’t work its way into cylinder

Figure 17.6G  AJAX® APV-100, high-efficiency compressor valve. Suction and discharge losses are 4–8% compared to conventional valves with losses of 6–20% as a percentage of the total indicated horsepower. A typical Worthington BDC plate valve in closed position. All passageways, lift clearances, springs, and plates have been dynamically designed and individually selected for maximum flow efficiencies. The individual spring plate valve offers both efficiency and reliability advantages over valves that have flexing strips or plates (used by permission: Bul. 2-241. Cooper-Cameron Corporation. Cooper Energy Services. AJAX Superior. All rights reserved).

A typical Worthington BDC plate valve in closed position. All passageways, lift clearances, springs and plates have been dynamically designed and individually selected for maximum flow efficiencies. The individual spring plate valve offers both efficiency and reliability advantages over valves that have flexing strips or plates.

Figure 17.6H  Dresser-Rand specialized valve (used by permission: Bul. 3640. Dresser-Rand Company).

Piston See Figure 17.8. Pistons may be of aluminum, built-up carbon or graphite, cast iron, cast steel, fabricated and metalized steel, stainless steel, or forged carbon. The selection involves the corrosive nature of the gas plus the weight-­ balancing problem of the compressor manufacturer.

Piston Rings See Figures 17.8 and 17.8A. Piston rings are rings mounted on the piston that seal against the cylinder wall and allow the piston to develop required pressures. Many types and materials are available. There are usually at least two rings

Compression Equipment  521 Balanced spring system delivers equivalent motion to the valve plates.

Balanced flow paths through the valve provide minimum pressure drop.

Patented design prevents centerbolt from falling into the cylinder bore, meets API618.

The standard material for plates and buttons is “Hi-Temp”.

Figure 17.6I  Dresser-Rand HPS proprietary valve design, using proprietary blend of “PEEK,” an advanced non-metallic valve plate material, allowing for temperature ranges greater than previously available non-metallic plate materials, for lubricated and non-lubricated applications for long life (used by permission: Form 85084, © 1992. Dresser-Rand Company).

(I)

(II)

Figure 17.6J  Variety of standard and special valves designed and fabricated by the Hoerbiger Corporation. Many of these designs are used in compressor manufacturer’s cylinder designs, and some valves have been designed by the compressor manufacturer (used by permission: Bul. V-100a, © 1993, Hoerbiger Corporation of America).

522  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.7  Piston rods. Precision-manufactured rolled threads and induction hardening provide high fatigue strength and long life in heavy duty service. Standard rod material is AISI 4142 carbon steel; other materials are available as required. Tungsten carbide coatings are also available for maximum surface hardness. Pistons are locked securely onto the rods. For higher pressure, smaller bore cylinders, the piston may be integral with the rod (used by permission: Bul. 85084, © 1992. Dresser-Rand Company).

Figure 17.7A  Stuffing box with rod packing direct and indirect cooling (used by permission: Bul. BCNA-3P100. Howden Process Compressors Incorporated).

Figure 17.8  Piston and rings. Lubricated and non-lubricated pistons with PTFE or other composite materials for the piston and rider rings. These designs prevent piston-to-bore contact and provide reliable service life, particularly during possible periods of lubrication interruption (used by permission: Bul. 85084, © 1992. Dresser-Rand Company).

Compression Equipment  523

Figure 17.8A  Piston rings. The piston rod is manufactured from heat treated stainless steel and is coated with wear-resistant overlays, such as ceramic, chromium oxide, and tungsten carbide applied by plasma techniques. Piston-rod crosshead attachment has mechanical preloading system for the threads. Rider rings and seal rings are manufactured from PTFE filled resins; fillers are matched to the gas, piston speed, and liner specifications. Typical fillers are glass, carbon, coke, or ceramic (used by permission: Bul. BCNA- 3P100. Howden Process Compressors Incorporated. All rights reserved).

per cylinder for low pressure applications; six or more for high pressure services. Cast iron, bronze, micarta, aluminum, and carbon (graphite) are common ring materials.

Cylinders Cylinders are made of materials consistent with pressure range and gas service. Sometimes a liner is used to recognize and allow for wear (or corrosion) or possible future changes in capacity. Liners may be graphite, aluminum, cast iron, steel, tungsten carbide, or other suitable materials (see Figure 17.2F). Most cylinders have water jackets to remove some heat of compression and to maintain reasonable cylinder and/or liner temperatures. Any heat removed is reflected in a slight reduction in the compression horsepower. The cooler cylinder walls usually allow more efficient lubrication of the cylinder. When oil cannot be tolerated in the presence of the gas, nonlubricated cylinders are used with graphite (or carbon) liners or piston rings.

Piston Rod Packing See Figure 17.9. The pressure seal between the cylinder pressure and the crank case or atmosphere is maintained by a packing gland. The motion of the piston rod is reciprocating through this packing as contrasted to the rotating motion of the centrifugal compressor or pump shaft. In many applications, it is important to prevent any part of the shaft that has been inside the cylinder and exposed to the gas from being exposed to outside air. This is particularly important when handling such materials as hydrogen chloride, chlorine, hydrogen fluoride, and so on. This may be accomplished with a distance piece (Figure 17.2G). This packing may be arranged for vent or purge in a manner similar to that for reciprocating shaft glands (Figures 17.2A and 17.2Q (a, b)).

17.7 Specification Sheet Figure 17.10, Tables 17.11A, and 17.15A are convenient for summarizing the main specifications to the manufacturer. Any unusual conditions must be explained, and minimum and maximum ranges must be established.

524  Petroleum Refining Design and Applications Handbook Volume 2

Purge

Vent

Figure 17.9  Piston rod packing. To meet the latest environmental requirements for controlling packing gas leakage, special buffer gas sealing rings are installed in place of conventional ones. The packing design includes two seats of wedge rings with an inert buffer gas between them. The spring load on the rings forces them to slightly wedge in the cup. Two individual wedge rings seal the buffer gas in both directions. Packing cups with passages for lubrication, coolant, and venture are provided as required by the application and API 618. Packing can be supplied with special gasket designs if stringent emission requirements exist (used by permission: Bul. 85084, © DresserRand Company).

“Normal” conditions maybe the same as maximum, although this may not always be the case. Detailed driver specifications should be included unless the manufacturer is to make preliminary recommendations before final decisions are reached. Note that some of the data are to be supplied by the manufacturer, and the insistence on receipt of this information facilitates evaluation of competitive bids. When packings are purged with air or other gas, the manufacturer should specify the quantity passing into the cylinder and out to the air. Accessibility of packing, bearings, and valves should be identified on drawings for review at the time of bid evaluation.

17.8 Performance Considerations Cooling Water to Cylinder Jackets Most installations use water-cooled compressor cylinder jackets; however, some use air cooling (usually small horsepower units), and a few use no cooling. For water cooling of the cylinder.

Heat Rejected to Water Btu/bhp (h) Small Cyl 20 in. dia.

Temperature Difference tc − tw, °F

300

170

20

600

310

60

700

470

100

The usual temperature rise of the water is 10–15°F, and its inlet temperature to the cylinder is from 90–140°F, depending upon the manufacturer’s design and properties of the gas. The manufacturer can provide complete data on temperatures for the particular design together with the quantity of water circulated and the pressure drop through the jackets. This cooling water is usually arranged in a closed loop with the water being pumped through secondary coolers or over cooling towers and then returned to the jackets for reuse. Water quality must be good, with steam condensate being preferred, properly treated to prevent corrosion, and so on.

Compression Equipment  525

Figure 17.10  Reciprocating compressor specifications.

526  Petroleum Refining Design and Applications Handbook Volume 2

Pressure

(a) 3

P = C1

2 (Discharge Condition)

PVk = C 4

PVk = C P = C2

1 (Inlet Condition)

Volume Ideal Reciprocating Compression Diagram (b) Compressor Valves

Piston

Cylinder Piston and Valves at Start of Compression Stroke (c)

Piston and Valves at Start of Discharge (d)

Clearance Volume Piston and Valves at End of Discharge

Figure 17.11  Ideal pressure–volume cylinder action for single acting compressor cylinder with related piston positions. Note: DV, discharge valve; SV, suction valve; k or n may be exponent for gas (used and adapted by permission: Gas Engineers Handbook. 1st Ed. © 1977. Industrial Press. Inc. New York. All rights reserved).

Drivers Refer [107] to the chapter on drivers for mechanical equipment to obtain specification details. Reciprocating compressors are driven by the following: Electric motor

Directly connected, constant or variable speed, belt, gear, fluid coupling

Gas or diesel engine

Usually directly connected to crankshaft, jackshaft, belts, or gears

Steam turbine

Gear (not a usual application)

Compression Equipment  527

Ideal Pressure–Volume Relationship Although ideal conditions are not encountered in any compression operation, the actual condition is a series of particular deviations from this. Therefore, the theoretical ideal conditions can be practically considered as the building block of the operation (Figure 17.11A and Figure 17.12). The compression operation stepwise is as follows: Condition 1: Figure 17.12. Start of the compression stroke. The cylinder is full of gas at suction pressure and essentially suction temperature (neglecting valve loss). The piston moves during compression toward condition (2) with suction and discharge valves closed. Condition 2: Figure 17.12. Start of gas discharge from cylinder. Gas has slightly exceeded the system pressure, and the discharge valve opens releasing gas to the system. The piston begins to sweep the gas from the cylinder as it moves toward condition 3. Condition 3: Figure 17.12. Completion of gas discharge from cylinder. All the gas to be removed from the cylinder by the piston stroke has passed through the discharge valve. This also is the point where the return stroke of the piston starts, but not the beginning of the cylinder suction. As the piston starts its return stroke and the pressure in the cylinder is lowered slightly below the discharge pressure, the discharge valve closes. The volume of gas left in the cylinder between the end of the piston and the end of the cylinder (clearance volume) expands from condition (3) to condition (4) as the piston returns. Condition 4: Figure 17.12. Start of gas suction into cylinder. The cylinder pressure has dropped below the system suction pressure, and the suction valve opens to admit new gas into the cylinder as it returns to condition (1).

Actual Compressor Diagram The actual compression diagram naturally deviates from the ideal; the extent varying with the physical characteristics of the cylinder and the properties of the gas (Figures 17.12, 17.12A, and 17.12B).

Deviations From Ideal Gas Laws: Compressibility See Figures 17.13A–D. The thermodynamic processes that may occur during a compression operation are [9]: Adiabatic

– no heat added to or removed from the system

Isothermal

– constant temperature

Isometric

– constant volume

Isobaric

– constant pressure

Isentropic

– constant entropy

Isenthalpic

– constant enthalpy

For any gas compression,

PVn = constant = C

(17.2)

The “ideal” gas law or “perfect” gas law is combination of Boyle’s and Charles’ laws for any compressible fluid (gas/­vapor).

528  Petroleum Refining Design and Applications Handbook Volume 2 Pressure and Friction Losses

3

Discharge

P 2 , T2 Discharge Pressure

2

Adiabatic Compression k = 1.4 (as for air)

ke ro St

ion

n sio es pr m Co

Clearance Volume

Isothermal Compression k = 1.0

s xpan R e -E

Pressure

Actual Compression

Suction Pressure 4

P1, T1

Intake Stroke Stroke or Displacement

Clearance

0

100

Volume, % Stroke

Figure 17.12  Reciprocating compressor compression diagrams. Actual losses and effect of k = cp/cv on performance.

T

2

P2

1

H2

P1

TH PA

RO

NT

ISE

C PI

H1

LOG PRESSURE

T

IDEAL GAS STATE H2–H1 –ΔH1

–ΔH2 H2°–H1°

Figure 17.12A  Illustration of isentropic path on log pressure-enthalpy diagram, showing Mollier chart method of finding final temperature and calculation on H for reversible and adiabatic compression (used by permission: Edmister, W. C. Applied Hydrocarbon Thermodynamics, © 1961. Gulf Publishing Company, Houston, Texas. All rights reserved).

Compression Equipment  529 COMPRESSION PATHS FOR ETHANE 600

PATH

200

2.0

100

80

INITIAL CONDITION 500

1.0

ΔH

Q

∫VdP

B.T.U./LB. - MOLE

1.5 150

T = 420°

T = 180°F

PRESSURE, LB./SQ. IN ABS.

220 PATH A-ISENTHALPIC

400

V= 0.6 E/LB. CUF

200 PATH B-POL Y TRO PIC PAT HC -PO LY T 300 ROP IC PAT HD -IS EN PA TRO 340 TH PI C E-P OL YT RO PIC 380

500

300

FINAL CONDITIONS

0.4

A

O

– 2166

+ 2166

B

+ 908

– 1324

+ 2232

C

+ 1633

– 651

+ 2284

D

+ 2330

0

+ 2330

E

+ 2939

+ 553

+ 2386

.0

V=3

540

580 ENTHALPY, B.T.U./LB.

620

Figure 17.12B  Section of ethane pressure-enthalpy diagram illustrating five compression paths (used by permission: Edmister, W. C., Applied Hydrocarbon Thermodynamics, © 1961. Gulf Publishing Company, Houston, Texas. All rights reserved).

Based on the prefect gas and the adiabatic equation:

P2/P1 = (V1/V2)k

(17.3)

T2/T1 = (V1/V2)k–1

(17.4)

P2/P1 = (T2/T1)k/(k-1) = r(k–1)/k

(17.5)



PV = WR T

(17.6)



PV = RoT

(17.7)

where Ro = 1545 ft-lbf/lbm-°R P = pressure, lbf/ft2 V = volume, ft3 T = temperature, abs, °R (°F + 460) R = universal gas constant, 1545/ (mol wt of gas) Boyle’s law: For constant temperature (isothermal, but not realized under actual conditions):

530  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.13A  Enthalpy–entropy chart for natural gas, Sp.Gr. = 0.6 (used by permission: Engineering Data Book, 7th © 1957. Natural Gasoline Supply Men’s Association, Inc. All rights reserved).

Compression Equipment  531

Figure 17.13B  Enthalpy–entropy chart for natural gas, Sp.Gr. = 0.7 (used by permission: Engineering Data Book, 7th © 1957. Natural Gasoline Supply Men’s Association, Inc. All rights reserved).

532  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.13C  Enthalpy–entropy chart for natural gas, Sp.Gr. = 0.8 (used by permission: Engineering Data Book, 7th © 1957. Natural Gasoline Supply Men’s Association, Inc. All rights reserved).

Compression Equipment  533

Figure 17.13D  Enthalpy–entropy chart for natural gas, Sp.Gr. = 0.8 (used by permission: Engineering Data Book, 7th © 1957. Natural Gasoline Supply Men’s Association, Inc. All rights reserved).

534  Petroleum Refining Design and Applications Handbook Volume 2

P1V1 = P2V2 = constant = C1

(17.8)

For the adiabatic condition of no heat lost or gained.



P1V1k = P2 V2k



k = n

(17.9)

A reversible adiabatic process is known as isentropic [10]. Thus, the two conditions are directly related. In actual practice, compressors generate friction heat, give off heat, have valve leakage and have piston ring leakage. These deviations from the true adiabatic condition result in the process known as “polytropic.” It is defined as an internally reversible change of state [10] where



P1V1n = P2 V2n = constant (different from preceding )

(17.10)

For a polytropic process the change of state does not take place at constant entropy, but for an adiabatic process, it does. Heat may be added to or rejected from a gas in a polytropic process. For a polytropic process, the correlating exponent for the P1V1n component is the exponent “n,” which becomes an important part of the compressor design. “n” values are determined from performance testing. An adiabatic process is never fully attained but can be closely approached for many processes and is the primary design basis for most positive displacement compression equipment. where k = ratio of specific heats, cp/cv n = polytropic coefficient P1 = inlet pressure, abs, lb(force)/ft2 abs P2 = discharge pressure, abs, lb(force)/ft2 abs R = gas constant, ft-lb(force)/(lbm-°R) = 1545/(mol wt) Rʹ = specific constant for the gas involved = 1545/gas mol wt Ro = universal gas constant = 1545 and is same for all gases = 10.729 when P is lbf/in.2 abs T1 = inlet gas temperature, °R = °F + 460 T2 = discharge gas temperature, °R = °F + 460 V = volume of gas, ft3/lb-mole W = weight of gas, lb 1 = inlet condition (intake) 2 = outlet condition (discharge) Adiabatic Calculations



k −1    P2  k k  Adiabatic heat , Had = RT1   − 1  P1   ( k − 1)  

where Had = adiabatic head, ft-lbf/lbm = ft

(17.11)

Compression Equipment  535 R T1 P1 P2 W

= gas constant, ft-lb(force)/lbm°R = inlet gas temperature, °R = °F + 460 = absolute inlet pressure, lb(f)/in.2 = absolute discharge pressure, lb(f)/in.2 = flow rate of gas, lb/s



1 hp = 550 ft-lbf/s  ft − lbf lbm  Work on the gas during compression = Had (W)  •  s   lbm

HPad



WHad 550

k

(WRT1 ) [(P2 /P1 )( k (k 1) (550)

1)/ k

1]

(17.12)

HPad = horsepower, hp Q = volume flow of gas, ft3/min at inlet conditions

Charles’ Law at Constant Pressure [11] V2/V1 = T2/T1 or

(17.13)

V2/T2 = V1/T1

(17.14)

Amonton’s Law at Constant Volume [11] P2/P1 = T2/T1 or

(17.15)

P2/T2 = P1/T1

(17.16)

Combined Boyle’s and Charles’ Laws

P1V1 P2 V2 = T1 T2

(17.17)

Figures 17.12A and 17.12B illustrate various paths of the compression or expansion of gas that can take place, depending on the properties of the gas/vapor.

Mollier Chart Method After identifying the initial temperature (T) and pressure (P) values, the final temperature and both enthalpy values (H) can be read on the same entropy line of the appropriate gas Mollier chart [9]. For the adiabatic process, the work done on the gas is equal to H [9] (see Figures 17.13A–D). The following is reproduction by permission of Edminster, W.C., Applied Hydrocarbon Thermodynamics, Gulf Publishing Company [9].

536  Petroleum Refining Design and Applications Handbook Volume 2 “When a Mollier chart is available for the gas involved [12, 13] the first method, which is illustrated by Figure 17.12A is the most convenient. On the abscissa of Figure 17.12A, four enthalpy differences are illustrated. (H2 − H1) is the enthalpy difference for the isentropic path. (H2° − H1°) is the ideal gas state enthalpy difference for the terminal temperatures of the isentropic path. The other ΔH values are the isothermal pressures corrections to the enthalpy at the terminal temperatures. A generalized chart for evaluating these pressure corrections was presented previously. As Mollier charts are available for only a few pure components and practically no mixtures, this calculation method is very limited. For example, it cannot be used for most process calculations because these gases are usually mixtures. Some of the charts available for mixtures are the H-S charts presented by Brown [12] for natural gases of gravities from 0.6 to 1.01.”

Entropy Balance Method “Using generalized isothermal effects of pressure and the ideal gas state “S” and “H” values, the final temperature required to satisfy the condition S = 0 is found, and the value of H is determined for the path [9]. The second method can be applied to mixtures as well as pure components. In this method the procedure is to find the final temperature by trial, assuming a final temperature and checking by entropy balance (correct when Spath = 0). As reduced conditions are required for reading the tables or charts of generalized thermodynamic properties, the pseudo critical temperature and pressure are used for the mixture. Entropy is computed by the relation. See reference [12] for details.”



S = S° − RlnP + S

(17.18)

Isentropic Exponent Method [12] Using exponents defining temperature and volume changes with pressure for the gas, the final temperature and work are computed by simple equations.

Many gases deviate from the ideal state when pressures and/or temperatures are greater than 100–500 psia and 100°F. Some deviations yield a compressibility factor, Z, less than 1.0, and others give values greater than 1.0.



PV = ZNRT

(17.1)

PV = 10.73 ZNT

(17.19)

or

where P V T R Z N

= absolute pressure, psia = volume of gas, ft3/lb-mole = absolute temperature, °R (Rankine) = °F + 460 = universal gas constant = 10.729 psia ft3/lb mole .°R for units noted here = compressibility factor = number of lb-moles of gas

Values of gas constant, R, for the other units: R = 1545.3 when P = lbf/ft2, abs R = 0.7302 when P = atmosphere R = 10.729 when P = lbf/in.2, abs Generalized compressibility factors for gases are given in Figures 17.14A–E. These charts have been prepared to allow approximately the same accuracy in reading values over the entire range. Compressibility factors at low

Compression Equipment  537 pressure for several major hydrocarbons are presented by Pfennig and McKetta [14]. Compressibility charts for specific gases are given in Figures 17.14F–W. Figure 17.15 is a compressibility chart for natural gas based on pseudo-reduced pressure and temperature. The reduced pressure is the ratio of the absolute operating pressure to the critical pressure, Pr, and the reduced temperature is the ratio of the absolute operating temperature to the critical temperature, Tc, for a pure gas or vapor. The pseudo value is the reduced value for a mixture calculated as the sum of the mol percentages of the reduced values of the pure constituents.



pseudo Pr = y1Prl + y2Pr2 + y3Pr3, etc.

(17.20)

Similarly, the pseudo-reduced temperature can be determined.



pseudo Tr = y1Trl + y2Tr2 + y3Tr3, etc.

(17.20a)

Values of compressibility are available for many pure hydrocarbons and gases [15, 16, 28]. Figure 17.16A illustrates a compression path for deviation from the ideal that overestimates the actual power required (area of dotted portion is greater than solid line actual area). Actual volumetric efficiency and inlet volume is less than ideal due to the deviation on the re-expansion path [30]. Table 17.2 compares an example for propane; a compressor with 10% clearance, 1000 cfm piston displacement, compression from 100 psia and 80°F to 300 psia. For Figure 17.16B, as illustrated by a 24–76% (volume) mixture of nitrogen-hydrogen at around 5000 psia, the deviation is opposite to that of Figure 17.16A. The actual power requirements are greater than ideal; volumetric efficiency exceeds ideal gas laws. Figure 17.16C illustrates ethylene in the extreme high pressure range (30,000–40,000 psia) where the deviation is unpredictable without thermodynamic data. Figure 17.16D illustrates the type of reciprocating compressor performance problems that can develop from various mechanical details. To maintain peak efficiency in a compressor cylinder, a pressure–time indicator card of the cylinder during operation can be quite helpful in pointing to a problem and its nature [79]. These figures illustrate what takes place inside the cylinder during the compressor’s operation. When specifying performance, the actual capacity at suction and/or discharge conditions must be specified. Table 17.3 lists the variation of compressibility factor, Z, with pressure as read or computed from accepted charts. Compressibility must be taken into account along with the adiabatic coefficient, k (or, if known, the polytropic coefficient, n), and other losses, which will be presented in the following paragraphs. “k” value of Gas (Ratio of Specific Heats). The ratio cp/cv is known as the “k” value of a gas and is associated with adiabatic compression or expansion. The change in temperature during compression (for most average water cooled jackets) is related by



P1V1k = P2 V2k = P3V3k = constant

(17.21)

for the same weight of gas at three different states or conditions. Most compression and expansion curves are represented by the preceding relationship. The actual value of “n” for a polytropic compression is usually 1.0–1.5 and is a function of the gas properties, such as specific heats, degree of cooling during compression (external), and operating features of the cylinder [18]. Figure 17.12 shows the effect of change in “k” on the compression curve. A usual reciprocating compressor performance evaluation uses adiabatic cp/cv, and this is the representation here. With the k = 1.0, the compression is isothermal; with “k” = “n” greater than 1.0, the operation is actually polytropic. For air the adiabatic “k” = 1.4. In adiabatic compression or expansion, no release or gain of heat by the gas occurs, and no change occurs in entropy. This condition is also known as isentropic and is typical of most compression steps. Actual conditions often cause a realistic deviation, but usually these are not sufficiently great to give errors in the calculations. Table 17.4 gives representative average “k” values for a few common gases and vapors. The specific heat is the heat required to raise the temperature of a unit mass of material one degree. Specific heat varies with temperature, but essentially no variation occurs with pressure [19]. The ratio k, is important in most compression-related situations, i.e.,

538  Petroleum Refining Design and Applications Handbook Volume 2

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

REDUCED PRESSURE, PR 0.8 0.9 1.0 1.1

1.2

CED T

RATU

R

1.7

1.8

1.1 0

8

1.0 6

4

COMPRESSIBILITY FACTOR, P V Po Vo T CONSTANT

1.6

1.0

1.02

0.7

1.0

0.6

1.5

2

1.00

0.5

1.8 1.00 0.98 0.96 0.94 0.92 0.90 0.88 0.86 0.84 0.82 0.80 0.78 0.76 0.74 0.72 0.70 0.68 0.66 0.64 0.62 0.60 0.58 0.56 0.54 0.52 0.50 0.48 0.46 0.44 0.42 0.40 0.38 0.36 0.34 0.32 0.30 0.28 0.26 0.24 0.22 0.20 0.18 0.16 0.14 0.12 0.10

1.3 0 1.2 1.2 8 6 1.2 1.2 4 2 1.2 0 1.1 8 1.1 6 1.1 4

1.1

E

0.4

1.7

1.40

LIN

0.3

1.6

1.35

N TIO RA

0.2

1.5

1.50

RE, T

TU SA

0.1

1.4

1.60

EMPE

5

0

1.3

1.70 REDU

0.9

1.00 0.98 0.96 65 1.1 0.94 5 1.25 1.0 0.70 5 0.92 0.90 0.75 0.88 0.86 0.84 0.80 0.82 0.80 0.78 0.76 0.85 0.74 0.72 0.70 0.68 0.90 0.66 0.64 0.92 0.62 0.60 0.58 0.94 0.56 0.54 0.52 0.96 0.50 0.48 0.46 0.44 0.42 0.40 0.38 0.36 COMPRESSIBILITY FACTOR FOR GASES 0.34 0.32 p REDUCED PRESSURE PR = pc 0.30 T 0.28 REDUCED TEMPERATURE TR = Tc 0.26 p, pc, T AND Tc ARE IN ABSOLUTE UNITS 0.24 0.22 pV = 1 FOR IDEAL GASES po Vo T CONSTANT 0.20 0.18 0.16 0.14 COPYRIGHT 1949 0.12 WORTHINGTON PUMP AND MACHINERY CORPORATION 0.10

0.98

0.8 0.9 1.0 1.1 REDUCED PRESSURE, PR

1.2

1.3

1.4

Figure 17.14A  Compressibility factor for gases, Part 1 of 5 (used by permission: Worthington research Bul. P – 7637 © 1949. Dresser-Rand Company. All rights reserved).

PV Po Vo T CONSTANT

COMPRESSIBILITY FACTOR,

1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00 0.98 0.96 0.94 0.92 0.90 0.88 0.86 0.84 0.82 0.80 0.78 0.76 0.74 0.72 0.70 0.68 0.66 0.64 0.62 0.60 0.58 0.56 0.54 0.52 0.50 0.48 0.46 0.44 0.42 0.40 0.38 0.36 0.34 0.32 0.30 0.28 0.26 0.24 0.22 0.20

1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00

0

0

REDUCED

1

5

2

1.1

1.00

1

1.2 0

1.60

1.70

4 3 2.60 2.40 2.20 2.10 2.00 1.90 1.80

1.40

1.45

1.50

1.55

3

3

1.35

1.30 1.25

TURE, TR TEMPERA

2

4

4

40

7

8

REDUCED TE

9

REDUCED PRESSURE, PR

10

10

,T MPERATURE R

1.16 1.14 1.12 0 1.10 1.08 1.1 1.06 1.04 1.02 1.00 0 1.2 0.98 0.96 0.94 0.92 0.90 0.88 0.86 0.84 0.82 0.80 0.78 0.76 0.74 0.72 0.70 0.68 0.66 0.64 0.62 0.60 0.58 0.56 0.54 COMPRESSIBILITY FACTOR FOR GASES 0.52 p 0.50 REDUCED PRESSURE PR = pc 0.48 T 0.46 REDUCED TEMPERATURE TR = Tc 0.44 p, pc, T AND Tc ARE IN ABSOLUTE UNITS 0.42 0.40 pV = 1 FOR IDEAL GASES 0.38 po Vo T CONSTANT 0.36 0.34 0.32 0.30 COPYRIGHT 1949 0.28 0.26 WORTHINGTON PUMP AND MACHINERY CORPORATION 0.24 0.22 0.20 5 6 7 8 9

14 30

5 8

5 6 REDUCED PRESSURE, PR

4 6 10 12 20 40

4 the compressibility factor reaches a maximum, and then decreases with an increase in reduced temperature values, to avoid confusion in reading, the reduced temperature lines greater than 4 are offset on an identical scale.

1.0 5

NOTE: In this range, at reduced temperature approximately equal

8 10 12 14 20 30 40

4 5 6

11

11

12

1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00 12

Compression Equipment  539

1.10

1.05

Figure 17.14B  Compressibility factor for gases, Part 2 of 5 (used by permission: Worthington research Bul. P – 7637 © 1949. Dresser-Rand Company. All rights reserved).

540  Petroleum Refining Design and Applications Handbook Volume 2 11

12

14

13

0 1.5 1.6 0 1 0 2 .80 2.2 .00 0

1.4 0

1.3

1.2

0

1.1

0

1.0

5

10

TR

0 2.4 60 2.

ED

TEM

PER

ATU

RE,

3

RED UC

NOTE: Lines are dotted to aid in reading.

4 3

0 2.6 0 2.4 0

2.2

0

2.0

COMPRESSIBILITY FACTOR FOR GASES 0

1.8

REDUCED PRESSURE PR =

p pc

0

T Tc

1.4

1.6

0

REDUCED TEMPERATURE TR =

1.5 0 1.1 0

p, pc, T AND Tc ARE IN ABSOLUTE UNITS pV

5

T CONSTANT

= 1 FOR IDEAL GASES

1.3 0

po Vo

1.0

1.20 1.19 1.18 1.17 1.16 1.15 1.14 1.13 1.12 1.11 1.10 1.09 1.08 1.07 1.06 1.05 1.04 1.03 1.02 1.01 1.00 0.99 0.98 0.97 0.96 0.95 0.94 0.93 0.92 0.91 0.90 0.89 0.88

9

COPYRIGHT 1949

WORTHINGTON PUMP AND MACHINERY CORPORATION

0

1.40 1.39 1.38 1.37 1.36 1.35 1.34 1.33 1.32 1.31 1.30 1.29 1.28 1.27 1.26 1.25 1.24 1.23 1.22 1.21

8

1.2

COMPRESSIBILITY FACTOR,

PV Po Vo

T CONSTANT

REDUCED PRESSURE, PR 7

7

8

9

10 11 REDUCED PRESSURE, PR

12

13

14

1.40 1.39 1.38 1.37 1.36 1.35 1.34 1.33 1.32 1.31 1.30 1.29 1.28 1.27 1.26 1.25 1.24 1.23 1.22 1.21 1.20 1.19 1.18 1.17 1.16 1.15 1.14 1.13 1.12 1.11 1.10 1.09 1.08 1.07 1.06 1.05 1.04 1.03 1.02 1.01 1.00 0.99 0.98 0.97 0.96 0.95 0.94 0.93 0.92 0.91 0.90 0.89 0.88

Figure 17.14C  Compressibility factor for gases, Part 3 of 5 (used by permission: Worthington research Bul. P – 7637 © 1949. Dresser-Rand Company. All rights reserved).

2.50 2.48 2.46 2.44 2.42 2.40 2.38 2.36 2.34 2.32 2.30 2.28 2.26 2.24 2.22 2.20 2.18 2.16 2.14 2.12 2.10 2.08 2.06 2.04 2.02 2.00 1.98 1.96 1.94 1.92 1.90 1.88 1.86 1.84 1.82 1.80 1.78 1.76 1.74 1.72 1.70 1.68 1.66 1.64 1.62 1.60 1.58 1.56 1.54 1.52 1.50 1.48 1.46 1.44 1.42 1.40 1.38 1.36 1.34 1.32 1.30 1.28 1.26 1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00

12

12

PV Po Vo T CONSTANT

COMPRESSIBILITY FACTOR

14

15

16

17

T Tc

D

CE

TE

14

PE

M

,TR RE TU A R

15

16

17

COPYRIGHT 1949 WORTHINGTON PUMP AND MACHINERY CORPORATION

pV = 1 FOR IDEAL GASES po Vo T CONSTANT

p, pc, T AND Tc ARE IN ABSOLUTE UNITS

DU RE

13

p pc

REDUCED TEMPERATURE TR =

REDUCED PRESSURE PR =

COMPRESSIBILITY FACTOR FOR GASES

13

18

18

19

19

20

20

22

22

23

23

REDUCED PRESSURE, PR

21

21

REDUCED PRESSURE, PR

24

24

25

25

26

26

27

27

28

28

29

29

30

30

31

31

32

2.50 2.48 2.46 2.44 2.42 2.40 2.38 2.36 2.34 2.32 2.30 2.28 2.26 2.24 2.22 2.20 2.18 2.16 2.14 2.12 2.10 2.08 2.06 2.04 2.02 2.00 1.98 1.96 1.94 1.92 1.90 1.88 1.86 1.84 1.82 1.80 1.78 1.76 1.74 1.72 1.70 1.68 1.66 1.64 1.62 1.60 1.58 1.56 1.54 1.52 1.50 1.48 1.46 1.44 1.42 1.40 1.38 1.36 1.34 1.32 1.30 1.28 1.26 1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00

32

Compression Equipment  541

Figure 17.14D  Compressibility factor for gases, Part 4 of 5 (used by permission: Worthington research Bul. P – 7637 © 1949. Dresser-Rand Company. All rights reserved).

542  Petroleum Refining Design and Applications Handbook Volume 2

30

REDUCED PRESSURE, PR

40

45

50

60

65

70

75

80

90

85

95

0

2.40

p pc

REDUCED TEMPERATURE TR =

2.6

2.00

2.20

REDUCED PRESSURE PR =

T Tc

p, pc, T AND Tc ARE IN ABSOLUTE UNITS

4.0

3.5

3.0

pV = 1 FOR IDEAL GASES po Vo T CONSTANT

5

4.5

COPYRIGHT 1949 WORTHINGTON PUMP AND MACHINERY CORPORATION

6

,TR RE

D CE

M

TE

7

TU RA

PE

DU

RE

9 10

12

14

20

25 30

40

35

40

45

50

55

60

65

70

REDUCED PRESSURE, PR

75

80

85

90

100 2.58 2.56 2.54 2.52 2.50 2.48 2.46 2.44 2.42 2.40 2.38 2.36 2.34 2.32 2.30 2.28 2.26 2.24 2.22 2.20 2.18 2.16 2.14 2.12 2.10 2.08 2.06 2.04 2.02 2.00 1.98 1.96 1.94 1.92 1.90 1.88 1.86 1.84 1.82 1.80 1.78 1.76 1.74 1.72 1.70 1.68 1.66 1.64 1.62 1.60 1.58 1.56 1.54 1.52 1.50 1.48 1.46 1.44 1.42 1.40 1.38 1.36 1.34 1.32 1.30 1.28 1.26 1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00

8

COMPRESSIBILITY FACTOR

55

COMPRESSIBILITY FACTOR FOR GASES

PV Po Vo T CONSTANT

2.58 2.56 2.54 2.52 2.50 2.48 2.46 2.44 2.42 2.40 2.38 2.36 2.34 2.32 2.30 2.28 2.26 2.24 2.22 2.20 2.18 2.16 2.14 2.12 2.10 2.08 2.06 2.04 2.02 2.00 1.98 1.96 1.94 1.92 1.90 1.88 1.86 1.84 1.82 1.80 1.78 1.76 1.74 1.72 1.70 1.68 1.66 1.64 1.62 1.60 1.58 1.56 1.54 1.52 1.50 1.48 1.46 1.44 1.42 1.40 1.38 1.36 1.34 1.32 1.30 1.28 1.26 1.24 1.22 1.20 1.18 1.16 1.14 1.12 1.10 1.08 1.06 1.04 1.02 1.00 30

35

95

100

Figure 17.14E  Compressibility factor for gases, Part 5 of 5 (used by permission: Worthington research Bul. P – 7637 © 1949. Dresser-Rand Company. All rights reserved).

Compression Equipment  543

1.25

BROKEN LINES INDICATE EXTRAPOLATION

1.20

COMPRESSIBILITY FACTOR Z =

PV RT

1.15

1.10

°F 400 300° 200° 150°

1.05

100° 80° 60° 40° 20°

1.00

0° –20°

0.95

–40°

COMPRESSIBILITY CHART FOR AIR

0.90

BASED ON: DIN – THERMODYNAMIC PROPERTIES OF GASES BUTTERWORTHS SCIENTIFIC PUBLICATIONS TRANSACTIONS OF THE ASME – OCTOBER, 1954, HALL AND IBELE TABULATION OF IMPERFECT GAS PROPERTIES NATIONAL BUREU OF STANDARDS CIRCULAR 564, 1955 ISSUE CU. FT./POUND AT 14.696 PSIA AND 60°F = 13.106 Z AT 14.696 PSIA AND 60°F = 0.9985 © INGERSOLL – RAND COMPANY 1960

0.85

0.80

0

1000

2000

3000 PRESSURE – PSIA

4000

5000

6000

Figure 17.14F  Compressibility factor for air (used by permission: From 3519 D (1981), © Ingersoll-Rand Company. All rights reserved).

544  Petroleum Refining Design and Applications Handbook Volume 2

1.00

0°

380° 20

0.95

340°

°

300°

COMPRESSIBILITY FACTOR Z =

PV RT

40

280° 260° 240°

° 60

°

SAT UR

0.90

220°

ATI ON L

80 °

200°

INE

180°

10

0°

160

°

12

0°

14

0°

0.85

COMPRESSIBILITY CHART FOR AMMONIA – (NH3) BASED ON BUREAU OF STANDARDS CIRCULAR NO. 142 – 1945 PRINTING CU FT./POUND AT 14.696 PSIA AND 60°F = 22.05 Z AT 14.696 PSIA AND 60°F = 0.989 © INGERSOLL – RAND COMPANY 1960

0.80

0

50

100

150 PRESSURE – PSIA

200

250

300

Figure 17.14G  Compressibility chart for ammonia (used by permission: From 3519 D (1981), © Ingersoll-Rand Company. All rights reserved).

Compression Equipment  545

1.00

1.00 –50° –30° –10°

0° ° 40

10°

0.95

80 °

12

0°

16

0° 200°

240

°

280°

320°

360°

0.95

COMPRESSIBILITY FACTOR Z =

PV RT

30°

0.90

0.90

SA TU

RA TIO

NL

COMPRESSIBILITY CHART FOR CHLORINE – (Cl2)

0.85

INE

0.85

ADAPTED BY PERMISSION FROM R. M. KAPOOR AND J. J. MARTIN “THERMODYNAMIC PROPERTIES OF CHLORINE” ENGINEERING RESEARCH INSTITUTE PUBLICATIONS, UNIVERSITY OF MICHIGAN (1957) CU. FT/LB. AT 14.696 PSIA AND 60°F = 5.2834 Z AT 14.696 PSIA AND 60°F = 0.988 © INGERSOLL – RAND COMPANY 1967

0.80

0

50

100

150 PRESSURE – PSIA

200

250

300

0.80

Figure 17.14H  Compressibility chart for chlorine (used by permission: From 3519 D (1981), © 1967. Ingersoll-Rand Company. All rights reserved).

546  Petroleum Refining Design and Applications Handbook Volume 2

1.30

COMPRESSIBILITY FACTOR Z =

PV RT

1.20

1.10 400°F 300°

200° 150°

100° 60° 40° 20°

1.00

0° –20°

COMPRESSIBILITY CHART FOR NITROGEN – (N2)

–40°

BASED ON SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” NATIONAL BUREAU OF STANDARDS CIRC, 564 — 1955 ISSUE TRANSACTIONS OF THE ASME, OCTOBER 1954, HALL AND IBELE, “TABULATION OF IMPERFECT GAS PROPERTIES CU. FT./POUND AT 14.696 PSIA AND 60°F = 13.55 Z AT 14.696 PSIA AND 60°F = 0.999 © INGERSOLL – RAND COMPANY 1960

1.90

0

1000

2000

3000 PRESSURE – PSIA

4000

5000

6000

Figure 17.14I  Compressibility chart for nitrogen (used by permission: From 3519 D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

Compression Equipment  547

1.00 400° 350°

0.90

–4

0°

–2

0°

0°

20

°

40

°

60°

80°

COMPRESSIBILITY FACTOR Z =

PV RT

0.80

100

°

120

140

°

160

180°

200°

220°

240°

260°

300° 280°

°

°

0.70 SAT

0.60

UR

ATI O

NL

INE

0.50

0.40 COMPRESSIBILITY CHART FOR CARBON DIOXIDE (CO2) 0.30

BASED ON: DIN “THERMODYNAMIC FUNCTIONS OF GASES” SWEIGERT, WEBER AND ALLEN, “THERMODYNAMIC PROPERTIES OF GASES” − IND. B ENG. CHEM. FEB, 1946– NATIONAL BUREAU OF STANDARDS CIRC. 564-1955 ISSUE PERRY, “CHEMICAL ENG HANDBOOK.”

0.20

CRITICAL POINT

CU. FT./POUND AT 14.696 PSIA AND 60°F = 8.576 Z AT 14.696 PSIA AND 60°F = 0.994 © INGERSOLL RAND COMPANY 1960

0

100

200

300

400

500

600 700 PRESSURE – PSIA

800

900

1000

1100

1200

1300

Figure 17.14J  Compressibility chart for low pressure carbon dioxide (used by permission: From 3519 D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

548  Petroleum Refining Design and Applications Handbook Volume 2

1.00

0.90

400° F 350°

0°

0.80

0.70

260°

SAT TIO URA

240°

IN NL

0.60

220°

E

COMPRESSIBILITY FACTOR Z =

PV RT

300° 280°

20°

40°

200° 60°

0.50

180°

80°

160° 140°

0.40 120°

0.30 CRITICAL POINT

COMPRESSIBILITY CHART FOR CARBON DIOXIDE (CO2)

100°

BASED ON “THERMODYNAMIC FUNCTIONS OF GASES” VOL. 2, DIN. “THERMODYNAMIC PROPERTIES OF GASES,” SWEIGERT, WEBER, AND ALLEN. INDUSTRIAL AND ENGINEERING CHEMISTRY–FEB. 1946 NATIONAL BUREAU OF STANDARDS-CIRCULAR 564-1955 ISSUE CHEMICAL ENGINEERING HANDBOOK–PERRY CU. FT./POUND AT 14.696 PSIA AND 60°F = 8.576 Z AT 14.696 PSIA AND 60°F = 0.994 © INGERSOLL RAND COMPANY – 1960

0.20

0

1000

2000

3000 PRESSURE – PSIA

4000

5000

6000

Figure 17.14K  Compressibility chart for high pressure carbon dioxide (used by permission: From 3519 D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

Compression Equipment  549

1.15

1.10

DASH LINES ARE REFERENCE “A” SOLID LINES ARE REFERENCE “B”

1.05

400° 350° 300°

COMPRESSIBILITY FACTOR Z =

PV RT

1.00

250°

0.95

200° 180° 160°

0.90

140°

DOTTED LINES ARE EXTRAPOLATED

120° 100°

0.95

80°

COMPRESSIBILITY CHART FOR METHANE (CH4)

60°

0.80

REFERENCE “A” SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS.” MATTHEWS AND HURD, “THERMODYNAMIC PROPERTIES OF METHANE” – TRANSACTIONS, AMERICAN INSTITUTE OF CHEM. ENGINEERS, VOLUME 42–NO. 4. REFERENCE “B” AMERICAN GAS ASSOCIATION, “PAR RESEARCH PROJECT REPORT NX–19.” (COMPLETED DECEMBER 1962) CU. FT/LB. AT 14.696 PSIA & 60°F = 23.61 Z AT 14.696 PSIA & 60°F = 0.997 © INGERSOLL–RAND COMPANY 1966

40°

0.75

20°

0°

0.70

0.65

0

1000

2000

3000 PRESSURE – PSIA

4000

5000

6000

Figure 17.14L  Compressibility chart for methane (used by permission: From 3519 D (1981), © 1966. Ingersoll-Rand Company. All rights reserved).

550  Petroleum Refining Design and Applications Handbook Volume 2

1.00

0.90

350 ° 300 ° 250 225 ° ° 200 ° 175 °

0° –2

–80°

15

–60°

0°

0.80

12

5°

°

20

0°

10

PV RT

–40°

°

80

0.70

°

TIO RA

60

TU SA N

°

40

E

LIN

COMPRESSIBILITY FACTOR Z =

0°

0.60

0.50 COMPRESSIBILITY CHART FOR ETHYLENE (C2H4) BASED ON: H. BENZLER AND A.V. KOCH TECHNISCHEN HOCHSCHULE KARLSRUHE 1954 CU. FT./LB AT 14.696 PSIA AND 60°F = 13.453 Z AT 14.696 AND 60°F = 0.9947 © INGERSOLL –RAND COMPANY 1967

0.40

0

100

200

300

400 500 PRESSURE – PSIA

600

700

800

900

1000

Figure 17.14M  Compressibility chart for low pressure ethylene (used by permission: From 3519 D (1981), © 1967. Ingersoll-Rand Company. All rights reserved).

Compression Equipment  551

1.10

1.00

0.90

350° 300°

0.80

°

250 25°

0.70

2 °

200

40°

60°

0.50

0.40

E

0.30

CRITICAL POINT

1

5°

12 0°

10

80

0

°

COMPRESSILITY CHART FOR ETHYLENE (C2H4) BASED ON: H. BENZLER AND A.V. KOCH TECHNISCHEN HOCHSCHULE KARLSRUHE 1954 CU. FT/LB AT 14.696 AND 60°F = 13.453 Z AT 14.696 AND 60°F = 0.9947 © INGERSOLL − RAND COMPANY 1967

°

60 40

0.20

0.10

°

175 50°

80°

0.60

TION LIN SATURA

COMPRESSIBILITY FACTOR - Z =

RT

100°

PV

0°

°

1000

2000

3000

4000

5000

6000

PRESSURE − PSIA

Figure 17.14N  Compressibility chart for high pressure ethylene. Note: special charts are available for pressures in the range 20,000–75,000 psi (used by permission from 3519 D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

552  Petroleum Refining Design and Applications Handbook Volume 2 1.00

400° 350°

0.90

16

14

RT

0°

0.70

TU SA N

TIO RA E

LIN

COMPRESSIBILITY FACTOR Z =

PV

0° 12 0° 10

80°

60 °

40°

20° 0°

0.80

0°

300° 280 260 ° 240 ° 22 ° 0° 20 0 ° 18 0°

0.60

0.50

COMPRESSIBILITY CHART FOR ETHANE (C2H6) BASED ON = SAGE AND LACEY, ” THERMODYNAMIC PROPERTIES OF HYDROCARBONS” AND “THERMODYNAMIC PROPERTIES OF ETHANE” BARKELEW, VALENTINE AND HURD, “TRANSACTIONS OF AICHE”− VOL. 43 NO. I, JANUARY 1947 CU. FT./LB. AT 14.696 PSIA AND 60°F = 12.52 Z AT 14.696 PSIA AND 60°F = 0.992 © INGERSOLL − RAND COMPANY 1960

0.40

0

200

400

600

800

1000

PRESSURE - PSIA

Figure 17.14O  Compressibility chart for low pressure ethane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

Compression Equipment  553 1.10

1.00

0.90

0.80

0.70

350°

0°

300° 280°

20° 40° 60° 80°

260° 240° 220°

0.60

200°

N RATIO SATU

COMPRESSIBLITY FACTOR Z = PV RT

400°

0.50

180°

LINE

160°

0.40

COMPRESSIBILITY CHART FOR ETHANE (C2H6)

140°

BASED ON: SAGE AND LACEY, ” THERMODYNAMIC PROPERTIES OF HYDROCARBONS” AND, “THERMODYNAMIC PROPERTIES OF ETHANE” − BARKELEW, VALENTINE AND HURD, ”TRANSACTION OF AICHE,” VOL. 43 NO. I JANUARY 1947. CU. FT./LB. AT 14.696 PSIA AND 60°F = 12.52 Z AT 14.696 PSIA AND 60°F = 0.992 © INGERSOLL − RAND COMPANY 1960

120° 0.30

CRITICAL POINT

0

100°

1000

2000

3000 4000 PRESSURE − PSIA

5000

6000

Figure 17.14P  Compressibility chart for high pressure ethane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).



k = cp/cv

(17.22)

For monatomic gases, k is about 1.66; for diatomic gases, k is about 1.40; and for polyatomic gases, k is about 1.30. Details of values for specific heat of gases are available in many engineering tables. The ratio, k, may be calculated from the ideal gas equation:



k = c p /c v =

M cp M cp − 1.987

(17.23)

where Mcp = molal heat capacity at constant pressure, Btu/lb-mol (°F) M = molecular weight When values of Mcp are not available, they may be calculated:

Mcp = A + BT, Btu/mol/l °R

(17.24)

with T in °Rankine at compressor cylinder inlet. The constants A and B may be obtained from Table 17.5. Table 17.5A gives MCp values for gases at varying temperature in °R.



k = cp/cv = cp/(cp − 1.987)

(17.25)

554  Petroleum Refining Design and Applications Handbook Volume 2

1.00

0.90

0.80

60° 80°

COMPRESSIBLITY FACTOR Z =

PV RT

100° 120°

0.70

400°

140° 0.60

350°

160°

325° 180°

0.50

300° 280° 260°

0.40 240° 0.30

200°

COMPRESSIBILITY CHART FOR PROPYLENE (C3H6)

220°

BASED ON - CANJAR, GOLDMAN, AND MARCHMAN, “THERMODYNAMIC PROPERTIES OF PROPYLENE” INDUSTRIAL AND ENGINEERING CHEMISTRY VOL. 43, NO. 5, MAY 1951... CU. FT/LB. AT 14.696 PSIA AND 60°F = 9.021 Z AT 14.696 PSIA AND 60°F = 0.9836

NL

INE

CRITICAL POINT

SAT

URA TIO

0.20

0.10 0

500

© INGERSOLL − RAND COMPANY 1960

2000

1500

1000

2500

3000

PRESSURE − PSIA

Figure 17.14Q  Compressibility chart for propylene (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

where cp and cv are specific heats at constant pressure and constant volume respectively, Btu/lb-mol-°F [20]. To obtain the average value of cp for a gas mixture, use the weighted mole fraction average, evaluating cp at the average of the suction and discharge temperatures of the compressor cylinder. Depending on the magnitude of the compression ratio, the cp at suction temperature can be used when the ratio is small. m  = isentropic or adiabatic exponent = (k − 1)/k m = n = polytropic exponent = (k − 1)/kEp Ep  = polytropic efficiency = m/m = [(k − 1)/k]/[(n − 1)/n]

m

1(k 1) E p (k )

m Ep

(n 1) (n)

Mcp = Mcv + 1.987  Btu/(lbmol.°F) Then; k =

Mc p c p Mc p = = Mc v c v Mc p −1.987

(17.26) (17.27) (17.28)

Compression Equipment  555

1.0 –50° 0.9

0° 400°F

COMPRESSIBLITY FACTOR Z =

PV RT

50°

350°

10

0.8

0°

12

300° 280° 260°

0° 14

0°

0.7

SAT

16 0° URA TIO NL

18

0°

INE

0.6

20

0°

24 0 22 230° ° 0 ° 21 0°

0.5

0.4

COMPRESSIBILITY CHART FOR PROPANE (C3H8)

0.3

CRITICAL POINT

BASED ON: SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” – STEARNS AND GEORGE, “THERMODYNAMIC PROPERTIES OF PROPANE” INDUSTRIAL AND ENGINEERING CHEMISTRY − VOL. 35, NO. 5 – MAY 1943... CU. FT/LB. AT 14.696 PSIA AND 60°F = 8.471 Z AT 14.696 PSIA AND 60°F = 0.9875 © INGERSOLL − RAND COMPANY 1962

0.2

0

100

200

300 PRESSURE − PSIA

400

500

600

Figure 17.14R  Compressibility chart for low pressure propane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

where M = molecular weight of gas c = specific heat, Btu/lb-°F temperature rise Mcp = molar heat capacity, Btu/(lb mol-°F) ([60] see tables this reference), constant pressure; Mcv = molar heat capacity at constant volume, Btu/lb mol-°F 1.989 = constant for all hydrocarbon gases For mixtures of gases, calculate the average Mcp by multiplying the individual gas mol % of each component by its respective Mcp (see Reference [11] or other sources for tables) and sum to get the molar average, Mcp, for the mixture. For the ratio of specific heat, see Eq. 17.28. For a perfect gas:

cp – cv = R

(17.29)

For real gases, the relationship applies [19].

cp − cv = R/J

(17.30)

(cp/cv)ideal = cp/(cp − R)

(17.31)

556  Petroleum Refining Design and Applications Handbook Volume 2 1.2 1.1 1.0

100° .8 120° 140° 160° .7 180° 200°

400° 380° 360° 340° 320° 300°

ON ATI UR SAT

.6 .5

E LIN

COMPRESSIBILITY FACTOR Z = PV RT

.9

280°

.4

260°

COMPRESSIBILITY CHART FOR PROPANE (C3H8)

240°

.3

CRITICAL POINT

220°

BASED ON SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” STEARNS AND GEORGE, “THERMODYNAMIC PROPERTIES OF PROPANE” INDUSTRIAL AND ENGINEERING CHEMISTRY. VOL. 35, NO. 5, MAY 1943... CU. FT/LB. AT 60°F AND 14.696 PSIA = 8.471 Z AT 60°F AND 14.696 PSIA = 0.9875

.2 .1

© INGERSOLL − RAND CO. 1960

0

500

1000

1500

2000

2500

3000

3500

4000

PRESSURE − PSIA

Figure 17.14S  Compressibility chart for high pressure propane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

where cp and cv are specific heats at constant pressure and constant volume respectively, Btu/lb-°R. R = gas constant, ft-lbf/lb-mol-°R J = Joules’ constant = 778 ft-lbf/Btu or, for a real gas [21].

cp cp = c v c p − (c p − c v )



(17.32)

From Edmister [16], Δcp = 1.44[(cp − cv°)/k2], where Δcp cp° R R'

= Btu/(lb-mol)(°R) = mol heat capacity at ideal gas state = universal gas constant = 1545 ft-lbf/lbm-°R. For dry air: R = 53.35 ft-lbf/lbm°R. = gas constant for a specific gas, 1545/(mol wt)

From combined Boyle’s and Charles’ Law Equation of State for Perfect Gas:



Pv = RT/Cp = RT

(17.33)

Compression Equipment  557

COMPRESSIBILITY CHART FOR N-BUTANE (C4H10)

1.00

.90

BASED ON: SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” CU FT./POUND AT 14.696 PSIA AND 60°F = 6.327 Z AT 14.696 PSIA AND 60°F = 0.975 © INGERSOLL − RAND COMPANY 1960

100°F

14

0° 18

0° 22 0° SAT 24 URA 0° TIO NL INE

RT

COMPRESSIBILITY FACTOR – Z =

PV

.80

.70

400°

380 ° 360 ° 34 0°

26

0° 28

.60

0°

32

30

0°

0°

.50

.40

.30 CRITICAL POINT .20

0

100

200

300

400

500

600

PRESSURE − PSIA

Figure 17.14T  Compressibility chart for low pressure N-butane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

v = specific volume, ft3/lbm P = absolute pressure, lbf/ft2 abs R = gas constant, ft-lbf/lbm-°R T = absolute temperature, °R = (°F + 460) Cp = conversion factor = 1.0 For real gases: Pv = ZRT Z  = compressibility factor

17.9 Compressor Performance Characteristics Piston Displacement Piston displacement is the actual volume of the cylinder displaced as the piston travels its stroke from the start of the compression (condition (1)) to the end of the stroke (condition (e)) of Figure 17.12 expressed as ft3 of volume displaced per minute. Displacement values for specific cylinder designs are available from the manufacturers (Table 17.6). Neerken [22] is a useful reference. Reciprocating compressors are usually rated in terms of piston displacement, which is the net volume in ft3 per minute displaced by the moving piston [23]. Note that the piston does not move through the clearance volume of Figure 17.12; therefore this volume is not displaced during the stroke.

558  Petroleum Refining Design and Applications Handbook Volume 2 1.20

°F 100 ° 5 1 00° 20 50° 2 ° 300

1.10

350°

.90

400°

.80 .70 .60 .50 .40 .30

0° 4075° 3 ° 35205° 3 0° NE 30 ° N LI 250 URATIO SAT

COMPRESSIBILITY FACTOR Z = PV RT

1.00

CRITICAL POINT

COMPRESSIBILITY CHART FOR N-BUTANE (C4H10)

.20

BASED ON: SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” CU FT/POUND AT 14.696 PSIA AND 60°F = 6.327 Z AT 14.696 PSIA AND 60°F = 0.975 © INGERSOLL − RAND COMPANY 1960

.10

0

500

1000

1500

2000 2500 PRESSURE − PSIA

3000

3500

4500

4000

Figure 17.14U  Compressibility chart for high pressure N-butane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

For Single-acting Cylinder (Figure 17.4A)



PD = Aps(rpm)/1,728

(17.34)

where PD = piston displacement, cfm Ap = c ross-sectional net area of piston, in.2 If cylinder is head-end, Ap is total area of piston; if cylinder is crank-end, Ap is net area of piston area minus rod cross-section area. s = stroke length, in. rpm = revolutions per minute of crank shaft or number of compression strokes per minute For Double-acting Cylinder (Figure 17.4B): The displacement of the head end and crank end of the cylinder must be added for the total displacement. The displacement of the crank end is less than that of the head end by the volume equivalent to the piston rod displacement. For a multistage unit, the piston displacement is often only given for the first stage [24].

A p s(rpm) (A p − A r )s(rpm) + 1, 728 1, 728



PD =



PD = (Ap − Ar/2)2s(rpm)/1728

where Ar = cross-sectional area of piston rod, in.2

(17.35) (17.35a)

Compression Equipment  559

1.00 100° 0.90 120° 140°

18

0.80

0°

0.70

400°

20

0°

SAT

-400 ° 380° 360 °

22

0°

URA TIO

24

340

0°

N LI

NE

0.60

26 0°

COMPRESSIBILITY FACTOR Z =

PV RT

160°

°

30

28

°

320 0°

0°

0.50

0.40

0.30

COMPRESSIBILITY CHART FOR ISOBUTANE (C4H10)

CRITICAL POINT

BASED ON: SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” Z AT 14.696 PSIA AND 60°F = 0.992 CU. FT/LB. AT 14.696 PSIA AND 60°F = 6.339 © INGERSOLL – RAND COMPANY 1960

0.20

0

100

200

300

400

500

600

PRESSURE – PSIA

Figure 17.14V  Compressibility chart for low pressure iso-butane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

Compression Ratio The compression ratio is the ratio, Rc, of the absolute discharge pressure to the absolute suction pressure of the cylinder:

Rc = P2/P1

(17.36)

where P1 = initial suction pressure, absolute units P2 = cylinder discharge pressure at cylinder flange, absolute units Compression ratios usually vary between 1.05 and 7 per stage; however, a ratio of 3.5–4.0 per stage is considered maximum for most process operations. Quite often temperature rise of the gas during the compression dictates a limit for the safe or reasonable pressure rise. The maximum temperature rise is governed either by the maximum operating temperature of the compressor cylinder or by the maximum temperature the gas can withstand before decomposition, polymerization, or even auto-ignition as for chlorine, acetylene, etc. Because the volumetric efficiency decreases with an increase in compression ratio, this also adds to the selection of a reasonable limiting

560  Petroleum Refining Design and Applications Handbook Volume 2

1.10

0.90 0.80 200° 0.70

220° 240° 260°

0.60

450°F

UR SAT

0.50

N ATIO

COMPRESSIBILITY FACTOR Z = PV RT

1.00

0.40

LINE

0.30

CRITICAL POINT 280°

400° 380° 360° 340° 320° 300° COMPRESSIBILITY CHART FOR ISOBUTANE ( C4H10)

0.20

BASED ON - SAGE AND LACEY, “THERMODYNAMIC PROPERTIES OF HYDROCARBONS” Z AT 14.696 PSIA AND 60°F = 0.992 CU. FT/LB AT 14.696 PSIA AND 60°F = 6.339 © INGERSOLL – RAND COMPANY 1960

0.10

0

500

1000

1500

2000

2500

3000

3500

4000

PRESSURE – PSIA

Figure 17.14W  Compressibility chart for high pressure iso-butane (used by permission from 3519D (1981), © 1960. Ingersoll-Rand Company. All rights reserved).

discharge pressure. With a known maximum temperature, the maximum ratio of compression can be calculated from the adiabatic temperature rise relation. The optimum minimum horsepower occurs when the ratios of compression are equal in all cylinders for multistage units. With external cooling of the gas between stages, it is necessary to make reasonable allowances for pressure drops through the intercoolers and take this into account when setting the compression ratios: a. Ideal (no intercooling), for four stages (cylinders)

P2/P1 = P3/P2 = P4/P3

(17.37)

b. Actual (with intercooling)



Pi1 /P1 = Pi 2 /Pil′ = Pi 3 /Pi′2 = … Pfy /Piy

(17.38)

where 1,2,3,.…y = conditions of gas across a cylinder represented by (1) for first stage, (2) for second stage, etc. i = interstage discharge pressure condition, immediately at cylinder. Prime (') = interstage discharge condition, reduced by the pressure drop through the intercoolers, valves, piping, etc.; therefore, a prime represents actual pressure to suction of succeeding cylinder in multistage cylinder system. f = final or discharge pressure from multistage unit.

Compression Equipment  561 PSEUDO REDUCED PRESSURE 3

2

4

5

6

PSEUDO REDUCED TEMPERATURE 3.0 2.8 2.6 2.4 2.2 2.0 1.9 1.8

1.0

0.9

7

1.5

1.0 1.05 1.2 1.3 0.95 1.1

1.4

1.7

1.0

1.6 0.8

8 1.1

5

1.1

1.5 1.45

1.2

1.4 0.7

1.6

1. 3

1.35

COMPRESSIBILITY FACTOR Z

1.3 0.6

1.4 1.5 1.5 1.6

1.25

1.7

1.2 0.5 1.15

0.4

1.7

1.1

1.8 1.9 2.0 2.2

1.4

2.4 2.6 3.0

1.3

1.2

0.3 1.05

0.25

3.0 2.8

1.1

0.9

1.1

2.6 2.4 2.2 2.0 1.9 1.8 1.7 1.6

1.0

1.2 1.1

1.0

COMPRESSIBILITY OF NATURAL CASES JAN. 1, 1961

1.05

1.4 1.3 7

COMPRESSIBILITY FACTOR Z

1.1

1

0

0.9 8

9

10

11

12

13

14

15

PSEUDO REDUCED PRESSURE PR Pseudo-reduced temperature = Pseudo-reduced pressure =

absolute temperature molecular average critical temperature absolute pressure molecular average critical pressure

Figure 17.15  Compressibility factor for natural gas (used by permission: G.G. Oberfell, D. L. Katz, and R. C. Alden. Natural Gasoline Association of American, Inc. All rights reserved).

562  Petroleum Refining Design and Applications Handbook Volume 2 (A)

Note: Details of Losses not Shown, See Fig. –4 Discharge

Pressure

Ideal Gas Law Actual

Co m

pre

ssi

on

Intake Volume or Stroke Compressibility Factor Less than 1.0 (B)

Pressure

Ideal Gas Law Actual

Volume or Stroke Compressibility Factor Greater than 1.0 (C)

Pressure

Ideal Gas Law

Actual

Volume or Stroke Compressibility Factor Greater than 1.0: Extreme Deviation (Ethylene Discharging at 30,000 – 40,000 psig)

Figure 17.16A–C  Deviations from the ideal gas law.

Compression Equipment  563

1

2

3

4

5

6

7

8

9

1–Suction Valve Chatters Probably due to weak valve springs, and may result in broken valve plate or a leaky valve. 2–Discharge Valve Chatters Shows weak springs in the discharge valves, and will result in a broken valve plate or a leaky valve, which in turn will result in cylinder heating and loss of horsepower. 3–Suction Passage Too Small In addition to too small a suction passage, too small a valve lift could also be indicated. 4–Discharge Passage Too Small In addition to too small a discharge passage, too small a valve lift could also be indicated. 5–Suction Valve Spring Too Sti Too stiff a suction valve means a loss of horsepower. Valve spring of proper tension should be installed. 6–Discharge Valve Spring Too Sti Too stiff a discharge valve spring likewise results in loss of horsepower. Valve spring of proper tension should be installed here, also. 7–Suction Valve Leaking Leak may be in either the valve or the valve gasket. 8–Discharge Valve Leaking Curve 1 indicates a badly leaking discharge valve; curve 2 a slightly leaking one. Leak may be in the valve or in the valve gasket. 9–Piston Ring Leaking Leaky piston rings may be due to worn rings, out of round compressor cylinders, or weak expander rings used with plastic-type piston rings.

Figure 17.16D  Typical compressor aliments and how they look on P-T diagrams (used by permission: Palmer, E. Y. Petroleum Processing, p. 884, June 1954. © National Petroleum News, Adams Business Media).

Table 17.2  Comparison of performance for propane. Actual

Ideal

Volumetric efficiency

0.802

0.835

cfm at inlet conditions

0.802

835

Specific volume in inlet, ft3/lb

1.160

1.314

lb handled/min

691

635

Basic horsepower required

388

425

Horsepower/lb

0.561

0.670

Used by permission: Hartwick, W. Chemical Engineering, p. 204, Oct. 1956. ©McGraw-Hill, Inc. All rights reserved.

564  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.3  Compressibility factors, Z. Propane

24% Nitrogen–76% Hydrogen

Pressure, Psia

Z

Psia

Z

Psia

Z

100

0.884

1,600

1.061

400

0.954

160

0.838

2,400

1.092

500

0.953

220

0.800

3,500

1.129

600

0.955

300

0.765

4,800

1.172

700

0.957

Used by permission: Hartwick, W. Chemical Engineering, p. 204, Oct.1956. ©McGraw-Hill, Inc. All rights reserved).

Table 17.4  Approximate ratio of specific heats (“k” values) for various gases. k @ 14.7 psia Gas

Symbol

Monatomic

He, Kr, Ne, Hg

1.67

Most diatomic

O2, N2, H2, etc

1.4

Acetylene

C2H2

Air

Mol wt

60°F

150°F

Density @ 14.7 psia & 60°F lb/ft3

26.03

1.3

1.22

0.0688

28.97

1.406

1.40

0.0765

17.03

1.317

1.29

0.0451

Ammonia

NH3

Argon

A

Benzene

C6H6

78.0

1.08

1.09

0.2064

Butane

C4H10

58.1

1.11

1.08

0.1535

Isobutane

iC4H10

58.1

1.11

1.08

0.1578

Butylene

C4H8

56.1

1.1

1.09

0.1483

Iso-butene

iC4H8

56.1

1.1

1.09

0.1483

Carbon dioxide

CO2

44.0

1.3

1.27

0.1164

Carbon monoxide

CO

28.0

1.4

1.4

0.0741

Carbon tetrachloride

C Cl4

153.8

1.18

0.406

Chlorine

Cl2

70.9

1.33

0.1875

Dichlorodifluoromethane

C Cl2F2

120.9

1.13

Dichloromethane

CH2Cl2

84.9

1.18

Ethane

C2H6

30.0

1.22

1.17

0.0794

Ethylene

C2H4

28.1

1.25

1.21

0.0741

Ethyl chloride

C2H5Cl

64.5

1.13

1.667

Flue gas Helium

0.1056

0.2245

0.1705

1.14 He

4.0

1.667

0.01058 (Continued)

Compression Equipment  565 Table 17.4  Approximate ratio of specific heats (“k” values) for various gases. (Continued) k @ 14.7 psia Gas

Symbol

Mol wt

60°F

150°F

Density @ 14.7 psia & 60°F lb/ft3

Hexane

C6H14

86.1

1.08

1.05

0.2276

Heptane

C7H16

100.2

1.04

0.264

Hydrogen

H2

2.01

1.41

1.40

0.0053

Hydrogen chloride

HCl

36.5

1.48

Hydrogen sulfide

H2S

34.1

1.30

1.31

0.0901

Methane

CH4

16.03

1.316

1.28

0.0423

Methyl chloride

CH3Cl

50.5

1.20

0.1336

19.5

1.27

0.0514 0.0793

Natural gas (approx.)

0.09650

Nitric oxide

NO

30.0

1.40

Nitrogen

N2

28.0

1.41

Nitrous oxide

N 2O

44.0

1.311

Oxygen

O2

32.0

1.4

1.39

0.0846

Pentane

C5H12

72.1

1.06

1.06

0.1905

Propane

C3H8

44.1

1.15

1.11

0.1164

Propylene

C3H6

42.0

1.16

0.1112

Sulfur dioxide

SO2

64.1

1.256

0.1694

Water vapor (steam)

H2O

18.0

1.33*

1.40

0.0743 0.1163

1.32

0.04761

*At 212°F. Used and compiled by permission: “Plain Talks on Air and Gas Compression,” Fourth of Series, Worthington. Dresser-Rand Corporation. Also compiled by permission from “Reciprocating Compressor Calculation Data,” ©1956. Dresser-Rand Corporation.

Compression ratios across stages:

R 1 = Pi1 /P1 R 2 = Pi 2 /Pi′1



R 3 = Pi 3 /Pi′2 R f = Pfy /Piy′



R 1 = R 2 = R 3 =…R f = y R t



(17.39)

where Rt= overall compression ratio of unit = Pi/P1. For two-stage, compression per stage is



R 1 = R 2 = Pf 2 / P1

(17.39a)

566  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.5  Constants for molal heat capacity. Gas

Formula

Air

Molecular weight

Critical press, psia

Critical temp, °R

A

B

28.97

546.7

238.4

6.737

0.000397

Ammonia

NH3

17.03

1,638

730.1

6.219

0.004342

Carbon dioxide

CO2

44.01

1,073

547.7

6.075

0.005230

Carbon monoxide

CO

28.01

514.4

241.5

6.780

0.000327

Hydrogen

H2

2.016

305.7

72.47

6.662

0.000417

Hydrogen sulfide

H2S

34.07

1,306

672.4

7.197

0.001750

Oxygen

O2

32.00

730.4

277.9

6.459

0.001020

Sulfur dioxide

SO2

64.06

1,142

774.7

Water

H2O

18.02

3,200

1,165

7.521

0.000926

Methane

CH4

16.04

673.1

343.2

4.877

0.006773

Acetylene

C2H2

26.04

911.2

563.2

6.441

0.007583

Ethene

C2H4

28.05

748.0

509.5

3.175

0.013500

Ethane

C2H6

30.07

717.2

549.5

3.629

0.016767

Propene

C3H6

42.08

661.3

656.6

4.234

0.020600

Propane

C3H8

44.09

617.4

665.3

3.256

0.026733

1-Butane

C4H8

56.11

587.8

75.2

5.375

0.029833

Isobutene

iC4H8

56.11

580.5

736.7

6.066

0.028400

Butane

C4H10

58.12

530.7

765.3

6.188

0.032867

Isobutane

iC4H10

58.12

543.8

732.4

4.145

0.035500

Amylene

C5H10

70.13

593.7

853.9

7.980

0.036333

Isoamylene

C5H10

70.13

498.2

836.6

7.980

0.036333

Pentane

C5H12

72.15

485.0

846.7

7.739

0.040433

Isopentane

C5H12

72.15

483.5

829.7

5.344

0.043933

Neopentane

C5H12

72.15

485.0

822.9

4.827

0.045300

Benzene

C6H6

78.11

703.9

1,011

-0.756

0.038267

Hexane

C6H14

86.17

433.5

914.3

9.427

0.047967

Heptane

C7H16

100.2

405.6

976.8

11.276

0.055400

Used by permission: Hartwick, W. Chemical Engineering, p. 209, Oct. 1956. ©McGraw-Hill, Inc. All rights reserved.

26.038 28.054 30.070 42.081 44.097 56.108 56.108 56.108 58.124 58.124 72.151 72.151 78.114 86.178 100.205

C2H2 C2H4 C2H6 C3H6 C3H8 C4H8 C4H8 C4H8 C4H10 C4H10 C5H12 C5H12 C6H6 C6H14 C7H16

Methane

Ethyne (Acetylene)

Ethene (Ethylene)

Ethane

Propene (Propylene)

Propane

1-Butane (Butlyene)

cis-2-Butene

trans-2-Butene

iso-Butane

n-Butane

iso-Pentane

n-Pentane

Benzene

n-Hexane

n-Heptane

16.043

CH4

Gas

M

Chemical formula

142.943

123.401

66.435

105.133

101.897

85.277

83.476

77.329

67.598

73.359

64.176

55.878

47.131

38.254

39.888

34.301

−25

154.539

133.303

74.060

112.603

110.369

91.270

90.078

82.587

73.268

79.583

68.783

59.898

49.882

40.906

42.020

34.931

0

Temperature, °C

159.011

137.144

77.034

115.565

113.675

93.685

92.690

84.628

75.461

81.961

70.605

61.459

50.904

41.937

42.778

35.199

10

165.985

143.110

81.675

120.211

118.792

97.447

96.815

87.823

78.925

85.663

73.524

63.895

52.666

45.559

43.926

35.717

25

*Data source: selected values of properties of hydrocarbons, API Research Project 44

Table 17.5A  Molal heat capacity MCp (ideal-gas state), kJ/mole °C.

177.141

152.709

89.224

130.686

127.335

105.326

103.624

92.979

84.508

91.509

78.561

67.832

55.723

46.115

45.650

36.744

50

188.293

162.308

96.761

136.160

135.581

110.334

110.408

98.174

90.154

97.310

83.585

71.789

58.819

48.695

47.235

37.870

75

199.400

171.884

104.324

144.452

144.029

117.024

117.340

103.387

95.851

103.111

88.820

75.762

62.114

51.283

48.720

39.201

100

210.046

181.080

111.321

152.182

152.011

123.326

123.932

108.434

101.323

108.493

93.820

79.584

65.294

53.753

49.981

40.529

125

(Continued)

220.585

190.194

118.202

161.448

159.999

130.400

130.521

113.464

106.800

113.860

98.838

83.395

68.556

56.214

51.168

41.986

150

Compression Equipment  567

29.131 29.079 28.290

31.999 28.013 2.016 34.076

O2 N2 H2 H2S CO CO2

Oxygen

Nitrogen

Hydrogen

Hydrogen sulfide

Carbon monoxide

Carbon dioxide

34.700

44.010

35.962

29.123

33.673

28.611

29.114

29.240

33.474

29.067

35.636

0

36.411

29.105

33.815

28.687

29.092

29.265

33.488

29.078

35.640

10

37.122

29.146

34.028

26.502

29.114

29.361

33.572

29.098

35.645

25

38.212

29.150

34.379

28.964

29.116

29.481

33.678

29.141

35.653

50

39.261

29.193

34.729

29.065

29.140

29.647

33.832

29.196

35.661

75

40.290

29.263

35.080

29.126

29.196

29.870

34.032

29.262

35.670

100

41.199

29.319

35.434

29.158

29.219

30.045

34.207

29.339

35.678

125

42.095

29.405

35.792

29.178

29.279

30.274

34.424

29.429

35.688

150

Source: Gas Processors Suppliers Association (GPSA) Engineering Data Book, SI Version, vol. 1, 12th ed., 2004.

*Exceptions: Air—Keenan and Keyes, Thermodynamic Properties of Air, Wiley, 3rd Printing 1947. Ammonia—Edw. R. Grabl, Thermodynamic Properties of Ammonia at High Temperatures and Pressures, Petr. Processing, April 1953, Hydrogen Sulfide—J. R. West. Chem. Eng. Progress, 44, 287, 1948.

29.087

28.010

33.313

33.388

18.015

H2O

29.048

35.626

17.031

Water

Ammonia

−25

M

28.964

NH3

Gas

Temperature, °C

Air

Chemical formula

*Data source: selected values of properties of hydrocarbons, API Research Project 44

Table 17.5A  Molal heat capacity MCp (ideal-gas state), kJ/mole °C. (Continued)

568  Petroleum Refining Design and Applications Handbook Volume 2

Compression Equipment  569 Table 17.6  Typical reciprocating air compressor data. Single-stage horizontal

Size, in.

rpm

5×5

550

Two-stage, angle vertical

Piston Max. press., displacement, psi cfm

Size, in.

rpm

Two-Stage, Horizontal Duplex Piston displacement, cfm

Size, in.

rpm

Piston displacement, cfm

150

61

11¼/7 × 7

600

478

21/13 × 14

277

1546

6×5

100

88

13½/8½ × 7

600

690

23/14 × 14

277

1858

7×5

60

121

14½/9½ × 7

600

798

24/15 × 17

257

2275

8×5

40

157

16/10½ × 7

600

973

28/17 × 19

225

3031

10 × 5

20

248

18½/11½ × 8½

514

1351

30½/18 × 21

200

3704

20½/13 × 8½

514

1662

34½/21 × 25

180

4847

450

1975

225

6065

450

2412

30 1 2 18 1 2 / × 22 30 1 2 18 1 2

200

7396

34 1 2 21 / × 25 34 1 2 21

180

9673

36 1 2 22 / × 25 36 1 2 22

180

10,808

39 1 2 23 / × 25 39 1 2 23

164

12,189

6×7

150

100

7×7

100

138

8×7

60

180

10 × 7

35

283

12 × 7

20

410

8×9

450

1 17 3 4 / 16 × 9 2 17 3 4

28 17 / × 19 28 17

135

184

9×9

100

234

10 × 9

75

290

12 × 9

40

420

15 × 9

20

658

125

321

Designation numbers in table for multiple cylinders.

12 × 11

100

465

Bore of first stage/bore of second stage x stroke, all in inches.

14 × 11

60

635

15 × 11

50

730

17 × 11

30

940

19 × 11

20

1174

20 × 11

15

1300

125

502

14 × 13

100

686

17 × 13

55

1016

19 × 13

40

1270

10 × 11

12 × 13

360

1 16 /141 / 2 × 9 2 16

327

300

For example:

1 1 16 / 14 × 9 16 2 2

There are two first-stage cylinders, 16-in. dia. In parallel, one 14 ½ -in. second-stage cylinder and all on 9 ½ -in. stroke length.

(Continued)

570  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.6  Typical reciprocating air compressor data. (Continued) Single-stage horizontal

Size, in.

rpm

20 × 13

23 × 13 26 × 13

277

Two-stage, angle vertical

Piston Max. press., displacement, psi cfm 35

1410

20

1717

12

2202

Size, in.

rpm

Two-Stage, Horizontal Duplex Piston displacement, cfm

Size, in.

rpm

Piston displacement, cfm

Used by permission: “Feather Valve Compressor Selection Handbook,” Worthington bul. L-600-B16. Dresser-Rand Company.

For five stages:



R 1 = R 2 = R 3 = R 4 = R 5 = 5 Pf 5 / P1

(17.39b)

It is common practice to use intercoolers on multistage machines. The function of the intercooler is to cool the gas to as near the original suction temperatures as practical with as little pressure drop as possible. With temperature sensitive material, this is essential. This cooling effects a savings in the required brake horsepower as it essentially is cooling at constant pressure and results in a smaller volume of gas to be handled by the next cylinder. To effect the greatest saving, the coldest cooling practically available should be used. In some cases, it is desirable to use a two-stage compression without intercooling. If the composition of the gas must remain constant throughout the compression and the temperature does not limit, intercoolers cannot be used if condensables are present. Sometimes two stages are used on low “k” or “n” value gases to improve the volumetric efficiency. When this is the case and high compression temperatures or economy of operation do not control, it may be advantageous to omit the intercooler. Note that when intercoolers are not used, the compressor jacket water should be 10–15°F greater than the interstage dew point. This will require warm jacket water through the preceding stage. The intercooler operation does not outwardly affect the theoretical optimum compression ratio per stage. However, it does affect the cumulative horsepower required to do the work of total compression, because all the pressure drop lost must be replaced as horsepower. There is also a gain in performance due to this intercooling as is shown in Figures 17.17A and 17.17B. The allowance for intercooler pressure drop is usually made by increasing the discharge pressure from the cylinder to include one-half of the intercooler pressure drop between stages, and the suction pressure on the following stage is reduced to the other one-half of the pressure drop, when compared to the theoretical pressures with no pressure drop allowance. Ratio of compression per stage may be calculated.

Pf = P1R − ( p1)R −1 − ( p2)R −2

– ( p3)Ry−3 − ( p4)Ry−4…..

(17.40)

Continue for number of terms on right side of equation equal to number of stages. This is usually best solved by trial and error and can be simplified if most of the P values are assumed equal. It assumes all the intercooler pressure drop is deducted from the suction pressure of the succeeding stage, i.e., first stage intercooler pressure drop is deducted from second stage suction pressure. Pf = final pressure of multistage set of cylinders = number of compression stages

Compression Equipment  571 Saving due to Jacketing of Cylinder Discharge Pressure Adiabatic Compression Average Compression Line had Compression Occurred in One Cylinder Saving Due to Intercooling

Pressure

H-p Card

If Perfect Intercooling between Stages, c c

L-p Card

Intercooler Pressure

b

Suction Temperature after Intercooling Saving due to Jacketing L-p Cylinder

Isothermal Compression Intake Pressure

Adiabatic Compression a

Volume

Clearance

Figure 17.17A  Combined indicator cards from a two-stage compressor showing how cylinder water jackets and intercooler help bring compression line nearer to isothermal (used and adapted by permission: Miller, H. H. Power, © 1994. McGraw-Hill, Inc., New York, All rights reserved). C D

B

P2

10%

5%

10%

15%

Pressure

5%

15% P1

A

E F High Clearance Volume Moderate Clearance Volume Low Clearance Volume

Figure 17.17B  Effects of clearance volume on performance efficiency of reciprocating compressor cylinder (valve design effect) (used by permission: Livingston, E. H. Chemical Engineering Progress, V. 89, No. 2 © 1993. American Institute of Chemical Engineers, Inc. All rights reserved).

p = pressure drop across interstage coolers, psi 1 = first stage 2 = second stage If one half p is added to discharge of one stage and one half deducted from suction of next stage:

Pf = P1R − (1/2 p1)R −1 − (1/2 p2)R −2

− (1/2 p3)R -3 − (1/2 p4)R -4 ….

(17.41)

572  Petroleum Refining Design and Applications Handbook Volume 2 In practice, the ratios for each stage may not work out to be exactly the same; however this does not keep the compressor from operating satisfactorily as long as all other factors are handled accordingly. Compressor Jacket Cooling. The compressor jacket cooling water does not have to be as warm as does the gas engine jacket water. Water 15–20°F warmer than the dew point of the gas being compressed will ensure against condensation. A maximum of 15–20°F rise in jacket water temperature is recommended. The flow of water to the jackets should never be throttled in order to maintain this temperature as the lowered velocity tends to facilitate fouling of the jackets. The amount of heat rejected by compressor jackets varies with the size and type of machine. This heat rejection is usually given as Btu/h/bhp. Heat rejection to the compressor cylinder will average about 500 Btu/h/bhp. Some are low as 130, and it is necessary to check with the manufacturer to obtain an accurate figure.

Example 17.1: Interstage Pressure and Ratios of Compression For two stages of compression, what should be the pressures across the cylinders if the intercooler and piping pressure drop is 3 psi?



Suction to first stage: P1 = 0 psig (14.7 psia)



Discharge from second stage: Pf2 = 150 psig (164.7 psia)



Per stage: Rc = 164.7 / 14.7 = 11.2 = 3.35 No intercooling:

  R c = 3.35 Pi1 = 3.35(14.7 ) = 49.2 psia   P1 = 14.7 psia



  R c = 3.35 Pf 2 = 164.7  P2 = 49.2

With intercooling: First stage:

  R c = 3.45 Pil = 49.2 + ( 1 2 )(3.0) = 50.7 psia   P1 = 14.7 psia

Second stage:



Pi′1 = 49.2 − ( 1 2 )(3.0) = 47.7 psia   R c = 3.445 Pf 2 = 164.7 

The example shows that although the ratios per cylinder are balanced, they are each greater than the theoretical. This corresponds to actual operations.

Compression Equipment  573 It is important to note that quite often the actual compression ratios for the individual cylinders of a multistage machine will not be balanced exactly. This condition arises as a result of the limiting horsepower absorption for certain cylinder sizes and designs of the manufacturer. In the final selection, these will be adjusted to give compression ratios to use standard designs as much as possible.

Actual Capacity or Actual Delivery, Va This is the volume of gas measured at the intake to the first stage of a single or multistage compressor at stated intake temperature and pressure, ft3/min. Manufacturer performance guarantees usually state that this capacity is subject to 6% tolerance when intake pressure of first stage is 5 psig or lower, and may state a volume tolerance of about 3% for pressures above this 5 psig intake [25]. It is extremely important to state whether the capacity value has been corrected for compressibility. At low pressures, compressibility is usually not a factor, however, if conditions are such as to not require the use of compressibility, it is usually omitted and so stated. The actual required capacity may be calculated for process requirements, or if a known cylinder is being examined.

Va = PD(Ev); cfm cylinder will compress at suction pressure and temperature Ev = volumetric efficiency, is based on the characteristics of the cylinder.

(17.42)

Ev, or sometimes Ev, is the volumetric efficiency of a cylinder and is the ratio of the amount of gas that is actually compressed to the amount of gas that could be compressed if no clearance existed in the cylinder (see Figure 17.12). Ev can be obtained from Figures 17.18A–F.

(

)

%E v = 100 − R c − (Vpc ) R 1c/k − 1



(17.43)

Clearance Volume This is the total volume remaining in the cylinder at the end of the piston stroke. This consists of the volume between the end of the piston and the cylinder head, in the valve ports and the volume in the suction valve guards and the discharge valve seats [25] (see Figures 17.12, 17.17A, and 17.17B). The effect of clearance volume is shown in Figures 17.17A and 17.17B [98]. The illustrated volumes of 5%, 10%, and 15% usually satisfy a reasonable process compressor range. For example, in the 15% compression slope, ABC will reach pressure shown as P2 sooner than the slope of the 10% curve. Upon re-expansion at the end of the compression stroke DEF, the slope is steeper and allows the gas to enter the cylinder sooner during the suction or intake cycle [98]. The volumetric efficiency increases with a decrease in clearance volume and a decrease in compression ratio [98]. This is the most profound effect, although other design factors do influence the efficiency to a lesser extent. In attempting to balance volumetric and compression efficiency, Livingston [98] points out “for a high compression ratio (6 to 15) clearance volume is the key factor with valve design being secondary. For a compression ratio of 3 to 6, the clearance volume and valve design should be balanced. For low compression ratio, less than 3, the valve design is the primary factor.”

Percent Clearance Percent clearance is the volume % of clearance volume to total actual piston displacement [25].



Vpc = Calculate for each cylinder end.

Vc (100) PD′

(17.44)

574  Petroleum Refining Design and Applications Handbook Volume 2 where Vc = clearance volume, in.3 Vpc = percent clearance PD' = piston displacement, in.3 For double-acting cylinders, the clearance at the head end should be calculated separately from that of the crank end, because for small cylinders, the volume occupied by the piston rod is significant when cylinder unloading is considered. For double-acting cylinders, % clearance is based on total clearance volume for both the head end and crank end of the cylinder × 100 divided by the total net piston displacement. The head and crank end % clearance values will be different due to the presence of the piston rod in the crank end of the cylinder. The % clearance values are available from manufacturers for their cylinders. The values range from about 8% for large 36-in. cylinders to 40% for small 3- and 4-in. cylinders. Each cylinder style is different.

Cylinder Unloading and Clearance Pockets For a discussion of this important performance control topic, refer to “Cylinder Unloading,” later in this chapter and Figure 17.27. A reasonable average range is 7–22% with fixed valve pockets [98].

Volumetric Efficiency Volumetric efficiency is the efficiency of a cylinder performance based on operating experience and actual volume conditions.

(

)

%E v = 100 − R c − Vpc R 1c/k − 1



(17.45)

where Rc = ratio of compression across an individual cylinder. Volumetric efficiency may be expressed as the ratio of actual cylinder capacity expressed at actual inlet temperature and pressure conditions, divided by the piston displacement (see Figure 17.17B). Values of Ev may be read from Figures 17.18A–F for values of Rc and Vpc. For example, in a multistage compressor, such as a two-stage compressor, each cylinder does one half of the total work of compression. The low pressure or first stage of the two-stage unit controls the capacity of the overall compressor, i.e., the second stage can handle only the volume of gas passed to it from the discharge of the first-stage cylinder. That is, the gas that passes through the low or first-stage discharge valves must continue on through the compressor’s second (or final in this case) stage cylinder and be discharged at the specified pressure and calculated/actual temperature. Thus, in all compressors of two or more stages, the volumetric efficiency of the low-pressure cylinder determines the volumetric efficiency of the entire compressor (not recognizing packing leaks) [23].

Compression Efficiency (Adiabatic) The compression efficiency is the ratio of the work required to adiabatically compress a gas to the work actually done within the compressor cylinder as shown by indicator cards (Figures 17.12 and 17.16). The heat generated during compression adds to the work that must be done in the cylinder. Valves may vary from 50% to 95% efficient depending on cylinder design and the ratio of compression. Compression efficiency (or sometimes termed volumetric efficiency) is affected by several details of the systems. a. b. c. d. e.

 rocess gas compression ratio across the cylinder. P Compressibility of the gas at inlet and discharge conditions, compression ratio. Compression valve action including friction and leakage. Nature of the gas, for example, its ratio of specific heat and compression exponent. Leakage across the piston rings during compression stroke.

Compression Equipment  575 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95

CO M

90

90

PRE S

SOR

CYL

IND

ER

85

CLE

ARA

85

NC

E5

%

80

80 10

70 15

60

40 30

25

40

30 35

30

40

20

60

1.5

2.0

70

80 90 100%

10

50

50

20

60

20

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N-1)

50

70

2.5 3.0 3.5 COMPRESSION RATIO

10

4.0

4.5

Figure 17.18A  Compressor volumetric efficiency curve for gas with k or n of 1.15 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).

f. T  ype and loss through intake and discharge valves. g. Moisture or condensibles in the gas being compressed. h. Clearance volume of cylinder. The compressor manufacturer can control items a–c, e, f, and h; however, the control of clearance volume at high compression ratios for gases/vapors with low specific heat ratios is of great concern [98]. Compression efficiency is controlled by the clearance volume valves, and valve pocket design. A decrease in compression efficiency leads to increased power requirements [98].

Mechanical Efficiency Mechanical efficiency is the ratio of compressor cylinder indicated horsepower to the brake horsepower. Efficiency values range from 90%–93% for direct-driven cylinders to 87%–90% for steam engine units. The efficiency of the driver is not included.

576  Petroleum Refining Design and Applications Handbook Volume 2 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95

90

COM

PRE

90 SSO

RC

85

YLI

ND

ER C

LEA

RAN

CE

85 5%

80

80 10

70

70 15

60

40

40

35

30 20

60 70

1.5

2.0

80 90

100%

10

30

50

20

50

25

40

30

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N–1)

50

60 20

10

2.5 3.0 3.5 COMPRESSION RATIO

4.0

4.5

Figure 17.18B  Compressor volumetric efficiency curve for gas with k or n of 1.20 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).

Piston Speed Piston speed is a useful guide to set relative limits on compressor cylinder selection. It is difficult to establish acceptable and nonacceptable limits because this is best evaluated with operating experience and compressor manufacturer’s recommendations.



Piston speed =

(rpm)(s) , ft / min 6

(17.46)

This is of more significance in corrosive or polymer-forming services than in clean hydrocarbon or air applications. For example in hydrogen chloride and chlorine service using cylinders with either (a) cast iron liners or (b) carbon piston rings, a speed of around 600 ft per min is acceptable.

Compression Equipment  577 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95

COM PRE

90

90

SSO

RC

YLIN D

ER C

LEA RAN

85

CE 5

%

85

80

80 10

70

70 15

60

40

40

35

30

50

20

2.0

80

1.5

70

90 100%

10

30

60

20

50

25

40

30

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N–1)

50

60

20

2.5 3.0 3.5 COMPRESSION RATIO

10

4.0

4.5

Figure 17.18C  Compressor volumetric efficiency curve for gas with k or n of 1.25 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).

Horsepower Horsepower is the work done in a cylinder on the gas by the piston connected to the driver during the complete compression cycle. The theoretical horsepower is that required to isentropically (adiabatically) compress a gas through a specified pressure range. The indicated horsepower is the actual work of compression developed in the compressor cylinder(s) as determined from an indicator card [26]. The brake horsepower (bhp) is the actual horsepower input at the crankshaft of the compressor drive. It does not include the losses in the driver itself, but is rather the actual net horsepower that the driver must deliver to the compressor crankshaft. Single Stage Theoretical Hp



 P  ( k −1)/k  144  k  2  Hp = − 1   P1V1   33, 000 k − 1  P1  

(17.47)

578  Petroleum Refining Design and Applications Handbook Volume 2 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95 COM

PRE S

90

SOR

90 CYL IND ER C LEA RAN

CE 5

85

%

85

80

80 10

70 60

40

50

30

40

35

30 50

20

60

20

25

40

30

60

20

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N–1)

50

70

15

70

1.5

2.0

80

100%

90

10

2.5 3.0 3.5 COMPRESSION RATIO

10

4.0

4.5

Figure 17.18D  Compressor volumetric efficiency curve for gas with k or n of 1.30 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).

Actual Brake Horsepower, Bhp

 P  ( k −1)/k  144  k  2 Bhp = − 1 (L o )(FL )Z1   P1V1   33, 000  k − 1  P   1  



(17.48)

= suction pressure, psia = discharge pressure, psia = suction volumetric rate, ft3/min, at suction conditions = loss factor, comprised of losses due to pressure drop through friction of piston rings, rod packing, valves, and manifold (see Figure 17.19). FL = frame loss for motor-driven compressors only, values range 1.0–1.05 (note, this is not a driver efficiency factor) Z1 = compressibility factor, based on inlet conditions to cylinder (usually negligible, except at high pressures) (see Figures 17.14 and 17.15).

where P1 P2 V1 Lo

Figure 17.20 is convenient to use in solving the complete theoretical power expression, giving

Compression Equipment  579 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95

COM

90

PRE

90

SSO

R CY

LIND

ER C

LEA

85

80

20

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N–1)

60

25

50

30 35

40

40

30

50

60

20

85

70

45

30

%

80

15

60

40

CE 5

10

70

50

RAN

20

70

1.5

2.0

80

90 100%

10

2.5 3.0 3.5 COMPRESSION RATIO

10

4.0

4.5

Figure 17.18E  Compressor volumetric efficiency curve for gas with k or n of 1.35 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).



 Btu lb mole  Theoretical hp = Fw Z1T1N m / 2, 546  •o R •  o h   lbmole R

( k −1)/ k   k   P2    where Fw = R  − 1    k − 1   P1   

(17.49a)

(17.49b)

R = gas constant = 1.987 Btu/(lbmole.°R) Nm = lb-mol/h T1 = suction or inlet temperature, °R = (°F + 460) 1 hp (U.S.) = 2542.5 Btu/h To obtain actual brake horsepower, bhp, multiply the theoretical hp by Lo and FL. The actual brake horsepower, bhp is:



bhp = (Theoretical horsepower) (Lo) (FL)

(17.49c)

580  Petroleum Refining Design and Applications Handbook Volume 2 1.5

2.0

2.5

3.0

3.5

4.0

4.5

95

95

COM

90

90

PRE SSO

R CY LIND ER C

LEA R AN

CE 5

85

80

20

40

25

50

30 35

40

40

30

50

60

20

60

45

30

VOLUMETRIC EFFICIENCY PERCENT % Ev = 100–R-%CL.(R1/N–1)

50

70

15

60

85

80

10

70

%

20

70

1.5

2.0

80

90 100%

10

2.5 3.0 3.5 COMPRESSION RATIO

10

4.0

4.5

Figure 17.18F  Compressor volumetric efficiency curve for gas with k or n of 1.40 (used by permission: Natural Gasoline Supply Men’s Association Data Book, © 1957. Origin Ingersoll-Rand Co. All rights reserved).

The values of n shown on the chart are Edmister’s isentropic exponents [27, 28]; however, the chart satisfactorily solves the preceding relation using “k” values. Loss Factor. The loss factor is a correction factor for standard horsepower curves for high suction pressures at low ratios of compression. The bhp (brake horsepower) is obtained from the curves (Figures 17.21A–C). These curves are a plot of the “n” or “k” value of the gas versus the required brake horsepower (required to compress 1 million ft3 of gas at 14.4 psia and suction temperatures) for various ratios of compression. The bhp curves give a value greater than the actual. At high ratios of compression, this deviation is not significant. However, when the compression ratio is less than 2.5 and the suction pressure is initially high, appreciable deviation may be encountered. From a percentage standpoint, this average is an appreciable part of the total bhp requirements, and a correction should be made by use of the “loss factor” multiplier (Figure 17.19). When the use of the “loss factor” is indicated and exact thermodynamic data on the gas handled is available, refer to a reliable compressor manufacturer for a more exact correction, which will indicate a lower bhp requirement. This case is justifiable but must be handled with caution and be accompanied by firm operating conditions. That is, there should be very little change of the suction and discharge temperatures, pressures, or capacity requirements. For approximate power requirements [29].

Compression Equipment  581 1.9 Actual Horsepower = (Adiabatic Hp) (Loss Factor, Lo) For Cp/Cv = 1.20 Adiabatic Hp/MMcfd = 262(R 0.2/1.2–1) c Loss Curve applies for all Cp/Cv

1.8

1.7

1.6

Loss Factor

1.5

1.4

1.3

Rc

Actual Bhp/MM See Fig.-21A,B,C

Adiabatic Hp/MM

1.1

10.0

4.19

2.39

1.2

15.4

8.07

1.91

1.4

24.4

15.1

1.616

1.7

34.9

24.2

1.44

2.0

43.0

32.1

1.34

2.5

54.5

43.2

1.26

3.0

65.1

52.6

1.24

3.5

74.1

60.8

1.22

4.0

82.5

68.1

1.21

5.0

98.5

80.7

1.205

6.0

113.0

91.1

1.20

Loss Factor

1.2

1.1

1.0

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

6.0

Pressure Ratio

Figure 17.19  Loss factor curve (used by permission: Cooper-Cameron Corporation).



ghp =

w 1H , gas horsepower (33, 000)( ηp )

(17.50)

Adjust for balanced piston leakage, 2% [29] Add losses for seal hp, (x) The shaft horsepower, shp is expressed by:



shp = [(ghp)(1.02)] + [losses, (x*)], shaft horsepower



* range (60–80) hp depends on number of stages and type of shaft seal

where ghp = gas horsepower shp = shaft horsepower H = head, (ft-lbf/lbm) =ft w1 = weight flow, lb/min ηp = polytropic efficiency, fraction, for selected units. See Table 17.9B (Centrifugal Compressors)

(17.51)

582  Petroleum Refining Design and Applications Handbook Volume 2 0.15

0.5

0.6

0.7

0.8

0.9 1.0

ISENTROPIC WORK FACTOR FOR COMPRESSION AND EXPANSION

–0.5

7.0

–1.0

6.5

–1.5

6.0 FOR EXPANDERS USE TOP AND LEFT SCALES

1.3

T AN ST

ES LIN

1

N CO F O

TA N

Tn

1.2

1.1

OF

1.0

1.0

4.0

ES

0.9

LIN

0.9

3.5

0.8

0.8

–4.0

4.5

CO NS

–3.5

5.0

1.

1.5 1.4 1.3

n

1.2

–2.5

–3.0

5.5

1 1.4 .5

–2.0

VALUES OF Fw FOR COMPRESSOR CALCULATIONS

RATIO: P2/P1 0.3 0.4

0.2

–4.5

3.0

–5.0

FOR COMPRESSORS USE BOTTOM AND RIGHT SCALES

–5.5

2.0

NOTES:

1. UNIT OF WORK: (Fw) (Zl) (Tl) = BTU/LB MOLE GAS 2. DIVIDE BTU/LB MOLE BY 2546 TO GET WORK IN HORSEPOWER.

–6.0

2.5

1.5

VALUES OF Fw FOR COMPRESSOR CALCULATIONS

0

0.1

∫ vdp = Zl Tl Fw n–1 P2 n n Fw = R –1 n–1 P1

1.0

WHEN: PVR = CONSTANT

1.0

1.5

2

3 4 RATIO: P2/P1

5

0.5

6

7

8

9

0 10

Figure 17.20  Chart for solving theoretical work of compression or expansion (used by permission: Edmister, W. C., Petroleum Refiner, V. 38, No. 5, © 1959. Gulf Publishing Co. All rights reserved).

Compression Equipment  583 60 30 0

75

25

80

0

PS

IG

&

AB

OV E

BHP/MMCFD CORRECTION FACTORS

200 150

90

100

50 95

4 1. W

1.5 2.0 COMPRESSION RATIO, R

2.5

0

100 1.0

PSIG & BELO

1 1. .2 1. 1 3

85

1.

BHP/MMCFD, BRAKE HORSEPOWER PER MILLION CUBIC FEET PER DAY AT 14.4 AND SUCTION TEMPERATURE

50

BHP/MMCFD CORRECTION FACTOR

70

40

K VALUES (RATIO OF SPECIFIC HEATS) Cp K= Cv 30

20

10 1.0

NOTE: FOR R = 1.0 TO 2.5 MULTIPLY BHP/MMCFD BY CORRESPONDING CORRECTION FACTOR OBTAINED FROM ABOVE CURVE. MECHANICAL EFFICIENCY OF COMPRESSOR CYLINDER = 95%

1.2

1.4

1.6

1.8

2.0

2.2

2.4 2.5

COMPRESSION RATIO, R

Figure 17.21A  Brake horsepower required to deliver 1 million ft3 of gas per day, part 1 of 3 (used by permission: Cooper-Cameron Corporation. All rights reserved).

Actual Brake Horsepower, Bhp (Alternate Correction for Compressibility) The development of Hartwick [30] indicates an approach to correcting the ideal gas horsepower for the effects of compressibility. The results examined with high pressure (a maximum discharge pressure of 15,000 psia) systems give agreement within less than 6% of enthalpy methods. 1. Determine gas specific volume at inlet conditions to cylinder:



v = ZRT/(144P), ft3/lb

Obtain Z from compressibility charts (Figure 17.14) (or for specific gas or mixtures, if available).

(17.52)

584  Petroleum Refining Design and Applications Handbook Volume 2 90

BHP/MMCFD, BRAKE HORSEPOWER PER MILLION CUBIC FEET PER DAY AT 14.4 PSIA AND SUCTION TEMPERATURE

85

80

K

75

=

4 1.

1.3

1.2

70

1.1

65 1.0

60

NOTE: MECHANICAL EFFICIENCY OF COMPRESSOR CYLINDER = 95%

55

50 2.5

2.6

2.8

3.0

3.2 3.4 COMPRESSION RATIO, R

3.6

3.8

4.0

Figure 17.21B  Brake horsepower required to deliver 1 million ft3 of gas per day, part 2 of 3 (used by permission: Cooper-Cameron Corporation. All rights reserved).



R = 1544/mol wt of gas

(17.53)

2. D  etermine discharge temperature, T2, using adiabatic temperature rise Eq. 17.62. Use k values for gas or mixture or calculate them by Eq. 17.4. 3. Calculate the specific volume at discharge condition, v2, using Eq. 17.52. 4. Determine inlet volume, V1. a. Calculate volumetric efficiency from ideal equation:

E ′v = 1 − Vpc′ [(P2 /P1 )1/k − 1] = 1 − Vpc′ ( v 1 /v 2 − 1), fraction



(17.54)

Note that this requires or assumes that compressor cylinder clearance Vpc′ be established. For studies, it may be assumed and the effects calculated. Values range from 5% to 35% clearance on actual cylinders. Special designs are used for smaller or larger values.

Compression Equipment  585 130

BHP/MMCFD, BRAKE HORSEPOWER PER MILLION CUBIC FEET PER DAY AT 14.4 & SUCTION TEMPERATURE

120

110

K

=

1.4

1.3

100

1.2

1.1

90

1.0

80 NOTE: MECHANICAL EFFICIENCY OF COMPRESSOR CYLINDER = 95%

70 4.0

4.2

4.4

4.6

4.8 5.0 5.2 COMPRESSION RATIO, R

5.4

5.6

5.8

6.0

Figure 17.21C  Brake horsepower required to deliver 1 million ft3 of gas per day, part 3 of 3 (used by permission: Cooper-Cameron Corporation. All rights reserved).

b. Calculate inlet volume.



V1 = (PD)( E ′v )

(17.55)

5. D  etermine pseudo compression exponent, k , to reflect the actual shape of compression and re-­ expansion curves.

586  Petroleum Refining Design and Applications Handbook Volume 2

P1 v 1k ′ = P2 v 2k ′

(17.56)

 k′  144 bhp =  P V [(P / P )( k ′−1)/k − 1](L o )(FL )  k ′ − 1  1 1 2 1 33, 000

(17.57)

6. Calculate horsepower required:



Another method to account for compressibility is given by Boteler [26]. c. Approximate Actual Brake Horsepower, Bhp, From Estimating Curves. Many process applications do not require the detailed evaluation of all factors affecting the actual horsepower requirements. A convenient and yet reasonably accurate calculation can be made using Figures 17.21A–C. Note that for low ratios of compression, a correction factor is to be multiplied by the curve reading as shown in Figure 17.21A. A mechanical cylinder efficiency of 95% is included. The curves use the ratio of heat capacities, k. The horsepower per stage may be calculated.



bhp = [bhp/(MMCFD)] (C/106)



(delivered to compressor crank shaft)



or, bhp = (PD) EvP1 (bhp/MMCFD)(10-4)

(17.58)

(17.59)

where Bhp/MMCFD = brake horsepower required to handle 1 × 106 ft3 of gas per day, measured at 14.4 psia and suction temperature to cylinder, from Figure 17.21, including correction.      C = capacity of gas to be compressed, ft3/day, referenced to base conditions of 14.4 psia and suction temperature. Note that corrections for compressibility are not to be included unless the suction temperature at 14.4 psia requires such a correction, assuming most gases require no compressibility correction for pressures as low as 14.4 psia, the reference pressure. When used to approximate overall bhp for a multistage unit, the calculated results will be high due to the reduction in horsepower obtained from interstage cooling. For best results with these curves, evaluate total compression horsepower as the sum of the individual stages (see Figure 17.17A). The effect of compressibility has been omitted from these curves; however, if it is known to be appreciable, use the more exact calculation methods listed previously. An approximation can be made by multiplying the bhp from the curves by the Z factor at the actual stage inlet conditions. If Z is less than 1.0, it should be neglected for this approximation, and only values greater than 1.0 should be considered.

Multistage Multistage horsepower is the sum of the horsepower requirements of the individual cylinders on the compressor unit. Actual bhp:



= 0.0043664 FL k/(k − 1) {P1V1[(Pi1/P1)(k−1)/k − 1]Lo1



+ Pi1Vi1[(Pi2/Pi1)(k−1)/k − 1]Lo2 +

....PiiVii[(Pf/Pi1)(k−1)/ k – 1]Lof } where Pi

= interstage pressure, psia

(17.60)

Compression Equipment  587 Pf 1,2…i Lo1, Lo2…Lof V1

= final, or last-stage discharge pressure, psia = successive interstage designations = loss factors designated by cylinder stages = intake volume including effect of compressibility when applicable

Total bhp/stage and per multistage compressor assembly may be approximated using Figure 17.21. Corrections for compressibility (Z) may be incorporated as described for the single-stage cylinder, handling this on a per-cylinder basis.

Bhp Actually Consumed by Cylinders This horsepower is convenient to calculate when a known cylinder(s) exists on a compressor and when its performance is to be studied.



bhp = [(PD)(Ev)](P1)(bhp/MMCFD)(10-4)

(17.61)

Actual capacity handled = (PD) (Ev) (100), cfm, measured at suction conditions to the cylinder where (PD) (Ev) = ft3 per min (cfm) a cylinder must handle, measured at suction pressure and temperature to the cylinder. (PD) = compressor cylinder piston displacement in ft3/min (cfm). These values can be calculated from known cylinder data or obtained from the respective compressor manufacturer for the specific cylinder in question, operating at the designated rpm. Ev = Ev = volumetric efficiency from Figures 17.18A–F. Note that actual capacity at 14.4 psia and suction temperature = (PD) (Ev) (P1) (100). Therefore, the bhp value given previously is in the correct units for the curves of Figure 17.21.

Temperature Rise—Adiabatic The relation between the suction and discharge temperatures of a gas during any single compression step is



T2 = T1 (P2 /P1 )( k −1)/k = T1R (ck −1)/k

(17.62)

where T1 = initially suction temperature to cylinder, °Rankine = (460 + °F) T2 = discharge temperature from cylinder, °Rankine = (460 + °F) Rc = ratio of cylinder compression Figure 17.22 presents a convenient solution to this relation. The value of R (ck −1)/k read from the chart times the absolute suction temperature gives the discharge temperature T2. Thus,

T2 = T1 (value from graph, Figure 17.22) Temperature Rise—Polytropic Note that for reciprocating compressor work, values of “n” may be used as “k” up to 1.4. “n” represents the polytropic coefficient that is related to “k” by (n − 1)/n = (k − 1)/[(k) (Ep)], where (Ep) is the polytropic efficiency. Cylinder temperature rise is an important consideration, not only at the exit or discharge of the gases from the cylinder, but often for temperature-sensitive gas/mixtures. The temperature calculated or projected inside the cylinder

588  Petroleum Refining Design and Applications Handbook Volume 2

T2/T1 for Compression T2/T1 for Expansion

1.2 3.4 1.1 3.2

1.0 1.0

3.0

1.2

1.4

2.8

2.6 2.4

1.3 3.6

2.2

1.4 3.8

es

4.0

nV a lu

4.2

For Adiabatic Temperature Rise: T2/T1 = (P2/P1)(k-1)/k Read Chart as Values of “k” Parameter. For Polytropic Process: Exponent = n (n–1)/n = (k–1)/(kep) ep = Polytropic Efficiency 3.0 2.6 2.2 2.0 1.8 1.6 1.5 1.4 1.3 1.2 1.1

nV alu es

4.4

3.0

4.6

1.6 2.0

2.8 2.6

1.8

2.4

1.7

2.2

1.6

2.0

1.5 1.4

1.8

1.3

1.6

1.2

1.4

1.15 1.1

1.2

1.05 1.0

1

2

3 4 5 6 7 8 R = P2/P1 for Compression P1/P2 for Expansion

9

10

Figure 17.22  Compression temperature rise (used by permission: Rice, W. T., Chemical Engineering, April 1950, © McGraw-Hill, Inc., All rights reserved).

as compression proceeds must be calculated or measured to guard against too high a temperature developing during the compression process. Some gases such as chlorine, fluorine, bromine acetylene (and acetylene compounds), ethylene, and others must be carefully evaluated. If temperature rise is too high, conditions can lead to internal fires (actually consuming the metal of the compressor cylinder/liner) and explosions. Also for some gases/mixtures, polymerization can occur in the cylinder and, thereby, change the entire performance of the unit, as the cylinders and valves are not designed to handle polymers that are no longer gases.

Altitude Conversion Because all compressors do not operate at sea level pressure conditions, it is important to use the proper absolute pressure at the particular locality. Figure 17.23 is useful for converting altitude to pressure.

Compression Equipment  589

Example 17.2: Single-Stage Compression A compressor is to be installed at a location 2000 ft above sea level. It will handle a gas mixture with “k” = 1.25 at 5 psig suctions and discharge at 50 psig. Suction temperature is 90°F. The gas capacity is to be 5,250,000 SCFD measured at 14.7 psia and 60°F. Determine horsepower requirements and discharge temperature.

Solution 1. Calculate the altitude conversion (Figure 17.23)



Atmospheric pressure at 2000 ft = 13.68 psia 2. Ratio of compression,

Rc =



50 + 13.68 = 3.41 5 + 13.68

This is satisfactory for single-stage operation if temperature does not limit. 3. Discharge temperature (adiabatic rise)

T2 = T1R (ck −1)k = (90 + 460)(3.41)(1.25−1)/1.25



T2 = (550)(1.278) = 702.9°R T2 = 702.9 − 460 = 242.9°F

This temperature is safe.

4. H  orsepower, bhp/MMCFD = 74.1 (at Rc = 3.41, k = 1.25, from Figure 17.21B). Note that these curves are for 14.4 psia and suction temperature; therefore, to this basis:

10,000

30

Barometer, Inches of Mercury 26 24 22

28

20

18

et

M er cu re ry , lb ./s q. in .

su

m os

ro m

0

At

2,000

ph er ic

er , In

4,000

Pr es

ch

es

of

6,000

Ba

Altitude Above Sea Level

8,000

15

14

13

12

Atmospheric Pressure, lb./sq.in.

Figure 17.23  Barometric and atmospheric pressure at altitudes.

11

10

590  Petroleum Refining Design and Applications Handbook Volume 2

 14.7   460 + 90  Capacity = 5, 250, 000   14.4   460 + 60  = 5, 670, 000 CFD at 14.4 psia and 90°F





 Capacity  BHP required = ( bhp/MMCFD)   (106 ) 



 5, 670, 000  = (74.1) = 420 bhp  106 



5. Compressor cylinders, Cylinder or cylinders volume must provide



(PD)(E v ) =



(17.63)

If the suction to a stage does not exceed 10 psig, use [31].

(PD)(E v ) =

( bhp) × 104 ( bhp MMCFD)(P1 )

( bhp) × 104 ( bhp MMCFD)(P1 − 0.5)

(17.64)

Note: Use the compression ratio calculated by

R c2 =



P2 (P1 − 0.5)

(17.65)

This equation is to be used only for this step in the evaluation of volumetric efficiency and should not be used for any other factor in the performance evaluation. Due to valve and other losses being a significant portion in low suction pressure (less than 10 psig) cylinder performance, this can result in reduced performance if not corrected as noted. Then, Rc2 = corrected compression ratio



50 psia + 13.68 psia (5 − 0.5) + 13.68 = 3.5 =



Reading chart Figure 17.18C, Ev = 84.5 at assumed 7% cylinder clearance. Required Piston displacement (PD)

                 =

bhp × 104 (0.845)( bhp/MMCFD)(18.68 − 0.5)

Compression Equipment  591

Required: (E v )(PD) =



(420)(104 ) = 3,118 cfm (or , cfm) (74.1)(18.18)

Because the manufacturer is the only firm qualified to design the actual cylinder, no further details will be presented here. Note that this is the horsepower available to the cylinders. It includes a 95% mechanical efficiency incorporated into the bhp/MMCFD curves. The rating of a gas engine must be such that its delivered horsepower is at least 420 hp, or if an electric motor drive is used, the mechanical losses of the intermediate frame (about 5%) must be added to arrive at the required motor shaft horsepower.

Example 17.3: Two-Stage Compression A natural gas compressor is required to handle 4 million SCFD (measured at 14.7 psia and 60°F) from a suction condition of 0 psig and 70°F to a discharge of 140 psig. The altitude at the location is 3000 ft. The cooling water for any interstage cooling is at 80°F for 95% of the peak summer months. Determine the horsepower requirements allowing 5 psi pressure drop through the intercooler. Solution 1. C  ompression ratio At 3000 ft, atmospheric pressure = 13.14 psia (Figure 17.23)

P1 = 0 + 13.14 = 13.14 psia

Pf = 140 + 13.14 = 153.14 psia Rc =



153.14 = 11.65 13.14

This indicates a two-stage compression because Rc is greater than 5 or 6. Under some designs and for some capacities (not this) it can be satisfactorily handled in a single stage.



Approximate Rc per stage = 11.65 = 3.414 a. First stage: (allowing for one-half pressure drop handled by first stage)

P1 = 13.14 psia Pi1 = (3.41)(13.14) +



5 psia = 44.9 + 2.5 = 47.4 2

Rc = 3.61 b. Second stage:



Pi1 = 44.9 −

5 psia = 42.4 2

Pf2’ = 153.14 

Rc = 3.61

592  Petroleum Refining Design and Applications Handbook Volume 2 2. Discharge temperature first stage

   Ti1 = T1R (ck-1)/k

“k” for natural gas = 1.26

Ti1 = (70 + 460)(3.61)(1.26–1)/1.26 = (530)(1.305) Ti1 = 691°R Ti1 = 691° − 460° = 231°F

Showing the use of Figure 17.22,

     Rc = 3.61, k = 1.26

Read T2/T1 = 1.30



Then, T2   = (1.30)(530) = 689°R

T2

= 689 − 460 = 229°F

This is usually as closed as needed. 3. Discharge temperature second stage Because the cooling water temperature is low enough to allow good cooling, cool the gas to 95°F. This will be the suction temperature to the second-stage cylinder.

Tf 2 = Ti′1R (ck −1)/k = (95 + 460)(3.61)(1.26−1)/1.26 Tf 2 = (555)(1.303) = 723°R



Tf 2 = 263°F



4. Horsepower First stage from Figure 17.21B. Bhp/MMCFD = 78.0 at Rc = 3.61 and k = 1.26 (Reference to 14.4 psia and suction temperature 70°F.) Suction volume @ 14.4 psia and 70°F,

 14.7   460 + 70  = 4 , 000, 000  = 4 ,162, 000 CFD  14.4   460 + 60 





Using Figure 17.21B,



 suction volume capacity  bhp = bhp/MMCFD    106



bhp = (78.0)(4,162,000/106) = 324.6 horsepower

Compression Equipment  593

Second stage,

bhp/MMCFD = 78.0 at Rc = 3.61 and k = 1.26 (Refer to 14.4 psia and 95°F.) Suction volume @ 14.4 psia and 95°F,

 14.7   460 + 95      = 4 , 000, 000  = 4 , 358, 000 CFD  14.4   460 + 60 



bhp = (78.0)(4,358,000/106) = 339.9 horsepower



Total bhp = 324.6 + 339.9 = 664.5 hp This is the horsepower consumed by the cylinders and does not contain any losses in transmitting the power from the driver to the point of use, such as belts or gears. It does contain 95% mechanical efficiency for the cylinder itself. 5. Cylinder Selection The general steps in cylinder selection will be outlined. However, actual selection can be accomplished only by referring to a specific manufacturer’s piston displacement and the volumetric efficiency is a function of the compression ratio and “k” value of gas (both independent of cylinder) and the % clearance, a function of cylinder design.

a.

[(Pd )(E v )] =

bhp(104 ) ( bhp/MMCFD)(P1 − 0.5)*

*Use 0.5 only when suction pressure less than 10 psig, and the Rc used for Ev selection must be corrected accordingly [25].

For a solution, use 325 bhp for first stage. However, it is quite likely that either a 660 bhp (overloaded) or a 750 hp driver may be available as “standard.” The available hp for the first stage is based on 750 hp.

 325  First stage =  (750) = 366 hp available  666 

 340  Second stage =  (750) = 382 hp available  666  Total = 748 hp



Using these, the first-stage cylinder capacity is



(366)(104 ) Required [(PD)(E v )] = = 3, 600 cfm (78.0)(13.14 − 0.5) Usually this would be handled in two parallel cylinders.



Each cylinder, [(PD)(Ev)] =

3, 600 = 1, 800 cfm 2

594  Petroleum Refining Design and Applications Handbook Volume 2 Next select a type or class, diameter and PD of a cylinder that will meet the required volume and pressure conditions. This must be done with the manufacturers’ tables. No. Cyl

Diam.

Class of Type

% Clearance

PD

Ev

[(PD) (Ev)]

2

*

*

*

*

*

**

*Manufacturer table values **Calculated based on Cylinder

The calculated [(PD)(Ev)] should be equal to or greater than the required value of 1,800 cfm (in this example). Second stage:

(384 )(104 ) Required[(PD)(E v )] = = 1,170 cfm (78.0)(42.2)



For this stage also select a cylinder and check that its [(PD)(Ev)] is equal to or greater than the 1170 cfm. b. if the actual [(PD)(Ev)] is larger than the required, the actual horsepower loading with the cylinders selected must be calculated to be certain that the total cylinder load does not exceed the allowable horsepower operating rating of the driver.

17.10 Hydrogen Use in the Refinery Hydrogen has placed an essential role in converting poor-quality crude oil into modern-day products and to comply with strict environmental mandates. Although these heavy crudes are cheaper, refineries are faced with the additional expense of upgrading to sophisticated processes to refine them to the required standards and product slate that is meeting demand. The alternative is to pay a premium for the lighter crudes. This choice has impacted many refineries that were originally built to process light and sweet crudes and have had to shut down because they could not fund the technology upgrade required to process heavier crudes. The cost of hydrogen is part of the premium that the refiners must pay to process cheaper crudes economically. The challenge is made more complex by the fact that no two refineries are the same, and the naturally-occurring hydrocarbon distribution in crude does not always match customer demand. Various additional processing steps are required to re-adjust the molecules, reshape them and remove the contaminants to ensure the refinery products meet the requirements for the market as well as environmental performance. Hydrogen allows refineries to comply with the latest product specifications and environmental requirements for fuel production being mandated by market and governments and therefore, to reduce the carbon footprints of their facilities. While lighter sweet crudes require fewer processing, the heavier sour crudes contain higher levels of sulfur, other contaminants and fractions. Processing them usually starts with the same distillation process as for the sweet crudes to produce intermediate products; however, additional steps are required. This involves hydrotreating as one such process to remove sulfur, a downstream stream pollutant and other undesirable compounds, such as unsaturated hydrocarbons and nitrogen from the process stream as described in volume 1. Hydrogen is added to the hydrocarbon stream over a bed of catalyst that contains molybdenum with nickel or cobalt at intermediate temperature, pressure and other operating conditions. This process causes sulfur compounds to react with hydrogen to form hydrogen sulfide (H2S) while nitrogen compounds form ammonia (NH3). Aromatics (CnH2n−6, where n = 6, 7……) and olefins (CnH2n, where n = 2, 3, 4, …) are saturated by the hydrogen and lighter products are

Compression Equipment  595 created. The final product of the hydrotreating process is typically the original feedstock free of sulfur and other contaminants. The hydrocracking process is a much more severe operation to produce lighter molecules with higher value for diesel, aviation and petrol fuel. Heavy gas oils, heavy residues, or similar boiling-range heavy distillates react with hydrogen in the presence of a catalyst at high temperature and pressure. The heavy feedstocks are converted (cracked) into lighter distillates, e.g., naphtha, kerosene and diesel or base stock for lubricants. The hydrocracker unit is the top hydrogen consumer in the refinery. Hydrogen is the key source of the hydrocracking to reduce the product boiling range appreciably by converting the majority of the feed to lower boiling products. Hydrogen enables hydrotreating reactions in the hydrocracking process; the final fractionated products are free of sulfur and other contaminants. Other refinery processes such as isomerization, alkylation, and tail gas treatment also consume small amounts of hydrogen. A typical cost of a refinery expansion in the order of US$1 billion, with hydrogen supply representing about 10% of this investment. Therefore, the decision concerning the optimum way to utilize this hydrogen becomes a critical one. In many cases, refinery operators see the investment into hydrogen supply as a defensive outlay required to remain competitive in the market. Hydrogen is required in large volumes 10–200,000 Nm3/h on a refinery, but is also needed for various applications at varying scales of supply. An essential decision confronting operators is the supply method and there are three options for large-scale hydrogen supply [106]. Hydrogen can also be used on a smaller scale in the refinery that is less than 1000 Nm3/h. In these instances hydrogen can be purchased and stored on site in a liquefied form and further vaporized to be used as gaseous hydrogen. Other forms of supply involved a hydrogen tube trailer delivered by a third party supplier that it is hooked to the back of a truck or “bundle” delivery that requires a “bundle” of 12 or 15 cylinders being delivered to the refinery site. Typical bundle supply is used to support hydrogen needs during start-up and possibly an on-site pilot plant that requires research and development (R &D) activity, such as experiments into hydrogenation studies [106].

17.10.1 IsoTherming Technology for Kerosene, Vacuum Gas Oil, and Diesel Hydroprocessing Liquid stream hydroprocessing technology allowed refiners to attain fast-changing kerosene, vacuum gas oil and diesel sulfur specifications and process a wide variety of feedstocks. Hydroprocessing involves chemically treating a petroleum stream with hydrogen in the presence of a catalyst at elevated temperatures and pressures. The units allow refiners to improve product quality, comply with government regulations, and increase profitability by converting low valued streams into high margin and high-quality products. A conventional trickle bed technology as discussed in volume 1 depends on near perfect feedstock distribution throughout the catalyst bed to maximize reaction efficiency and to avoid overheating and coking. Additionally, the quench stages in a trickle bed reactor are used to manage temperature rise and require the injection of large volume of additional hydrogen using a compressor into the reactor (Figure 17.24). IsoTherming technology developed by DuPont as shown in Figure 17.25 has been applied in hydroprocessing of feedstocks that meets the increasing demand for cleaner-burning fuel while simultaneously maintain or increase profitability. Refiners need to increase their capacity and capabilities to produce more diesel and remove more sulfur while minimizing capital investment and operating costs. IsoTherming process provides the hydrogen necessary for hydroprocessing reactions using a liquid stream, rather than a recycle gas stream. Fresh reactor feed is saturated with hydrogen, and additional hydrogen can be added to the feed by a saturated product recycle stream using a recycle pump. This recycles a portion of the reactor product to the inlet to the reactor. This additional liquid volume is then saturated with hydrogen to ensure that sufficient levels of hydrogen are delivered to the reactor for required hydroprocessing chemical reactions. With an IsoTherming liquid full reactor, the catalyst is completely wetted. This draws the heat of reaction away from the catalyst surface and eliminates local hot spots that would otherwise promote coking and catalyst deactivation. All commercially operating IsoTherming gas oil hydrotreating units have experienced catalyst life in excess of four years, indicating that the technology can achieve lower catalyst deactivation rates than conventional trickle bed technology. Additionally, uniform liquid flow throughout the catalyst bed results in a uniform radial temperature profile and acts as a heat sink for exothermic chemical reactions. This results in a lower temperature rise across the

596  Petroleum Refining Design and Applications Handbook Volume 2 Make up hydrogen Make up compressor Feed

Recycle gas compressor

Amine scrubber

Reactor Condenser

Hot HP separator

Cold HP separator

Notes: · Two phase reactor. · Once through liquid. · Gas recycle. · Hydrogen diffuses into liquid as it is consumed in the catalyst bed. · Distribution critical.

To fractionation

Figure 17.24  Conventional Trickle Bed Process Flow Diagram. Make up compressor Make up hydrogen Feed

Off gas for recovery Reactor Condenser

Hot HP separator Notes: · Single phase reactor. · Once through hydrogen. · Liquid recycle. · All hydrogen in liquid phase within catalyst bed. · Distribution less critical.

Cold HP separator

Recycle pump

Figure 17.25  Iso Therming process flow diagram.

To fractionation

Compression Equipment  597 reactor and minimizes light ends generation. These different hydrogen addition options eliminate the need for a recycle gas compressor as shown in Figure 17.24. This process requires low head and high flow to pump high pressure and high-temperature liquid. Conventional pumps with mechanical seals do not offer the required safety and reliability; therefore, a canned motor pump is the only viable type for this process. Figure 17.26 shows the horizontal configuration of the recycle and the difference between the ordinary sealed and canned motor pump. Figure 17.27 illustrates the liquid flow path, and Figure 17.28 shows the top viewing of the recycle pump. This pump type is suitable because the high suction pressure and temperature make a conventional shaft sealing system unreliable, and the design guarantees there are no leaks in the seals. Figure 17.29 shows a photograph of recycle pump in IsoTherming hydroprocessing facility. IsoTherming technology employs a novel reactor system with a single liquid phase that uses hydrogen and catalyst more efficiently. Furthermore, all of the hydrogen required for the hydroprocessing chemical reactions is dissolved in a single liquid phase. This technology has successfully been used in kerosene, diesel hydrotreating, fluid catalytic cracking (FCC), pretreating, and mild hydrocracking. The technology has commercially processed a wide range of straight run and cracked feedstocks, including 100% light cycle oil (LCO), at capacities ranging from 2000 b/d to 78,500 b/d (13 m3/h to 520 m3/h) [169]. The major equipment differences between the two processes are [170]: IsoTherming

Conventional trickle bed

Hot high pressure separator

No

Yes

Cold high pressure separator

No

Yes

Recycle gas compressor

No

Yes

High pressure off gas cooler

No

Yes

Hot low pressure separator

Yes

No

High pressure amine contactor

No

Yes

Casing

Ordinary sealed Pump

Mechanical Seal Shaft

Eliminate Shaft Seal Casing Impeller

Leakage Coupling

Canned Motor Pump Casing Impeller

Frame

still two separate shafts

Stator Ass’y Bearing

Eliminate coupling DuPont Sustainable Solutions

Figure 17.26  Horizontal configuration of recycle pump [170].

Rotor with one piece shaft

598  Petroleum Refining Design and Applications Handbook Volume 2 High pressure amine pump

No

Yes

Stripper preheat exchangers

No

Yes

Reactor circulation pump

Yes

No

Feed/effluent heat exchange surface area

Low

High

Charge heater duty

Low

High

IsoTherming technology is inherently safer hydroprocessing since it eliminates the recycle gas compressor and associated treating equipment, and not only removes a large amount of high pressure equipment from the system, but also significantly reduces the hydrogen inventory in the process. Furthermore, the potential for runaway reaction

Process fluid out

CW out CW in

Process fluid in

Figure 17.27  Liquid flow path in IsoTherming ® Recycle pump [170].

Figure 17.28  Photograph: Top view of IsoTherming ® Recycle pump [170].

Positive Diesel flush

Compression Equipment  599

Figure 17.29  A photograph of IsoTherming recycle pump [170].

is significantly reduced and associated catalyst deactivation in the reactor. Figure 17.30 shows the operating data from a commercial unit that experienced a 4 power failure. A power failure with a conventional trickle bed unit would result in the process having to make up hydrogen and would trip the reactor charge pump and heater. To eliminate the potential for reactor temperature runaway and increased catalyst deactivation, operators would require depressurizing and draining the reactor in order to remove excess hydrogen and reactants. Once power is restored, the reactor bed unit would be refilled, reheated, and repressurized. This start-up process may take hours or days resulting in additional unit downtime. Figure 17.31 shows hydrogen consumption data during operation of the IsoTherming diesel hydrotreating unit, days 0–600, which varies from 60% to over 160% of the design hydrogen consumption. This flexibility enables the refiner to process a wide variety of feeds in order to maximize refinery profits [169]. Figure 17.32 shows a 3-D layout plot and Figure 17.33 shows a photography of IsoTherming hydroprocessing facility. The following advantages of IsoTherming are as follows [170]: Recycle of hydrogen accomplished by liquid recycle Elimination of recycle gas equipment in grassroots units Catalyst bed completely wetted

Reactor bed temperature, °C

1. A  ll catalyst sites utilized • More effective use of catalyst.

Prior to power outage, WABT was ~347°C.

~4 h ~5 h

Power restored.

Power outage occurs.

Following power outage, WABT was equal or less for the same feed composition; desulphurization rates were the same as before the power outage.

~308°C Time, h

Figure 17.30  Feed sulfur content data during commercial operation of the IsoTherming Diesel Hydrotreating unit (source: [169]).

600  Petroleum Refining Design and Applications Handbook Volume 2 Initial operation (one reactor)

200

Full operation (two reactors)

Chemical hydrogen consumption, % of design

180 160 140 120 100

Design value

80 60 40 20 0

0

100

200

300

400 500 600 Days on stream

700

800

900 1000

Figure 17.31  Chemical hydrogen consumption data during commercial operation of the IsoTherming Diesel Hydrotreating unit [169].

2. M  inimum hot spot formation • Decreased catalyst deactivation/coking/thermal cracking. • Decreased light end formation. • Increased liquid yield. 3. Heat of reaction absorbed by high liquid recycle rate • Adiabatic temperature rise less than conventional trickle bed technology. • Reactor temperature rise tends toward isothermal operation. • Lower heater firing rates in normal operation.

Figure 17.32  IsoTherming® 3-D layout plot [170].

Compression Equipment  601

Figure 17.33  A photograph of IsoTherming® hydroprocessing unit [170].

Flexibility in reactor shape • L/D and bed depth not dependent on two phase flow regime. • Reactor fabrication • Often, reactor diameter and wall thickness can be minimized to allow use of cold-rolled plate instead of forged plate. • Reactor design can be optimized for local fabricator capabilities and transportation logistics. • Projects not dependent on just a few fabricators worldwide. • Shorter reactor delivery time possible. • Can be optimized based on fabricator’s capabilities. Plot plan will be smaller than conventional trickle bed reactor Heat integration may lead to smaller carbon/green house gas footprint

A Case Study Using UniSim Design R460.1 Software for a Two-Stage Compression Case Study 1. Consider the compression of a stream of 4000 lb/h hydrogen at 75°F from a feed pressure of 14.7 psia to a target pressure of 100 psia with an adiabatic efficiency of 72% for both compressors. Noting that the compression ratio is greater than the recommended value of 4. It is apparent that two-stage compression is desired with the pressure of the first stage set at 38.34 psia, thus setting a compression ratio of 2.6 for each stage. Coolers are installed to reduce the compression stage effluent temperature to 280°F. Determine the duties of the compressors and the coolers.

Solution The following steps are used to simulate the two-stage compression and are described as follows (Case Study-TwoStage-Compression-akc.usc):

602  Petroleum Refining Design and Applications Handbook Volume 2 1.  Starting UniSim Design software 1. C  lick on the UniSim Design R460.1 icon or from the Windows icon at the bottom on the left-hand side of the screen and then from the Honeywell UniSim suite design folder. Then click on the UniSim Design R460.1 icon and the unSim Desktop appears as shown in Figure 17.34 2.  Creating a New Simulation To start a new case, select File/New/Case or press Crtl+N or click on the New Case. A simulation file is referred to as a “case”. This will open up the Simulation Basis Manager as shown in Figure 17.34B, which is where all of the components and their properties can be specified. Saving the Simulation Before proceeding any further, save the file in an appropriate location. Select File/Save As and select where to save the file. 3.  Adding Components to the Simulation The first step in establishing the simulation basis is to set the chemical components that will be present in the simulation as follows: 1. T  o add the components to the simulation, click on the Add button in the Simulation Basis Manager. 2. Clicking on Add will bring up the Component List View which is a list of all the components available in UniSim Design. 3. Select the desired components for the simulation. This can be done by searching through the list of components in one of three ways: a. Sim Name b. Full Name/Synonym c. Formula Select which match term you want of the three types by selecting the corresponding button above the list of components. Then type in the name of the component you are looking for. For example, typing Hydrogen for Sim

Figure 17.34A  UniSim Design Desktop (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  603

Figure 17.34B  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Name narrows the list down to a single component. If your search attempt does not yield the desired component, then either try another name or try searching under full name or formula (see Figures 17.34D and Figure 17.34E). 4. Once the desired component is located, either double click on the component or click  Add Pure to add it to the list of components for the simulation. 5. At the bottom of the components page, you can give your component list a name. 6. Once this is complete, simply close the window by clicking the red X at the upper right hand corner of the component list view, which will return you the simulation basis manager.

Figure 17.34C  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

604  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34D  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34E  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

4.  Selecting a Fluid Package Once the components are specified, you can now set the fluid package for your simulation. The fluid package is used to calculate the fluid/thermodynamic properties of the components and mixtures in the simulation (such as enthalpy, entropy, density, vapor-liquid equilibrium, etc.). Therefore, it is important that you select the correct fluid package since this forms the basis for the results returned by your simulation. 1. F  rom the simulation basis manager (Figure 17.34F), select the Fluid Pkgs tab. 2. Click the Add button to create a new fluid package as shown below.

Compression Equipment  605 3. F  rom the list of fluid packages, select the desired thermodynamic package. The list of available p ­ ackages can be narrowed by selecting a filter to the left of the list (such as EOSs, activity models, etc.). 4. Once the desired model has been located, select it by clicking on it once (no need to double click).  For  example, select Soave Redlich Kwong (SRK) property package for the simulation (Figure 17.34G). 5. You can give your fluid package a name at the bottom of the fluid package screen (e.g., the name in Figure 17.34G is Basis-1). 6. Once this is done, close the window by clicking on the red X on the upper right hand corner of the Fluid Packages window. Select Soave Redlich Kwong (SRK) from Property Package Selection and EOS button from Property Package Filter window. 5.  Select the Units for the Simulation From the Simulation Basis Manager and in the Tools menu, select Preferences from the drop down menu as shown in Figure 17.34H. From the Session Preferences windows, Click on Variable tab and in the variables window, select the units required from Variable Unit Set window as shown in Figure 17.34I. 6.  Enter Simulation Environment Click on the Enter Simulation Environment button to begin your simulation as shown in Figure 17.34J. Once you have specified the components and fluid package and entered the simulation environment, you will see the view as shown in Figure 17.34J. Here are few features of this simulation window. 1. U  niSim solves the flowsheet after each addition/change to the flowsheet. This feature can be disabled by clicking the Solver Holding button (the red light button) located in the tool bar (Figure 17.34J). If this button is selected, then UniSim will not solve the simulation and it will not provide any results. In order to allow UniSim to return results, the Solver Active button (the green light button) must be selected.

Figure 17.34F  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

606  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34G  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34H  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

2. U  niSim simulation is capable of solving for information both downstream and upstream. Therefore, it is very important to pay close attention to your flowsheet specification to ensure that you are not providing UniSim with conflicting information. Otherwise, you will get an error and the simulation will not solve.

Accidentally Closing the PFD If the red X on the PFD is accidentally clicked, to revert back to the PFD, go to Tools  PFDs, make sure Case is selected, then click View.

Compression Equipment  607

Figure 17.34I  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34J  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc., All rights reserved).

Object Palette On the right-hand side of Figure 17.34J, you will notice the vertical toolbar. This is known as the Object Palette. If for any reason this palette is not visible, go to the Flowsheet pulldown menu and select Palette or press F4 to display the palette. It is from this toolbar that you will add streams and unit operations to your simulation. 7.  Adding Material Streams Material Streams are used to transport the material components from process units in the simulation. A material stream can be added to the flowsheet in one of three ways:

608  Petroleum Refining Design and Applications Handbook Volume 2 1. C  lick on the blue arrow button on the Object Palette. 2. Select the “Flowsheet” menu and select “Add Stream” 3. Press F11. Using any of the above methods will create a new material stream (a blue arrow) on the flowsheet (Figure 17.34K). The UniSim default names the stream in increasing numerical order (i.e., the first stream created will be given the name “1”). This name can be modified at any time. 8.  Specifying Material Streams To enter the information about the material stream, double click on the stream to show the window shown in Figure 17.34L. It is within this window that the user specifies the details regarding the material stream. For material stream that will be used as an input, we need to specify four variables. With UniSim environment, input material stream always has four degree of freedoms. Meaning we need to supply four information in order to fulfill the requirement for UniSim to start the calculations. Note: The four variables required for input stream are composition, flow rate, and two from temperature, pressure, or vapor/phase fraction. From Figure 17.34L, you will see the warning yellow message bar at the bottom of the window indicating what information is needed (unknown compositions). Just follow what the message wants. For example, the first thing that you need to supply is compositions. In order to specify the composition of the stream, select the “Composition” option from this list to display the window in Figure 17.34M. It is within this window that the user specifies the composition of the stream. Note that only the components that you specified in the simulation basis manager will appear in this list. You can specify the composition in many different ways by clicking on the “Basis..” button. The UniSim default is mole fractions, however the user can also specify mass fractions, liquid volume fractions, or flows of each component. If the user is specifying in fractions, all fractions must add up to 1. Enter mole fraction of 1 in the H2 section to indicate 1 mole fraction of hydrogen. Next, the warning yellow message bar indicates that you need to specify the input temperature for this stream. In order to specify the temperature of the stream, select the “Conditions” option from this list to display the window in Figure 17.34N. It is within this window that the user specifies the temperature of the stream. By clicking on this

Figure 17.34K  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  609

Figure 17.34L  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc., All rights reserved).

Figure 17.34M  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

drop down arrow, the user can specify any unit for the corresponding value and UniSim will automatically convert the value to the default unit set. Enter the temperature of 75 in the temperature section to indicate the temperature of 75°F. Next, the yellow warning message bar indicates that you need specify the input pressure for this stream. In the same window, enter the pressure of 100 in the pressure section to indicate the pressure of 100 psia as shown in Figure 17.34N. Next, the last variable that requires to be specified is flow rate. For this, there are two options either to specify molar flow rate or mass flow rate. In the same window, enter the mass flow rate of 4000 in the mass flow rate section to indicate the flow rate of 4000 lb/h as shown in Figure 17.34N.

610  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34N  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Once all of the stream information has been entered, UniSim will calculate the remaining properties and data provided it has enough information from the rest of the flowsheet. Once a stream has enough information to be completely characterized, a green message bar appears at the bottom of the window within the stream input view indicating that everything is “OK” as shown in Figure 17.34M. Otherwise, the input window will have a yellow message bar at the bottom of the window indicating information is missing. 9.  Adding a Compressor There are several ways to add unit operations. To use the

Do this

Menu Bar

From the Flowsheet menu, select Add Operation or Press F12 The UnitOps view appears

Workbook

Open the Workbook and go the UnitsOps page, then click the Add UniOp button The UnitOps view appears

Object Palette

From the Flowsheet menu, select Open Object Palette, or press F4. Double click the icon of the operation you want to add

PFD/Object Palette

Using the right mouse button, drag “n” drop the icon from the Object Palette to the PFD

a. On the Connection tab, add a Compressor and enter the following information as shown in Figure 17.34O. In this cell..

Enter

Name

K-100

Feed

1

Outlet

2

Compression Equipment  611 Energy

C1_Duty

b. Switch to the Parameters page. Change the Adiabatic Efficiency to 72% as shown in Figure 17.34P. c. Go to the Worksheet tab. On the Conditions page, complete the page as shown in the Figure 17.34Q. The pressure for 2 will be 38.34 psia. The calculated outlet temperature is 314°F. d. From the Object Palette, click on the cooler icon and drag onto the PFD (Figure 17.34R). Double click on the icon and the Design page of the cooler appears. On the Connection tab, enter the following information as shown in Figure 17.34S. In this cell..

Enter

Name

E-100

Inlet

2

Outlet

3

Energy

E1_Duty

e. On the Parameters tab, enter the following information as shown in Figure 17.34T. In this cell..

Enter

Delta P

0.0

Duty

Empty

Delta T

Empty

f. Click on the Worksheet tab of the Design page. Enter the temperature of stream 3 as 280°F as shown in Figure 17.34U. UniSim calculates the material and energy balances and the bottom light on the Worksheet turns green with OK. Subsequently the streams on the PFD turns blue.

Figure 17.34O  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

612  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34P  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34Q  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  613

Figure 17.34R  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34S  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

614  Petroleum Refining Design and Applications Handbook Volume 2 g. Click on the Compressor icon in the Object Palette and connect to the outlet stream 3 of the cooler E-100. On the Connection tab, add a Compressor and enter the following information as shown in Figure 17.34V. In this cell..

Enter

Name

K-101

Inlet

3

Outlet

4

Energy

C2_Duty

h. Switch to the Parameters page. Change the Adiabatic Efficiency to 72% as shown in Figure 17.34W. i. Click on the Worksheet tab of the Design page. Enter the pressure of stream 4 as 100 psia as shown in Figure 17.34X. UniSim calculates the material and energy balances and the bottom light on the Worksheet turns green with OK. Subsequently the streams on the PFD turns blue. j. From the Object Palette, click on the cooler icon and drag onto the PFD next to the outlet stream 4 of compressor K-101. Double click on the icon and the Design page of the cooler appears. On the Connection tab, enter the following information as shown in Figure 17.34Y. In this cell..

Enter

Name

E-101

Inlet

4

Outlet

5

Energy

E2_Duty

Figure 17.34T  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  615

Figure 17.34U  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34V  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

616  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34W  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34X  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  617 k. On the Parameters tab, enter the following information as shown in Figure 17.34Z. In this cell..

Enter

Delta P

0.0

l. Click on the Worksheet tab of the Design page. Enter the temperature of stream 5 as 280°F as shown in Figure 17.34Z1. UniSim calculates the material and energy balances and the bottom light on the Worksheet turns green with OK. Subsequently the streams on the PFD turns blue. Figure 17.34Z2 shows the PFD of the simulation of the two-stage compression of the hydrogen stream and the duties of the compressors and coolers are: Equipment

Compressor

Duty hp

Btu/h

Cooler

Duty hp

Btu/h

1

K-100

1273

3.24 × 106

E−100

181.9

4.629 × 105

2

K-101

1760

4.48 × 106

E−101

1758

4.472 × 106

The UniSim Design software (Case Study-Two-Stage-Compression-akc.usc) provides Example of Case-Study 1.

Solution of Compression Problems Using Mollier Diagrams See Figures 17.35A–H. The solution of the work compression part of the compressor selection problem is quite accurate and easy when a pressure-enthalpy or Mollier diagram of the gas is available (see Figures 17.35A–H). The charts in the figure present the actual relationship of the gas properties under all conditions of the diagram and recognize the deviation from the ideal gas laws. In the range in which compressibility of the gas becomes significant, the use of the charts is most helpful and convenient. Because this information is not available for many gas mixtures, it is limited to those rather common or perhaps extremely important gases (or mixtures) for which this information has been prepared in chart form. The procedure is as follows:

Figure 17.34Y  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

618  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.34Z  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Figure 17.34Z1  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Compression Equipment  619

E-100 314.0 F Feed Temperature Product Temperature 280.0 F

1 Temperature 75.00 F Pressure 14.70 psia Molar Flow 1984 lbmole/hr

2

E-100

E-101 Feed Temperature 606.0 F Product Temperature 280.0 F

E1_Duty 3

4

E-101

1 K-100

C1_Duty

K-100

Speed 1273 Power Capacity (act feed vol flow) 1.292e+004 14.70 Feed Pressure 38.34 Product Pressure 314.0 Product Temperature

Dynamic Surge Flow Rate

K-101

rpm hp ACFM psia psia F ACFM

5 E2_Duty Temperature 280.0 F 5 Pressure 100.0 psia Molar Flow 1984 lbmole/hr

C2_Duty

K-101 rpm Speed 1760 hp Power 6855 ACFM Capacity (act feed vol flow) 38.34 psia Feed Pressure 100.0 psia Product Pressure 606.0 F Product Temperature Dynamic Surge Flow Rate ACFM

A Two-stage compression of Hydrogen stream

Figure 17.34Z2  (source: UniSim Design® R460.1. Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved).

Horsepower (17.66) Work = h2 − h1 h     = enthalpy of gas, Btu/lb 1,2   = states or conditions of system; 1 = suction, 2 = discharge.

Brake Horsepower, Required



bhp =

 lb Btu ft − lbf 778 1hp (M )(h 2 − h1 )(L o )(FL )  • • • 778 ft − lbf Btu 33, 000  min lb 33, 000  min

   

(17.67)

where M = gas flow rate, lb/min Lo = loss factor, Figure 17.19 FL = frame loss for motor-drive unit only = 1.05, omit if an integral unit as for gas or steam engine drive. 1 Btu = 778 ft-lbf 1 hp = 33,000 ft-lbf/min Figure 17.36 represents combined compression and mechanical efficiency of a compression unit. Therefore, for approximation



bhp = (778/33,000)(M)(h2 − h1)/ecm

(17.68)

Take ecm from Figure 17.36



bhp/MMCF/day =

ihp 0.95

0.95 = average overall compressor mechanical efficiency

(17.69)

40

20

20

15

20

15

Figure 17.35A  Mollier chart for properties of ammonia (used by permission: Dept. of Commerce, US Bureau of Standards).

500

6

8

20

40

1923

60

PROPERTIES OF AMMONIA

OF

MOLLIER CHART

5

6

8

10

25

25

BUREAU OF STANDARDS

30

30

10

40

300

40

20 800 HEAT CONTENT BTU. PER. LB.

800

50

80

80

50

60

60

DEPARTMENT OF COMMERCE

20

60

700

700

80

80

80

80

60

60

100

40

40

100

20

20

150

600

600

150

80

80

200

60

60

200

40

40

250

20

20

250

500

620  Petroleum Refining Design and Applications Handbook Volume 2

PRESSURE – LBS. PER. SQ. IN.

Compression Equipment  621

Figure 17.35B  Mollier diagram of the properties of ammonia. Note the different construction from Figure 17.35A (used by permission. Elliot® Company. All rights reserved).

622  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.35C  Mollier diagram of the properties of methane (used by permission. Elliot® Company. All rights reserved).

Compression Equipment  623

Figure 17.35D  Mollier diagram of the properties of ethane (used by permission. Elliot® Company. All rights reserved).

624  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.35E  Mollier diagram of the properties of ethylene. Note: ethylene chart of 60,000–100,000 psi, refer to a special chart that is available from some reciprocating compressor manufacturers (used by permission. Elliot® Company. All rights reserved).

Compression Equipment  625

Figure 17.35F  Mollier diagram of the properties of propylene (used by permission. Elliot® Company. All rights reserved).

626  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.35G  Mollier diagram of the properties of propane (used by permission. Elliot® Company. All rights reserved).

Compression Equipment  627

Figure 17.35H  Mollier diagram of the properties of iso-butane (used by permission. Elliot® Company. All rights reserved).

628  Petroleum Refining Design and Applications Handbook Volume 2 Cylinder sizes are determined in the same manner as in the same manner as in the example on two-stage compression. The cfm or [(PD)(Ev)] at suction conditions is determined and sizing continued. The volumetric efficiency may be expressed [25]:

v  E v = 100 − R c − %Cl  s − 1  va 



(17.70)

where vs = specific volume at suction conditions, ft3/lb va = specific volume at discharge conditions, ft3/lb %Cl = percent clearance = Vpc Compressor Indicated Horsepower, ihp



ihp/MMOF/day = 0.0432(h2 − h1)/ear

(17.71)



ihp = (MEP)(S)(Ap)(rmp)/33,000

(17.72)

where MEP = mean effective pressure during compression stroke, from indicator card, psi.

 k  ( k −1)/k R MEP = 14.73 E ′v  − 1 , Ref . (23)  k − 1   c



(17.73)

E ′v ear

   = use Eq. 17.54    = compression efficiency, the product of adiabatic and reversible efficiencies, which vary with the cylinder and valve design, piston speed, and fraction; values range from 0.70 to 0.88 usually. Ap     = cross-sectional area of cylinder, in.2; for double-acting cylinder, use Ap as (2Ap − Ar) S    = stroke, ft MMCF = 1,000,000 ft3 gas at 14.7 psia and 60°F rpm    = revolutions per minute of compressor

90

E cien cy, %

80

70

60

50

40

0

1

2

3 4 Compression Ratio

5

6

7

Figure 17.36  Combined compression and mechanical efficiency of reciprocating compressors (used by permission: Campbell, J. M. Oil and Gas Journal; and Ridgway, R. S. California Natural Gasoline Association Meeting, © 1945. All rights reserved).

Compression Equipment  629

Example 17.4: Horsepower Calculation Using Mollier Diagram An ammonia compressor is required to handle 25,000 lb per hour of gas at a suction condition of 105 psia and 70°F and is to discharge at 250 psia. 1.  Ratio of compression

Rc = 250/105 = 2.38 This should be a single-stage compression. 2.  Ammonia diagram, Figure 17.29A, 1. Locate the suction condition at 105 psia and 70°F    = 635 Btu/lb. 2. Read h1 = 2.9 ft3/lb. 3. Read v1 4. Follow the constant entropy (isentropic compression) line from the suction point until it intersects the discharge pressure line at 250 psia. 5. Here, read T2 = 183°F     = 688 Btu/lb. 6. Read h2 = 1.46 ft3/lb. 7. Read v2 3. Horsepower, Capacity = 25,000 lb/h = 417 lb/min Loss factor, Figure 17.19 At Rc    = 2.38 Read Lo = 1.275 Using Eq. 17.67, omit FL for an assumed gas engine drive.

778 (417 )(688 − 635)(1.275) 33, 000



bhp =



bhp = 664 4.  Cylinder selection a. Required [(PD)(Ev)]

= (lb/min)(v1) = (417)(2.9) = 1209 cfm



A single cylinder will do this capacity; however, usually it can be handled in two parallel cylinders for better balance. Then, per cylinder:



[(PD)(Ev)] = 1209/2 = 605 cfm b. Volumetric efficiency

%Ev = 100 − Rc − Vpc (v1/v2 − 1)                   = 100 − 2.38 − Vpc(2.9/1.46 − 1)

630  Petroleum Refining Design and Applications Handbook Volume 2



= 100 − 2.38 − Vpc (0.986)

%Ev  = 97.62 − 0.986Vpc The actual value depends on the cylinder chosen, in order to use the proper clearance fraction, Vpc. c. Select cylinders From the manufacturer’s specific compressor cylinder tables, select cylinders to give the required [(PD) (Ev)]; follow the two-stage compression example here. The final actual capacity depends upon this selection of cylinders. Just obtaining these cylinders does not settle the design. The manufacturer must verify that no cylinder interferences exist and that the rod loading intension and compression are satisfactory. This design detail is handled by the manufacturer. The final design agreement should be by the manufacturer, as they should be responsible for the final quoted performance of the unit.

Cylinder Unloading This section is adapted from reference [25] with permission. For each compressor unit with its associated individual cylinders, a fixed horsepower characteristic curve exists. The curve rises, peaks, and falls as the range of pressure ratio requirements varies. See Figure 17.17B. Many compressors are designed and operated at a fixed condition in a process or refrigeration cycle. However, at least an equal number is designed and operated over a varying, or at the initial selection unknown set of conditions of suction or discharge pressures. This situation is a reality and an economic necessity if the full horsepower of the compressor and driver combination are to be realized. To understand this, the factors affecting the horsepower characteristic must be evaluated.



bhp = [(PD) (Ev)] (P1) (bhp/MMCFD)/104

(17.61)

The variable available for control is the volumetric efficiency, Ev, which is a function of the compression ratio of the process requirement and the % clearance of the cylinder. The % clearance can be varied in the cylinder for capacity control by 1. H  ead-end unloaders 2. Double-deck valves with valve cap unloaders 3. Adjusting (screwing) the piston rod further into or out of the cross-head for some single-acting units. Figures 17.37 and 17.38 show the relative characteristic horsepower curves of a gas of k = 1.3 when 1. D  ischarge pressure is constant and suction pressure varies. 2. Suction pressure is constant and discharge pressure varies. Each compressor unit and condition has its own specific horsepower point or requirement for operation. However, the general characteristic shape will be about the same, and for a reasonable range of conditions, the general shape and effect of varying a particular condition can be relatively established even for gases of other k values. Of course, the curves can be recalculated and drawn for the particular gas under consideration. The peaks will be in about the same ratio. Note that Figures 17.37 and 17.38 were established using a bhp/MMCFD correction factor at a mean pressure of 200 psia for the lower compression ratios where this correction is required [25]. In sizing cylinders with several operating conditions, considering the use of these curves will allow the designer to select conditions that will nearly always keep the cylinder loaded to its peak. After the approximate (or actual) % clearance for the new or existing cylinder is established, reference to the curves will usually indicate the effect of the compression ratio change—that is, whether the horsepower will decrease or increase for a specific change. The curves indicate ranges of % clearance where the horsepower change is small for rather wide changes in Rc. Many problems

Compression Equipment  631 5% Clearance 10 15 20

Bhp

30

40

50 60

0

10

1.2

1.4

1.6

90

70

80

1.8 2.0 2.2 2.4 Compression Ratio, Rc

2.6

2.8

3.0

Figure 17.37  Horsepower characteristic curves for constant discharge pressure, k = 1.3 (used by permission: Cooper-Cameron Corporation).

ce ran lea C 5% 10 15

20

Bhp

30 40

50 60 70

10

0

1.2

1.4

1.6

90

1.8 2.0 2.2 2.4 Compression Ratio, Rc

80

2.6

2.8

3.0

Figure 17.38  Horsepower characteristic curves for constant suction pressure, k = 1.2 (used by permission: Cooper-Cameron Corporation).

will fall in this fortunate situation, where a single clearance will satisfy all expected conditions and no cylinder unloading, or where a minimum of unloading will be required. Unloading of cylinders becomes necessary when the operating conditions vary sufficiently to require changes in % clearance in order to keep the usual 3% overload and 5% underload horsepower condition on the cylinders. This is done by using unloading schemes that change the % clearance within the cylinder. Figure 17.39 illustrates unloading connections mounted on a cylinder. Figures 17.40A and 17.40B show two schemes for unloading double-acting cylinders, one scheme using clearance pockets in the cylinder and the other using pockets plus valve lifters. The limits of the operation will determine whether one or more unloaders are necessary for a particular cylinder.

632  Petroleum Refining Design and Applications Handbook Volume 2 Five-step unloading of constant speed compressors allows the compressing load to change and match the process demand of full, three-fourths, one-half, one-fourth, and no-load without changing process variables. Threestep unloading provides for full, one-half, and no-load operation of the compressor. No-load operation allows the machine to remain running but not pumping gas into the system. This is particularly useful for air service systems or refrigeration processes. For units using clearance pockets (Figure 17.40A), when one clearance valve is opened the volume of that pocket is added to the normal cylinder clearance volume. Depending upon the pocket volume, this may cut to one-half the amount of gas entering that end of the cylinder. Several pockets may be in each cylinder, depending upon volume needed and cylinder design. When all pockets (equal to cylinder volume) are open at one end of a cylinder, no gas enters. In the by-pass control scheme, Figure 17.40B, a pressure switch activates a solenoid valve when the system discharge pressure reaches a present value. Activating air then causes the unloaders to open the suction valve(s), Figure 17.39, allowing suction pressure to pass freely in and out of the cylinder. No compression takes place. The unloaders may be manually operated, although automatic operation usually gives better control. The clearance pockets may be of many different shapes and arrangements (see Figures 17.6B, 17.41A, and 17.41B). Fixed volume pockets allow for fixed or set volume changes while the variable volume designs allow for changes to suit a particular operating condition or balance and are of value when the cylinder must be used in several different alternating applications. Capacity can be accomplished in several ways as illustrated in Figures 17.39–17.42A. In Figure 17.42 (A) suction valve discs are depressed form their seats to allow the gas to flow freely in and out of the cylinder without compression [32]. Both unloader designs are of the external diaphragm type.

1

2

3

PRESSURE OPERATED SOLENOID VALVES

AIR TO OPERATE UNLOADERS

NO 2

NO 3

SUCTION

NO 1

AUTOMATIC UNLOADERS IN SUCTION

CLEARANCE CYLINDER TO COOLER

AUTOMATIC UNLOADER ON CLEARANCE POCKET NOTE: DISCHARGE VALVES (NO UNLOADERS) AND OUTLET GAS PASSAGE NOT SHOWN.

Figure 17.39  Automatic cylinder unloading (used by permission: Worthington Bul. L 679-BIA, © 1957. Dresser-Rand Company).

Compression Equipment  633 Full Load

3/4 Load

1/2 Load

1/4 Load

No Load

Clearance Valves (Air Operated)

Clearance Pockets

Suction Valves to Cylinder for Inlet Gas

Discharge Valves from Cylinder

Indicator Cards for Work done in Cylinder

No Work

Figure 17.40A  Five-step clearance pocket control for compressor unloading (used and adapted by permission: Ingersoll-Rand Company. All rights reserved).

Step 1

Closed

Suction Valves 2

C.E.

Step 4

Step 2

2

3

1

H.E.

3

1

Step 4

Step 5

Open 2

3

1

2

3

1

2

3

1

Clearance Pocket 100% Capacity

Note: Discharge Valves not Shown

75% Capacity (Clearance Pocket Open)

50% Capacity (Suction Valves Held Open Crank End Clearance Pocket not E ective)

25% Capacity (Suction Valves Held Open Head End Crank end on Clearcance Pocket)

0% Capacity (Suction Valves Held Open Both Ends)

Figure 17.40B  Five-step control for compressor unloading (used by permission: Worthington Bul. L-679 – BIA, © 1957. Dresser-Rand Company. All rights reserved).

Figure 17.41A  Fixed volume clearance pockets (used by permission: Worthington Bul. L679-BIA, © 1957. Dresser-Rand Co. All rights reserved).

634  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.41B  Variable volume clearance pockets (used by permission: Worthington Bul. L-679 BIA, © 1957. Dresser-Rand Co. All rights reserved).

Figure 17.42A  Pneumatically operated clearance bottle (used by permission: Bul. 9-201B, © 1991. Cooper-Cameron Corporation. All rights reserved).

Example 17.5: Compressor Unloading This section is adapted from reference [25] with permission. A compressor is required to handle 9,360,000 SCFD at a suction of 75 psig and 100°F with the discharge at 300 psig. It is anticipated that the suction pressure may rise to 100 psig after one year of operation. The k value of the gas is 1.3, and the unit will be installed at a coastal installation.

Compression Equipment  635 Determine the proper unit for this operation.

Solution 1. Ratio of compression:



Condition 1: R c =

300 + 14.7 = 3.51 75 + 14.7

Condition 2: R c =

300 + 14.7 = 2.74 100 + 14.7

Figure 17.37 shows that at Rc1 = 3.51, the horsepower conditions are lower than at Rc2 = 2.74. The horsepower will have to be provided for Rc2 condition, and must operate satisfactorily at Rc1. The 75 psig suction condition will determine the unloading. 2. Horsepower



At Rc1 = 3.51

bhp/MMCFD, Figure 17.21B = 77.3 Capacity at 14.4 psia and 100°F = 10,290,000 CFD, converted from given value at 14.7 psia and 60°F.

Total bhp = (77.3)



10, 290, 000 = 795 1, 000, 000

Use an 800 hp-rated unit. At Rc2 = 2.74, the required bhp is less than the preceding.

3. Compressor cylinders,



[(PD)(E v )] =

(800)(104 ) = 1, 154 cfm (77.3)(75 + 14.7 )

For two cylinders in parallel:

[(PD)(Ev)] each = 576.5 cfm

Using Cooper-Cameron cylinder information for this example:

No. cylinders Diameter % clearance PD Ev (calc.) [(PD)(Ev)

=2 = 14 in. = 11.1% = 731 = 0.784, using Eq. 17.45 = 573

4. U  nloading From the characteristic horsepower-% clearance curves, Figures 17.37 and 17.38, the maximum amount of unloading will be required when the suction pressure is at Condition 2100 psig. From the calculated horsepower for this point, the maximum amount of unloading required can be determined.   A performance curve, Figure 17.43 for this problem, will aid in determining the number of unloading steps.

636  Petroleum Refining Design and Applications Handbook Volume 2



By examining the curve for the initial compression with no unloaders, it shows that the horsepower requirement crosses the +3% overload line about one-third of the way through the suction pressure range. Figure 17.43 shows the effect of adding first one unloader and then a second one. The simplest way to handle this is a head-end unloader on each of the two parallel cylinders. Actual size of unloaders: Piston displacement (double acting cyl.)

= 731 cfm each

Piston displacement head end

= 374 cfm

Piston displacement crank end

= 357 cfm

Clearance (cylinder data)

= 11.1%

Total clearance volume = (0.111)(731)

= 81.14 cfm

Assuming equal distribution of clearance:



81.14/2 = 40.6 cfm





Head end % clearance =

40.6(100) = 10.86% 374

Crank end % clearance =

40.6(100) = 11.37% 357

The horsepower at suction pressure of 100 psig with no unloading:



bhp = [(PD)(Ev)] (P1)(bhp/MMCFD)(10−4)

Ev for Rc2 and 10.86% clearance, calculated = 0.845

One Unloader Operation No Unloaders Open

900

876 Hp at 100 psig Suction (a) 836

Bhp

850

802

795

750

p’ 80

Rated Hp of Driver –5% Under-rate Limit

738

75

Two Unloader Operation +3% Over-rate Limit

(b) 786

800

700

839

85

90

95

100

Suction, psig

Figure 17.43  Compressor cylinder performance curve for unloading conditions.

Compression Equipment  637 From Figure 17.21B, bhp/MMCFD for Rc2 = 62 Head-end bhp

= [(374)(0.845)] (114.7)(62)(10−4)

H.E., bhp

= 225 hp

Crank-end bhp

= [(357)(0.839)](114.7)(62)(10−4) = 213 hp

Total bhp/cylinder

= 438 hp

Total bhp for the two parallel cylinders: = (2)(438)

= 876 hp

bhp available

= 800

Excess bhp

= 76 hp for cylinders

Using a head-end unloader on each cylinder, the head-end horsepower should be reduced:



76/2 = 38 hp bhp on one head end less

= 225 = 38 =187 bhp

If each head-end is unloaded to the point of requiring only the 187 hp, the unit will be overloaded at the maximum point. The head-end Ev would have to be



Ev =

187(104 ) = 0.703 (374 )(62.0)(114.7 )

Substitute in the Ev relation Eq. 17.45,

(

)

%E ′v = 100 − R c − Vpc R 1c k − 1



(17.45)

where %Ev = volumetric efficiency Vpc = percent clearance Rc = compression ratio



70.3 = 100 − 2.75 − %Cl (2.751/1.3 − 1)



70.3 = 97.25 − %Cl (1.18)



%Cl = 26.95/1.18 = 22.84%, required Total head end % clearance required

= 22.84

Normal fixed head end clearance

= 10.85

Additional % clearance required in H.E.

= 11.99

638  Petroleum Refining Design and Applications Handbook Volume 2 in3 required in each head-end unloader valve:



unloader volume =

[(0.1199)(374 )](1728) = 258 in3 300 rpm

The performance curve of the unit can be completed as follows: a. C  alculate the horsepower at pressure P equal to value of the suction pressure where line “a” (the original no unloader curve) crosses the 3% overload. Note that curve “a” is not a straight line. b. For the new suction condition, calculate the new horsepower (82.4 psig) with one unloader on only one of the cylinders open. At this point, One cylinder: (no unloader open) PD PD(HE) PD(CE) HE %Cl CE % Cl

= 731 cfm = 374 cfm = 357 cfm = 40.6/374 = 10.86 % = 11.37%

(

)

1  300 + 14.7  1 HE , %E v = 100 −  − 10.86 3.24 .3 − 1 = 80.8%  82.4 + 14.7 



CE, Ev    = 80.8% (calculated)



HE, bhp = (374)(0.808)(97.1)(72.4)(10-4) = 212



CE, bhp  = (357)(0.808)(97.1)(72.4)(10−4) = 203



Total

= 212 + 203 = 415 bhp (point a, Figure 17.43)

Second cylinder: (one unloader open on head-end)



PD = same



HE %Cl = 22.84%



CE %Cl = 11.36% unchanged



 300 + 14.7  HE , %E v = 100 −  − 22.84(3.241/1.3 − 1)  82.4 + 14.7 



= 63.2%



CE, Ev = 80.8% HE, bhp

= 374(0.632)(97.1)(72.4)(10−4) = 166

CE, bhp

= 357(0.808)(97.1)(72.4)(10−4) = 204

Total bhp

= 370



At 82.4 pisa suction,



Total load = 415 + 370 = 785 hp (point b, Figure 17.43)



Compression Equipment  639 Another point on the curve at 100 psig suction, One cylinder no unloader, second cylinder with unloader: One cylinder (no unloader open),

 314.7  HE , %E v = 100 −  − 10.86(2.751/1.3 − 1)  100 + 14.7  = 84.5%





CE, %Ev. = 83.8% HE, bhp = (374)(0.845)(114.7)(62)(10−4)

= 225

CE, bhp = (357)(0.838)(114.7)(62)(10−4)

= 213

Total bhp

= 438

Second cylinder (unloader open on head-end), PD = same HE: Reading curve for 70.8% Ev at Rc = 2.75, %Cl = 22.1 CE: %Cl = 11.36% unchanged Reading curve: HE, Ev = 70.8% CE, Ev = 83.8% HE, bhp = (374)(0.708)(114.7)(62)(10–4)

= 188

CE, bhp = (357)(0.838)(114.7)(62)(10–4)

= 213

Total bhp

= 401

Total for both cylinders = 438 + 401 = 839 hp Now determine the operating line for the condition of both head end unloaders open, at two suction conditions: a. S uction = 82.4 psig The head end % clearance will be 22.1% because this is the condition with the unloader open on each cylinder.

Reading curve:

HE, Ev: @Rc = 3.24 and % Cl = 22.1, Ev = 64% CE, Ev: @Rc = 3.24 and % Cl = 11.36, Ev = 80% HE, bhp = (374)(0.64)(97.1)(72.4)(10−4)

= 168

CE, bhp = (357)(0.80)(97.1)(72.4)(10−4)

= 201

Total bhp

= 369 per cylinder

640  Petroleum Refining Design and Applications Handbook Volume 2 For two cylinders alike, bhp = 738 hp (Curve “c”) b. Suction = 100 psig HE, Ev: @Rc = 2.75 %Cl = 22.1, Ev = 71.3% CE, Ev: @Rc = 2.75 %Cl = 11.36, Ev = 83.8% HE, bhp = (374)(0.708)(114.7)(62)(10−4)

= 188

CE, bhp = (357)(0.838)(114.7)(62)(10−4)

= 213

Total bhp per cylinder

= 401

Total for two cylinders = 802 hp (Curve “c”)

Example 17.6: Effect of Compressibility at High Pressure A mixture of 3000 scfm, dry basis, (14.7 psia and 60°F), 60% methane and 40% nitrogen is to be compressed from 16 psig to 3500 psig. Suction temperature is 90°F. Intercoolers will use 85°F water cooling gas to 90°F, and the installation is essential at sea level. The gas is saturated with water vapor. Pressure drop of 5 psi is to be allowed for the interstage coolers. This problem involves the compressibility of the gas and its moisture content. These will be taken into account in the following design. 1. Ratio of compression

Rc =



3500 + 14.7 = 114.48 16 + 14.7

This must be broken down into stages:



For three-stage Rc = 3 114.48 = 4.86 uncorrected



For four-stage Rc = 4 114.48 = 3.27 uncorrected Although the 4.86 could be used, usually it will be preferable to go to the extra stage and have the lower ratio. For this solution, use four stages. The interstage pressure will be by trial balancing and assuming that one half the intercooler P or 5 psi is carried by each cylinder. First-stage suction:



16 + 14.7 = 30.7 psia First-stage discharge:



(30.7)(3.27) = 100.04 psia + 5/2 = 102.54

Rc1 = 3.34

Compression Equipment  641 Second-stage suction:



102.54 – 5.0 = 97.54 psia Second stage discharge:



(97.54) (3.27) = 318.96 + 5/2 = 321.46

Rc2   = 3.30 Third stage suction:



(321.46) – 5 = 316.5 pisa Third-stage discharge:



(316.5) (3.27) = 1035.0 + 5/2 = 1037.5

Rc3  = 3.28 Fourth-stage suction:



1037.5 − 5 = 1032.5 psia Fourth-stage discharge:



(1032.5) (3.27) = 3,376.0 psia



Rc4  = 3.27 Note that the first approximation for “Rc” was obtained from Eq. 17.41. This figure is not the exact compression ratio as it is difficult to calculate an exact ratio over such a wide range. The final Rc values calculated are close enough for process design calculation. 2. “k” value for the gas mixture:

Methane (CH4)

Nitrogen (N2)

Fraction, y

Mcp*

(y) (Mcp)

0.6

9.15

5.49

0.4

7.035

2.81

Total

8.30

*at 150°F from average data tables.



k = c p /c v =

8.30 = 1.315 (8.30 − 1.987 )

3. Moisture Vapor pressure of water at cylinder suction temperature of 90°F is 0.6982 psia.



Total pressure at suction = 30.7 psia for first stage Mol % of water in gas =

(0.6982)(100) = 2.275% 30.7

642  Petroleum Refining Design and Applications Handbook Volume 2 Average molecular weight (dry basis),



= (0.60)(16) + (0.40)(28)



= 9.6 + 11.2 = 20.8 Total mol of gas on dry basis (60°F and 14.7 psia)



PV = nRT ft 3 1  PV (14.7 )(3000)  psia = . . n=   RT (10.73)(520)  psia . ft 3 min o R   mol. o R    = 7.904 mol/min

Mol of water vapor



=

(7.904 )(0.02275) = 0.1840 (1 − 0.02275)

Total mol to first stage = 7.904 + 0.1840 = 8.088 mol/min Second-stage suction: 0.6982(100) = 0.716% 97.54 (7.904 )(0.00716) Mol water vapor = = 0.0570 (1 − 0.00716)



Mol % water in gas =



Total mol to second stage = 7.904 + 0.0570 = 7.961 mol/min Third-stage suction: 0.6982(100) = 0.221% 316.5 (7.904 )(0.00221) Mol water vapor = = 0.0175 (1 − 0.00221)



Mol % water in gas =



Total mol to third stage = 7.904 + 0.0175 = 7.9215 mol/min Fourth stage: Neglect effect of water vapor, as it will be considerable less than for the third stage. Compressibility:

Tc-methane = 343°R, N2 = 227°R Pc-CH4 = 673 psia, Pc − N2 = 492 psia Pseudo-critical temperature:

Tc = (0.60)(343) + (0.40)(227) = 296.6°R

Compression Equipment  643 Pseudo-critical pressure:

Pc = (0.60)(673) + (0.40)(492) = 600.6 psia

Reduced temperature at suction:

460 + 90 = 1.85 296.6

Reduced pressure:

*Compressibility, Z

1st stage: 30.7/600.6 = 0.5111

0.998 ≅ 1.00

2nd stage: 97.54/600.6 = 0.1624

0.992

3rd stage: 316.5/600.6 = 0.5270

0.976

4th stage: 1,032.5/600.6 = 1.7191

0.925

*From compressibility charts, Figure 17.14.

4. Brake horsepower (Figure 17.21):



 capacity  bhp = ( bhp/MMCFD) (Z )  106  First stage, Rc = 3.34; from Figure 17.21B, at Rc = 3.34 and k = 1.315, BHP/MMCFD = 74.5 Volume/capacity = 8.088 mol/min (gas + water vapor, see previous paragraph 3)

bhp = (74.5) (8.088)(359 ft 3 /mol @14.7 psia and 32°F) × (60 min /h × 24 h /day )

× (14.7/14.14 )

 (460 + 90) (1.00)/106  (460 + 32) 

 8.088   14.7   460 + 90   = (74.5)  6  (1440)(359) (1.00)  14.4   460 + 32    10  = 355.5 bhp



Second stage, Rc = 3.30; from Figure 17.21B, at Rc = 3.30 and k = 1.315, BHP/MMCFD = 73.5



 7.9671   14.7   460 + 90   bhp = (73.5)  (1440)(359)  (0.992)  6  14.4   460 + 32    10  = 342.4 bhp



Third stage, Rc = 3.28; from Figure 17.21B, at Rc = 3.28 and k = 1.315, BHP/MMCFD = 73.3



 7.9215   14.7   460 + 90   bhp = (73.3)  ( 1440 )( 359 )     (0.976)  6 14.4   460 + 35    10  = 334.3 bhp



644  Petroleum Refining Design and Applications Handbook Volume 2 Fourth state, Rc = 3.27 (see note paragraph 3 previous); from Figure 17.21B, at Rc = 3.27 and k = 1.315, BHP/ MMCFD = 73.1

 7.91   14.7   460 + 90   bhp = (73.1)  6  (1440)(359) (0.925)  14.4   460 + 32    10  = 315.3 bhp





Total bhp = 355.5 + 342.4 + 334.3 + 315.3 = 1347.5, use 1350 *Some manufacturers will not use a Z less than 1.0 in horsepower calculations. The cylinders can be selected in the same manner as previously presented, remembering that it is the volume at the suction to the cylinder that is important. Therefore, the effect of the compressibility and moisture content must be reflected in the suction volume being considered. Be careful not to apply these factors twice, when calculating actual [(PD) (Ev)] from the horsepower equation. If driven by an electric motor through a crankshaft frame, the horsepower at the output of the motor would have to be



(1358) (1.05) = 1428 hp If driven by a gas engine, the rated hp of the engine must be at least 1358 hp.

Air Compressor Selection Air compressors are required for many services. Figures 17.44A–C and 17.45, Table 17.6, and performance curves are presented to indicated the type of units that are suitable. Other styles, sizes, and types are available, and their omission does not indicate a lack of suitability. Also see Schaefer [33] and Skrotzki [34]. Table 17.6A shows compressed air applications for various compressor types. When establishing intake capacity for air compressors, the moisture content of the air must be taken into account. It is not always necessary or desirable to assume that the air is saturated; however, this is the maximum condition with respect to water content. Intake air temperature must be selected with some recognition of maximum-minimumnormal for summer conditions. Figure 17.46 is convenient for reading air conditions. Figure 17.47(1), part 1a illustrates [34] the stage variation of the two-stage intercooled compressor on the T-S diagram (reproduced from Skrotzki [34] by permission):

A

C F

Figure 17.44A  Single-stage horizontal compressor (used by permission: Dresser-Rand Company).

E

D

B

Compression Equipment  645 B A O

J

N

C

K M

L

Figure 17.44B  Two-stage angle-type vertical compressor (used by permission: Dresser-Rand Company).

A

B

C

Figure 17.44C  Two-stage horizontal duplex compressor (used by permission: Dresser-Rand Company).

“For points 2–3, there is constant entropy (S) compression for a one pound of air from P2 to P3. From points 3–5 the air cools at constant pressure, and gives up heat, Q to the intercooler. From points 5–6 the air is compressed at constant S to the final pressure P6. Note that point T5 = point T2 for constant temperature. For minimum work T6 = T3. Then the heat, Q equals the Work, WL of Figure 17.47B. Figure 17.49 is convenient for estimating the moisture condensed from an airstream, as well as establishing the remaining water vapor in the gas-air. For the three stages with two intercooling stages, Figure 17.47(2), the work of compression would be reduced more than for single or two stages. Thus the work can be decreased by increasing the number of stages and the intercooling between them. As discussed earlier the minimum total work to the gases can be achieved by the cube root of the total overall ratio of compression. Referring to Figure 17.47(2) b, WH = W1 = WL. Then for the optimum conditions, heat, Q given up in the low pressure intercooler equals WL work input to the L-P (low-pressure) cylinder, and Q2 equals W1 work input to I-P (intermediate pressure) cylinder. If there were an aftercooler following the H-P cylinder to cool the air to B in Figure 17.47 (a), the area under the curve 9-B would equal the work of the H-P (high pressure) cylinder WH.” Figure 17.48 illustrates work associated with three types of compression: (1) constant temperature, (2) polytropic, and (3) constant entropy. Figure 17.47(1)(a) shows the arrangement of a single-stage compressor with an aftercooler and a receiver. Note that the receiver acts as a reservoir for high pressure air to operate the engine, which may have a varying demand. The compressor runs at a steady rate. Figure 17.49 provides a quick method of determining the change in moisture content of air.

646  Petroleum Refining Design and Applications Handbook Volume 2 Sea Level S = Single Stage, Horizontal A = Two Stage, Angle Type Vertical D = Two Stage, Horizontal Duplex Note: Actual Capacity is at Inlet Suction Conditions. Actual Capacity = (PD)(Ev, fraction) Actual Capacity, cfm 100

Single Stage, Ev, % (7, 9, 11, 13" Stroke)

S

40

Two Stage, Ev, % D A

80

(5" Stroke) A D

70 Bhp/100 cfm Actual (5" Stroke) Bhp/100 cfm Actual (7, 9, 11, 13" Stroke)

60 S

0

20

10

Single Stage

S 50

Two Stage, Bhp/100 cfm Actual

30 Bhp

S

90

Ev, %

Bhp 100 cfm factor

100 cfm Actual Capacity

Total Bhp req’d =

10

20

30

40

50

60 70 80 90 100 110 Discharge Pressure, psig

120

130 140

0 150

Figure 17.45  Typical air compressor performance, single and two-stage (adapted and used by permission: Dresser-Rand Company).

Win is the power into the compressor shaft. Heat is rejected at Qr and Qri. Wout is the work output of the system. Qa is heat introduced into the system. Then for the energy balance (reproduced by permission from Skrotzki, B. G. A., Power, p. 92, Jan. 1958):

Win + Qa = Wout + Qr

(17.74)

The receiver acts as a storage reservoir for the h-p air; it keeps a reserve of air for the engine whose demand may vary widely. This allows the compressor to run at a steadier pace.

Energy flow Energy flow into and out of the system takes two forms, work and heat. The prime energy source, Figure 17.48A, for the system is Win to the compressor shaft. The compressor cylinder and receiver-aftercooler usually reject heat to the atmosphere, Qr. The engine produces the major product of the system, Wout. Usually the engine and atmosphere introduce heat into the “closed” system as Qa. According to the first law of thermodynamics, these four energy flows must always be in balance. For steady air flow through the system:



Energy in = energy out

Win + Qa = Wout + Qr Constant-T system Figures 17.48B and 17.48C show the events for an ideal constant-T compressor and engine with an atmospheric temperature, Ta. Win, the gray area, raises air pressure from 1 to 2 while Qre, shaded area, flows through the compressor-

Compression Equipment  647 100

90

80 40

40 50 60

Relative Humidity, % 60 50 40

70

20

70

Dew Point Temp., °F.

80

80

ul

yB

10 11

18 19 20

1.00

0.02 0.99

1.05

re, p si

12 13 14 15 14 16 .7 17

1.06 1.07 1.08 1.09 Capacity Correction Factor, F.

0.03

Pres su

1.10

0.04 0.05 0.06 lb. of Moisture per lb. of Dry Air 0.98

a

25

0.01

1.04

30

1.03

35

1.02

40

1.01

45 50

60 70 80

90100 120 140 200

160

0.0

F.

° p.,

110

110

1.00

40

em bT

100

110

0 12

Dr

0

90

100

100

70 80

90

90

10 50

70

Dew Point Temperature, °F

30

60

50

0.97 Specific Gravity, Dry Air = 1.00

1.11

1.12

0.07

1.13 0.08

1.14

1.15 0.09

0.96

Figure 17.46  Air properties compression chart (used by permission: Rice, W. T., Report RP 383. Dresser-Rand Company; and Chemical Engineering. McGraw-Hill Inc. All rights reserved).

cylinder walls to the atmosphere. This system does not need an aftercooler. Air expands in the engine from 3 to 4 while it absorbs Qae from the atmosphere, hatched area, through the engine cylinder walls and produces shaft work Wout, hatched area. For reversible processes:

Win = Wout = Qae = Qre This assumes, of course, that no pressure drops are in the system.

Polytropic System Polytropic system (Figures 17.48D and 17.48E), gets nearer to the conditions of a practical system, with polytropic process having n = 1.2. The gray area Win compresses air from 1 to 2 while the air rejects heat Qrc to the atmosphere through the compressor cylinder walls. Qrc equals area 1-2-y-z in 4e. In the aftercooler-receiver, the air rejects heat Qri equal to gray area 2-3-w-y. In the engine, the air expands from 3 to 4 while absorbing heat Qae equal to area 3-4-x-w and produces work Wout, hatched area. Because the pressurized air draws on its internal energy to produce the work, its temperature drops below Ta, even though Qae enters the air during expansion. (In the constant-T cycle, Qae prevents the drop in temperature.) As the exhaust air returns through the atmosphere from engine to compressor, it absorbs heat Qaa, hatched area. The PV graph shows that work flow into the system Win is larger than work output Wout. The net cycle area for the system 1-2-3-4 measures the work lost by the system—external temperature irreversibilities cause this. All the

648  Petroleum Refining Design and Applications Handbook Volume 2 (a)

(a)

T

T 6

3 6

9 Ta

B

P6

5

B

P5

2 O

P2 D (b)

S P

(b)

O2

S B 9 A

W saved

W saved

WH S=C n = 1.4 = k

3

WI

1

0

0

V

(c)

5

WL

1

2

T=C n=1

3

4

WL

0

8

To = C n=1

5

S=C n = 1.4 = k

6

7 4

O1

P 10

WH

2

D

B 6 A

7

5

8

P6 P3 P2

P3

3

2

0

V Intercoolers

(c) Cooling water

Free air 1–2

3–4

4–5

Free air 1–2

H-P air 6–7

4–5

Intercooler

WL L-P cylinder 1

H-P air

3–4

9–10

6–7 7–8

WH H-P cylinder

Two-stage compression with intercooling cuts shaft work input, avoids too high a temperature of discharged air

WL L-P cylinder 2

WI I-P cylinder

WH H-P cylinder

Three-stage compression with two intercooling stages reduces work input more—used on higher-pressure air

Figure 17.47  Benefits of interstage cooling for air compression system (used by permission: Skrotzki, B. G. A. Power, p. 72, Jan 1958, © McGraw-Hill, Inc. All rights reserved).

Compression Equipment  649 Qrl

Qrc (a)

Qr = Qrc + Qrl

Compressor 2

Win Free air in

Engine

3

1

Wout

4 Air exhaust

Receiver and altercooler

Qoe Qo = Qoc + Qoe

Qoc (b)

(c) P

T To

P2 P1

2, 3

a

n = 1.0 2, 3

n = 1.0 Win = Wout

1.4

b O (d)

1.4

To Qce = Qrc

O

V

O

S

(e) T

P

P2

To 3

a

2

(Win – Wout) = Wlost

Wlost

n = 1.2

To

O

4

(f)

V

P

O (g)

W

X

Y

3

2 2

O

(Win – Wout) = Wlost To

1

3

4

4 O

S P2

P1

n = 1.4

n = 1.4 b

Z

T

To a

P1

Qrc = 1–2–y–z Qrl = 2–3–w–y Qce = 3–4–x–w

Qce

4 O

n = 1.2

3

1 b

2

V

Wlost

Qri

Qce

O

S

Simple compressed-air system could work on constant-temperature processes, b and c; or on polytropic processes, d and e; or on constant-entropy processes, f and g. As n rises above 1.0, work lost keeps growing quite rapidly

Figure 17.48  Work associated with three types of air compression (used by permission: Skrotzki, B. G. A. Power, p. 72, Jan 1958, © McGraw-Hill, Inc. All rights reserved).

650  Petroleum Refining Design and Applications Handbook Volume 2

1.2

1.58 2.13 2.25 3.76 4.91 6.14

POUNDS MOISTURE AT 0 LBS. GAGE

1.0

MOISTURE CONTENT OF SATURATED AIR AT VARIOUS TEMPERATURES AND PRESSURES

.9 .8 .7 13

.4 .3

60

5 °F 40 0°F 32 °F °F

.2 .1 0

0

20

40

80

70

°F

°F

60

10 0 90 °F °F

80

0°

F 0°

11

.5

F 0°

.6

12

POUNDS OF MOISTURE PER 1000 CU. FT. OF SATURATED FREE AIR OR GAS AT 147 LB. ABS. AND TEMP. SHOWN

1.1

F

100 120 140 160 180 200 220 240 260 280 300 320 PRESSURE – LBS. PER SQ. IN. GAGE

Figure Example: Saturated air at 80 at compressor intake (0 lbs.) contains 1.57 lbs. of moisture per 100 cu. ft. Compressed to 100 lbs. and cooled to 80° with 65° water the air contains only 0.20 lbs. per 1000 cu. ft. or 13% of the moisture originally taken into the compressor. The rest has been condensed in the intercooler (if used) and the aftercooler.

Moisture as precipitated by aftercoolers.

Figure 17.49  Moisture as precipitated by aftercoolers (used by permission: Bul. L-600-B9-4, No. 4 in a series. Dresser-Rand Company).

processes, however, have been considered as internally reversible. This contrasts with the engine cycles studied; for these, net area measured shaft work output, but for compressed-air systems, net area measures work lost. Remember, completely available energy, shaft work, runs compressed-air systems; higher-temperature heat runs engine cycles. To continue the analysis, from the circuit flow diagram:

Win + Qae + Qaa = Wout + Qrc + Qri

(17.75)

Win − Wout = Qrc + Qri − Qne − Qaa

(17.76)

From the PV graph,

Wlost = Win − Wout

(17.77)

Substituting from the energy flow balance:

Wlost = Qrc + Qri − Qae − Qaa

(17.78)

The last equation means that the net area 1-2-3-4 on the TS graph also measures the net work lost, even though this is in Btu rather than ft-lbf as on the PV graph.

Constant-S System Figures 17.48F and 17.48G use adiabatic compression and expansion (zero heat transfer). All heat added to the cycle comes from heating the engine exhaust by Qaa. The heat rejected from the cycle, Qri, leaves through the aftercooler. An

Compression Equipment  651 adiabatic expansion of the air in the engine causes a maximum temperature drop of the exhaust. An adiabatic compression causes a maximum temperature rise of the compressed air. These effects combine to cause the greatest work loss of any compressed-air system, when pressurized air must be cooled back to atmospheric temperature. The energy analysis parallels the one just made for the polytropic system. This shows that net areas on both PV and TS graphs measure the work lost. If the pressure parts of an adiabatic system can be thoroughly insulated to prevent loss of Qri and the aftercooler can be dispensed with, this would be an efficient energy transmitting system, with no work lost. The compressor would work along 1–2 in Figures 17.48F and 17.48G and the engine along 2–1. There would be no areas on the TS graph, and the two areas for compressor and engine would be equal on the PV graph.

Example 17.7: Use of Figure 17.35 Air Chart (©W. T. Rice) Assume that a plant air system requires 10,000 ft3/min of dry air measured at 14.7 psia and 60°F [35]. The air is required at 100 psia. Intake conditions are



Atmospheric pressure at location = 13.0 psia



Temperature = 84°F



Humidity = 90°F

Aftercooler: The water used can cool air to 75°F. The pressure at this point = 100 psia. Referring to Figure 17.46, follow the dashed line, starting at the left scale at a dry bulb temperature of 84°F. Follow up and to the right to the intersection with a vertical relative humidity of 90%; follow across to the intersection with an inlet pressure of 13.0 psia, and read vertically down:



Moisture capacity correction, F = 1.0412



lb water vapor/lb dry air = 0.026



Specific gravity of air-water vapor mixture = 0.985 At aftercooler conditions, the dry bulb equals the wet bulb temperature (air is saturated):



Wet bulb = dry bulb temperature = 75°F



Pressure = 100 psia



lb water/lb dry air = 0.003



Dry air capacity at inlet = 10,000(14.7/13)(544/520)



  = 11,820 cfm



Atmospheric air required = (1.0412)(11,820) = 12,310 cfm



Specific volume of moist air, vm



= (0.37)(T1)/(Sp. Gr.)(P1)



= (0.37 × 544)/(0.985 × 13)



= 15.72 ft3most air/lb Mass flow rate of moist air = 12,310/15.72 Mass flow rate of dry air = 783/(1.0412 × 0.985)

= 783 lb/min. = 763 lb/min

Mass flow rate of water vapor entering compressor = 20 lb/min

652  Petroleum Refining Design and Applications Handbook Volume 2 Leaving: Mass flow rate of water leaving in air from aftercooler = 763(0.003)   = 2.289 lb/min Mass flow rate of water condensed = 20.0 − 2.289 = 17.711 lb/min

Centrifugal Compressors The centrifugal compressor is well established for the compression of gases and vapors. It has proven its economy and uniqueness in many applications, particularly in which large volumes are handled at medium pressures. This compressor is particularly adaptable to steam turbine or other continuous speed change drivers, as the two principles of operation and control are quite compatible. It is also adaptable to the electric motor, gas engine, and gas turbine with each installation being specific to a particular problem or process. Installation as well as operating costs can be quite reasonable. Nissler [36] presents a rather complete review of centrifugal and axial compressors.

Mechanical Considerations A centrifugal compressor, Figures 17.50A–D, raises gas pressure by accelerating the gas as it flows radially out through the impeller and converting this velocity energy to pressure by passage through a diffuser section. The casing is stationary, and the wheels or impellers mounted on the shaft are rotated by the driver. The units are usually mounted horizontally with horizontal split case for low pressures and vertical split case (barrel design) for high pressures about 800 psi. In general configuration, the centrifugal compressor resembles a centrifugal pump. However, the significant difference in performance requirements lies in the compressibility of the gas. A dynamical analogy between these two items could be used to simplify the fundamental principles involved. Both receive mechanical energy from an outside source, and by rotating impellers they transform this into pressure energy in the fluid being pumped. The centrifugal force depends on the peripheral speed of the impeller and the density of the fluid. The action of a centrifugal compressor depends more on the density and fluid characteristics of the material handled than does a reciprocating compressor. The peripheral speed and, hence, the head developed per stage is limited by the acoustic velocity, as it is believed that the peripheral speed should not exceed the speed of sound in the fluid being handled. Significant features of centrifugal compressor are as follows.

Case Centrifugal compressor cases are classified as horizontally split or vertically split (Figures 17.51A–C). The 5th Edition, April, 1988, API Standard 617 refers to the horizontally split style as “Axial Split” and vertically split units as “Radial Split.” The first terminology is more standard than that of the API-617 [60]. Figure 17.51D illustrates one flow arrangement for back-to-back internal flow, with the following advantages: • Elimination of potential thrust bearing failure due to failure of the large diameter balance piston labyrinth. (Balanced piston labyrinths in straight-through designs are required to withstand differential pressures as high as 5000 psi). • Reduction of recirculation losses in the compressor since (1) the pressure exposed to the seals balanced to the compressor suction is an intermediate pressure as opposed to full discharge pressure on straight-through flow designs; (2) the seals that are balanced to suction are a much smaller diameter (and, therefore, have much smaller flow clearance area) than balance piston labyrinths on straightthrough flow designs [60]. The outer shell or case is usually split for assembly along a horizontal centerline, Figures 17.50A–D, for units operating with pressures up to 800 psi. The single-stage centrifugal blower operates as a centrifugal compressor but

Compression Equipment  653 1

9

2

7

8

13

4

5 1 6 3

11

4

12 3

10

The horizontally split units are accessible for inspection and cleaning. Removal of the upper half of the case permits access to the rotor, diaphragms, guide vanes, and other internal parts. Journal and thrust bearing and seals, however, can be examined or removed without disturbing the upper half of the case. 1. Integral bearing construction. 2. Double-wall cooled diaphragms reduce horsepower, allow higher compression ratios, maximum safety, avoid gas contamination, and ensure accurate process temperature control. No water connections are between halves. These are not used for all applications. 3. Bearing chambers are cast integral with case for freedom from alignment problems. 4. Isolation chamber eliminates external gas leakage to atmosphere. 5. Single- or double-thrust bearings accurately locate shaft. Balancing drum removes all but residual thrust. 6. Shaft extension permits tandem drive of five or more cases by a single driver. 7. Labyrinth seals are replaceable. 8. Return bends. Good hydraulic efficiency. 9. Fixed or adjustable inlet guide vanes for economy. 10. Interstage drains permit removal of condensate duting operation or draining of “washdown” fluid. 11. Integral studs for maximum tightness. 12. Horizontally split design 13. Maximum compression ratio, maximum stages per unit.

Figure 17.50A  Internal construction features of multistage centrifugal compressor (used by permission: Dresser-Rand Company).

is limited to a case pressure of about 275–375 psig and 2 to 3.5 ratios of compression (Figure 17.52). Above this pressure ratio, the multistage split case units, Figure 17.51E, become more economic and have better mechanical design features for applications as high as 5000 psi. For the usual situation the gas inlet and outlet connections can be arranged at either the top or bottom and sometimes in horizontal locations. This should be arranged to suit the piping of the installation and also to avoid liquid holdup or drainage into the unit. The manufacturer’s mounting instructions regarding expansion, etc., should be carefully followed, as the nozzle connections on the case are not designed to carry piping loads. Materials of construction depend on the metallurgical requirements and pressure of the gas being compressed but usually the more “popular” materials include cast iron, cast steel, alloy steel, or forged steel (high pressure). Figure 17.53 illustrates the extent of damage internally when materials of construction are not resistant to possible effects of internal corrosion.

654  Petroleum Refining Design and Applications Handbook Volume 2 1

3

2

4

15

5

14 6

4

T

6

8 9

13 7

10

12

11 1. Casing 2. Diaphragm 3. Impeller 4. Interstage seals 5. Shaft end seals 6. Bearing housing 7. Load bearing 8. Oil baffles

9. Balance piston 10. Shaft 11. Keyway 12. Inlet nozzle 13. Double-acting thrust bearing 14. Retaining nuts 15. Shaft sleeves

Figure 17.50B  Construction features of multistage centrifugal compressor (used by permission: © A. C. Compressor Corporation. All rights reserved).

2 1 4 5

7

6

1. Radial vaned impellers are investment cast to ensure precise contours and dynamically balanced for a smooth operation. 2. Discharge may be purchased in horizontal or vertical position for installation ease. 3. Choice of vaned or vaneless diffusers, providing optimum curve shape and high efficiencies. 4. Rugged integral speed increasing gearbox with precision ground gearing ensures smooth operation, with high mechanical efficiency and low noise levels. 5. Removable high-speed shaft assembly contains the bearing and seals and is easily removed to facilitate servicing. 6. Splash and pressurized lubrication systems are available. They are completely self-contained and require no external connections. Cooling is available. (Pressure lubrication is required on some models.) 7. Generous clearances of .035 in. (.889 mm) elminate performance deterioration caused by wear and the need for mechanical adjustment.

3

Figure 17.50C  Single-stage gas compressor with integrally geared drive shaft (used by permission: Bul. 1.10., Jan. 1994. © Sunstrand Compressor, Sunstrand Fluid Handling).

Compression Equipment  655

B

E

Simplicity means reliability The design of thr PAP Plus compressor is simplicity itself. The only moving pads in the compressor are a gear and the rooms. Because PAP Plus is a centrifugal compressor there are no lubricated parts in the stream. Thus, PAP Plus compressors are designed to deliver off free air Optimized air flow Ambient air enters the first stage through the inlet

C

A

D

(A) where it is accelerated by the first imprifier (B) a diffuser converts this velocity in pressure before the air enters thr serial casing (C) the healed air is structed through interstage piping to the intercooler (D) the cooled air the flows through thr account impeller. (E) diffuser and scroll casing before being discharged into the altercooler and on to that plant air system.

Figure 17.50D  Oil-free air compressor with two impellers, Elliot Company. “Plant Air Package®, Plus” gear driven (used by permission: Bul. P-51B Elliot® Company).

Diaphragms and Diffusers The diaphragms shown in the assembly, Figures 17.50A and 17.50B, may be uncooled or liquid cooled. Figures 17.54A and 17.54B represent the two halves of uncooled diaphragms for horizontally split unit. These are inserted in matching casing locating grooves and locked in each casing half. The diaphragms are the separation walls between the successive impeller stages. The diaphragms form the diffuser walls and the return passages for guiding the gas to the inlet of the next higher stage impeller. The design of these diaphragms has an important bearing in the operational characteristics of the machine. The spaces between faces are carefully proportioned to match the impeller and to minimize pressure losses (see Figure 17.54A). Diffuser vanes are used to decelerate a high velocity flow to create a pressure rise. They are usually at the periphery of each impeller. The variable diffuser vane system may be controlled manually by a handwheel or automatically by a hydraulic or air-operated positioner [37] (see Figure 17.55B). The return channels (passages) contain vanes that direct and evenly distribute the flow of gas into the guide vanes of the next impeller. Most diaphragms for horizontally split compressors are of the uncooled open diffuser type. Water-cooled diaphragms are used to cool the discharge temperature of the gas stream, but this cooling may be limited in degree and not provide a total cooling in place of a final external cooler [38]. Water-cooled diaphragms, Figures 17.55A and 17.50A, are used to cool the surfaces of the metal passages and, thereby, reduce the temperature of the gas as it passes through the machine. This will often allow for higher ratios of compression in the same machine case. For some designs, these are used on high-pressure or high compression-ratio applications, for hazardous gases, or temperature sensitive materials. Careful installation of the water-cooled diaphragms prevents contamination of the process gas by the cooling fluid (usually water). Despite the care and attention to proper sealing, assembly, etc., the chance of a coolant leak into the gas or vice versa always exists. Extreme

656  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.51A  Centrifugal compressor case types. These usually apply to multistage units rather than single stage units. See Figures 17.50A, B (Note: API Standards 617, April 1988, Par. 2.2.8) (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

MAIN INLET

1ST DISCHARGE

2ND INLET

FINAL DISCHARGE

5M COMPOUND COMPRESSOR Flow Path Arrangements: COMPOUND FLOW For many high ratio applications, the capability to extract the total gas flow for intercooling is desirable to minimize gas temperature and power requirements. In many applications, compounding can reduce the number of compressor casings required. The flow path is the same as two “straight-through” compressors in series. that is, the total flow enters at the main inlet of the compressors and is totally discharged at the first discharge connection, is cooled or otherwise reconditioned, and re-enters the compressor at the second inlet connection and is totally discharged at the final discharge nozzle.

Figure 17.51B  Flow path arrangements: Compound flow (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

attention to mechanical details at this point is important. Some gaseous dry-chlorine compressors use a noncorrosive chlorinated solvent as the diaphragm coolant to guarantee no water in the system. Internal liquid injection into the diffuser passage is used in a few applications for direct contact cooling. The quantity and quality of the liquid must be carefully controlled. Materials of fabrication again vary with the nature of the gas being compressed but are usually low alloy steel, such as AISI 4140 or 4340, heat treated at 1100°F to

Compression Equipment  657 5M WITH SIDESTREAMS

S.S. OUT INLET

S.S. IN DISCHARGE

S.S. IN

Flow Path Arrangements SIDESTREAM FLOW For refrigeration cycles and other process requirements, the capability to admit or discharge gas at intermediate pressure levels is required. Compressors can be provided with sidestreams with minimum flow disturbance and provide effective mixing of the main sidestream gas flows. In the cross-section shown, examples of both incoming” and “outgoing” sidestreams are shown. Flow enters the main inlet and is compressed through one impeller to an intermediate pressure level at which point an incoming sidestream flow is mixed flow is compressed to a higher pressure ahead of the next impeller. The total mixed flow is compressed to a higher pressure level through an outgoing sidestream to satisfy a process requirement. The remainder of the flow is compressed through one impeller, is mixed with an incoming sidestream, compressed through two stages, and exits through the final discharge.

Figure 17.51C  Flow path arrangements: Sidestream flow (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

Rockwell hardness C-26 to 30, AISI Type 410 stainless steel, precipitation hardening stainless such as Armco 17-4Ph or 15-5-PH, type 304 or 316 austenitic stainless for very low tip speed impellers, or Monel® K-500 for halogen gases. Aluminum is used for certain applications [39]. Hydrogen embrittlement can cause severe failure problems with many metals when hydrogen is present in the gas mixture.

Labyrinth Seals The seal of the rotating shaft to the diaphragm is usually a labyrinth (Figure 17.56). With proper design, these can effectively seal the pressure of one stage or wheel from the other in the case. Extreme care is needed in selecting the labyrinth material, as it must be soft enough not to score the shaft, yet maintain its shape and be resistant to any corrosive materials. The seal is effected when the knife edges of the labyrinth shape themselves on the shaft. Care in the initial shaft rotation and the cleanliness of the parts are important for an effective seal.

Impeller Wheels The common wheel types are (1) backward and (2) radial. The types of construction of wheels are milled, fabricated, welded, and cast (see Figures 17.57A–H). The fabricated or built-up wheels are machined from high-strength alloy steel forgings. These may be riveted or welded for assembly. The one-piece wheels are usually smaller than the built-up wheels and are milled from a solid forging. The cast and welded wheels are usually only made above a certain diameter due to fabrication problems in smaller diameters. Each manufacturer has its own recommendations for each application. Figure 17.57 illustrates the key styles of wheels for use on the rotating shafts of multistage centrifugal, single-stage compressors and axial flow compressors. The flow-handling capability of a specific impeller geometry is described by the “flow coefficient,”

658  Petroleum Refining Design and Applications Handbook Volume 2 BACK TO BACK IMPELLER ARRANGEMENT

INLET DISCHARGE FINAL DISCHARGE SECOND INLET

FIRST INLET

FIRST DISCHARGE

SEALS

RADIAL BEARINGS

THRUST BEARINGS

HIGH PRESSURE COMPRESSOR CROSS SECTION This arrangement internally utilizes back-to-back impeller arrangements providing for thrust balance without the use of a balance piston. This type of configuration has added advantages in high pressure, high case lift (pressure rise across the case) applications.

Figure 17.51D  Flow path arrangements: Back-to-Back flow (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

Interstage Gas Seals Balance Drum or Piston Equalizing Line Bearing Impeller Shaft Coupling here to Driver Thrust Bearing Assembly Shaft Sleeve Shaft Sleeve Seal Forged Steel Impeller Casing End Cover

Barrel Casing

Diaphragm

Figure 17.51E  Barrel type compressor section, horizontal mounting (used by permission: Cooper-Cameron Corporation).

Compression Equipment  659

16

15

22

14 13 12 11 10 9 8 7

21

20 OIL LEVEL

6 5 4 3

19 G

IN

AR

E TB US E R C TH RIFI O

TO OIL RESERVOIR

18

2 17 1

1 Base 2 Oil rings (if required for start-up) 3 Thrust bearing 4 Oil guard–coupling end 5 Shaft 6 Coupling 7 Thrust bearing housing 8 Bearing sleeve–coupling end 9 Thermometer–coupling end 10 Thermometer–impeller end 11 Bearing housing

12 Bearing sleeve—impeller end 13 Oil guard—impeller end 14 Packing box 15 Backplate 16 Gasket 17 Casing 18 Gasket 19 Inlet connection 20 Inlet guide vanes 21 Impeller 22 Inspection hole plug

Figure 17.52  Single impeller centrifugal blower (used by permission: Elliot® Company).

660  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.53  Results of internal chlorine gas fire and extensive corrosion in centrifugal compressor. Middle section of shaft with extensive damage to loss of center compression wheels. Note that ferric chloride is present.

Interstage diaphragms, usually made of cast iron are horizontally split and inserted in matching casing locating grooves and locked in each casing half. The diaphragms form the diffuser walls and the return passages for guiding the air or gas to the inlet of the next impeller. Diffusion action is accomplished by radially increasing the flow area of the diffuser and thus converting velocity head into pressure head. The diffuser passages are parallelsided and do not include vanes. However, return passages do contain vanes to redirect the flow to the next impeller. Diaphragms are designed to accommodate the interstage labyrinth seals at the shaft and impeller cover disc. The seals prevent interstage recirculation.

Figure 17.54A  Multistage centrifugal compressor uncooled diaphragms for horizontally split casings (used by permission: A. C. Compressor Corporation).

Compression Equipment  661

diaphragms Suction, intermediate and discharge diaphragms create the gas flow path within the stationary components. The suction diaphragm conveys the gas into the eye of the first impeller and can be fitted with adjustable guide vanes to alter the inlet flow angle. Intermediate diaphragms perform the dual function of forming the diffuser passage (where gas velocity is transformed into pressure) and the return passage to channel gas to the eye of the next impeller. The discharge diaphragm forms the diffuser for the last impeller as well as the discharge volute. The diaphragms are usually horizontally-split. In the MCL series the upper halves are fixed to

the casing to facilitate rotor inspection. The diaphragms are made of castiron, special cast iron, steel or stainless steel. Easily removable labyrinth seals are installed on the diaphragms at impeller shrouds, to prevent return flow from discharge to suction and on the shaft sleeves to eliminate interstage leakage.

Figure 17.54B  Diaphragms (used by permission: Bul. PROM 526/15/95, © S.pA. Nuovo Pignone, Florence, Italy: New York; Los Angeles; and Houston. All rights reserved).



Φ = Q/(π/4)(D2υ)

(17.79)

where Q = gas flow rate, ft3/s D = impeller diameter, ft υ = tip speed of impeller, ft/s, expressed by: υ = (π/720)D N, ft/s N = shaft speed, rpm (revolutions per minute) D′ = impeller diameter, in.



or, Φ = 3.056 Q/(D2)(υ)

(17.80)



or, Φ = 700 Q/D N

(17.81)

3

662  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.55A  Water-cooled diaphragm (used by permission: Dresser-Rand Company).

1 variable inlet vanes 2 impeller 3 suction head 4 volute casing 5 suction shroud 6 diffuser vanes 7 casing diaphragm 8 diffuser diaphragm

Figure 17.55B  Single stage centrifugal compressor with variable inlet vanes, diaphragm, and diffuser vanes illustrated (used by permission: Worthington Power and Fluids, V. 8, No. 2, Winter, 1965. © Dresser-Rand Company. All rights reserved).

Compression Equipment  663

The simplest and most commonly used seal is the labyrinth. It is composed of a series of restrictive rings or a grooved sleeve with the edges of the rings or grooves machined to knife edges. The single labyrinth is used when there is a low sealing pressure differential. Interlocking labyrinths are used for higher differentials. Labyrinth seals operate by breaking down the pressure differential across the labyrinth.

Figure 17.56  Labyrinth seals (used by permission: Dresser-Rand Company). Cover Disc Attached by Rivets which Pass Through the Milled Vanes

Figure 17.57A  Impeller with milled vanes on solid disc forging (used by permission: Dresser-Rand Company).

664  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.57B  A special design riveted wheel, used only on small wheels where welding is impractical (used by permission: Elliot® Company).

Then: Q =

(Q ) (D2 υ) (3.056)

(17.82)

This represents the linear effect of tip speed and the square of impeller size on the flow of a specific impeller. Referring to Figure 17.57, very low flow coefficients for a specific type of centrifugal or axial flow machine can cause excessive wall friction or leakage losses, and very high-flow coefficients tend to be subject to turbulence losses due to insufficient flow guiding [40]. The values of flow coefficient (Φ) for high-pressure barrel compressors at the inlet are not to exceed 0.07 for high tensile strength steel impellers [41]. For multistage (not barrel) compressors with flow coefficients. • at high Φ values, gas velocities in the impeller flow channels increase and lead to a fall in efficiency with increasing Φ. • at low Φ values, efficiency falls rapidly due to the increasing influence of the shroud leakage loss and of unavoidable friction loss in the boundary layer of the impeller disks and blades. • where the Φ values of the impeller are kept in the 0.03–0.09 range, the efficiency of a multistage compressor can be improved. Another design parameter is impeller tip speed as this relates to pressure difference by changing fluid velocities. Tip speed is defined previously [40]. The head output of a compressor is a square function of the tip speed alone [40] and is independent of the size of the machine itself. The volume flow is determined by both the rotor/wheel diameter and the tip speed for a given blade and flow geometry. For example, if a compressor is scaled to twice its size and the tip speed remains constant, it will produce the same head but will handle four times the flow of the original size compressor. It can be seen that wheel/impeller/rotor tip speed rather than rotating shaft speed (rpm) is a most useful design tool [40]. The “pressure coefficient” or “head coefficient” is dimensionless and is expressed:



ψ = Hadg/υ2, or = μ

where ψ = μ= pressure or head coefficient   g = acceleration due to gravity, ft/s2   υ = rotor/wheel/impeller tip speed, ft/s

(17.83)

Compression Equipment  665

The impellers for centrifugal compressors are assemblies consisting of three parts: the hub disc, the blades, and the cover disc. The hub and cover disc are machined from single-piece forgings of an alloy steel suitable for the application of the compressor. Blades are machined from forged steel plates of identical material. Each forging is checked with either sonic or X-ray machines to detect flaws or inclusions. The hub disc forms the back portion of the impeller. The hub disc has the proper design to form one-half of the inlet nozzle of the impeller and carries the blade and cover disc on the shaft. The blades are completely machined and formed to shape, leaving materials that form the rivet integral with the blade. The cover disc forms the inlet of the impeller and is accurately machined to allow smooth flow. A sealing surface is provided on the cover disc to prevent recirculation of the gas. The component parts are placed in the fixture, and the drilled holes for the rivets on both the hub and cover disc are countersunk and polished. The entire assembled impeller is statically balanced. The impeller is mounted on an overspeed mandrel and run at 25% overspeed.

Figure 17.57C  Cutaway of riveted wheel. Blades are riveted to hub disc, and the cover disc is drilled ready for securing blades (used by permission: A. C. Compressor Corporation).

Head for a single-stage, independent of machine size or rpm is

Had = ψυ2/g

(17.84)

The values for ψ for best design for centrifugal compressors should be in the range of 0.50 (± 0.04) for industrial compressor stages to 0.63 (± 0.04) for radial and forward-swept blading [40].

Had = adiabatic, ft-lbf/lbm = ft Wheels are statically balanced individually; then the total assembly of wheels on the shaft is also statically and dynamically balanced. An internal balancing drum (see Figure 17.51E) is usually placed on the discharge end of the shaft to balance thrust loads.

666  Petroleum Refining Design and Applications Handbook Volume 2

The component parts are heated. The blade shape is laid out on the hub disc and tack welded, which ensures that the blade cannot be misaligned. The hub disc with tack welded blades are placed on the automatic impeller welding machine and heated for welding. After the blades are completely welded to the hub disc, the cover disc is welded on by the same means. The completely welded impeller is then ready for annealing and finish machining.

Figure 17.57D  Part 1. View toward inlet of 4½ in. diameter brazed aluminum impeller. Note: Regardless of the metal of manufacturer, enclosed impellers with back-leaning blades are extremely useful in applications requiring a steep head-volume characteristic and the highest attainable efficiency. Applications include parallel operation with other compressors or boosting of another compressor’s output. The power–volume curve will show a self-limiting feature at higher volumes. This feature is very beneficial when the driver has limited power available but operation throughout the full capacity range is required (used by permission: A.C. Compressor Corporation).

Figure 17.57D  Part 2. Close-up welding of section of welded impeller (used by permission: Elliot® Company).

Compression Equipment  667

Figure 17.57E  Radial impeller for single stage compressor (used by permission: A.C. Compressor Corporation).

HEAD

100%

POWER

100%

100% INLET VOLUME Ideally suited for dirty gas, corrosive or high head applications. Their inherent self-cleaning design permits longer operation on dirt-laden or corrosive gas service without shutdown. At a given tip speed, higher heads are possible than with other impeller designs. A wide variety of materials are available to meet special application needs. Radial bladed impellers have a relatively flat head-volume characteristic, thus permitting a wide variation in volume with little change in pressure. The efficiency is almost constant over the normal range of operation. As a result, the power requirements are proportional to flow.

Figure 17.57F  Open radial blade impeller, Type “R” (used by permission: Bul. “Centrifugal Compressors Single Stage.” A.C. Compressor Corporation).

668  Petroleum Refining Design and Applications Handbook Volume 2

HEAD

100%

POWER

100%

100% INLET VOLUME Open impellers with back-leaning blades combine the best feature of both the radial bladed type and enclosed type with back-leaning blades. They have moderately rising head-volume characteristics, which not only permit a wide range of flows in a given impeller bu also allow a moderate variation in pressure. Efficiency is greater than that of a radial bladed type. The power-volume characteristic rises with flow at a rate slightly less than that of the radial bladed type.

Figure 17.57G  Open impeller with backward-leaning blades, Type “SR” (used by permission: Bul. “Centrifugal Compressors Single Stage.” A.C. Compressor Corporation).

Figure 17.57H  Advanced datum impeller design reduces operating stresses and improves flow velocity (used by permission: Dresser-Rand Company. All rights reserved).

Compression Equipment  669 TYPICAL EFFICIENCY RANGES

EFFICIENCY, %

90 80

AXIAL FLOW

MIXED FLOW

OW L FL DIA

RA

70

SINGLESTAGE FANS, & PRO. PELLERS

60 SINGLE-STAGE COMPR. & FANS

MULTI-STAGE COMPRESSORS

MULTI-STAGE COMPRESSORS

TYPICAL IMPELLER GEOMETRY

.01

.03

.05

.1

.3

.6

1.0

FLOW COEFFICIENT, Ø

Figure 17.57I  Part 1. Impeller geometry versus flow y, dimensionless to define the flow-handling capability of a specific impeller (wheel) geometry, (Φ = Q/(π/4)(D2υ)), Φ = Dimensionless flow coefficient, V = volume flow at inlet (m3/s, acfm), υ = circumferential or tip speed at impeller outlet (m/s, fps), Hp = polytropic head (J/kg, Btu/lb), He = effective head (J/kg, Btu/lb), µ = impeller polytropic head coefficient, n = mechanical speed (rpm), ηp = polytropic efficiency, D = impeller outlet diameter (m, ft), z = number of impellers (used by permission: Fullemann, J., Technical Report “Centrifugal Compressors,” © 1963. Cooper Energy Services, Cooper-Cameron Corporation. All rights reserved).

Guide or Prerotation Vanes Vanes are formed on the diaphragm assembly to direct the flow of gas into the eye of each succeeding impeller. The vanes are arranged to suit the wheel design and flow rates of the gas through the compressor. Figure 17.58 shows these interwheel vanes. Special designs allow for these to have the pitch manually adjusted during operation to properly balanced the compressor operation. When the vanes are placed on the inlet to the first stage wheel, they are usually of a variable pitch design. This allows for variation in compressor performance similar to that shown in Figure 17.73. The adjustable vanes vary the angle of the gas flow as it enters the first wheel, thereby changing the effective inlet gas pressure and/ or volume without throttling losses (Figure 17.58). Figure 17.59A shows the inner side of the prerotation vanes as they would be directly adjacent to the first wheel. The control linkage is shown. Figure 17.59B illustrates the exterior view with control air motor in place. All compressors do not have nor need inlet guide vanes; however, it is advisable to discuss this with the manufacturers as their designs may perform better with the vanes. They are usually an extra cost item. Power savings of 15% or more may result from the use of such vanes [42], depending on the design and final operating point on the compressor’s performance curves. The inlet guide vanes increase the turndown and, thus, increase the operating range.

670  Petroleum Refining Design and Applications Handbook Volume 2

1.1

Φ > 0.10

Relative efficiency η/η max

2

3

1.0 4 0.9

5

1

1 2

Φ = 0.04 ÷ 0.11

3

4

0.8 5 0.7

0.0

Φ = 0.005 ÷ 0.05

6

0.0

0.02

0.04

0.06

0.08

0.10

0.12

Flow coefficient Φ 0585 9021

Φ Dimensionless flow coefficient V Volume flow at inlet (m3/s, acfm) u Circumferential or tip speed at impeller outlet (m/s, fps) Hp Polytropic head (J/kg, Btu/lb) He Effective head (J/kg, Btu/lb) µ Impeller polytropic head coefficient n Mechanical speed (rpm) ηp Polytropic efficiency D Impeller outlet diameter (m, ft) z Number of impellers

Figure 17.57I  Part 2. The graph shows the influence of the flow coefficient, Φ on the efficiency, 1, 2, 3 … are the individual impellers or stages and their efficiencies in a multistage compressor designed for optimum speed and overall efficiency (O, O, O) and alternatively, for reduced speed (∇, ∇, ∇) (used by permission: Bul. 27.24.10.40 – Bhi50. Zulser Turbo Ltd.).

Shaft The shaft is a forging and may be designed as a stiff shaft or flexible shaft. A stiff shaft design means that the shaft will operate below any of its critical speeds. Usual practice limits design operation to 60% of the first critical speed. This requires a heavier shaft than the flexible design that allows the shaft to pass through its first critical speed at 40–60% of normal and maximum operating speeds.

Bearings Shaft journal bearings for compressors operating in most process services and some air applications are located “outside” the case, rather than being an inside bearing. This is important for maintenance, as well as for reducing the problems in keeping oil out of the gas stream; although this problem still exists, but not to such a great extent. Thrust bearings of the Kingsbury type are one example of a good bearing for this equipment (Figures 17.60A and 17.60B). The double-acting bearing can absorb thrust loads in either direction.

Accessories Oil coolers for bearing oil (and often sized for turbine oil requirements when turbine is used) must be a part of the system and are usually mounted on or in the compressor-driver base plate(s). This allows a compact arrangement but is sometimes so congested that poor maintenance conditions result. The cooler, oil filter, and regulator can also be mounted adjacent to the unit. For some sizes, the compressor and driver can be mounted on a single base plate;

Compression Equipment  671

0.60 1 0.50

100

2 3

0.40

80

“ηp”

0.30

1

60

2

40

0.20

0.10

DESIGN N/AO CURVE 11 1 9 2 5 3 10

N/AO = N (KgZRT)0.5

20

30

MU - EFFICIENCY CURVE

40 % Q/N

50

60

POLYTROPIC EFFICIENCY, ηp

PRESSURE COEFFICIENT “µ”

“µ”

20

70

80

Q = VOLUME FLOW N = ROTATIVE SPEED

Stage performance of a compressor is usually represented in a pressure coefficient (Mu) and efficiency (Eta) vs. Q/N (Capacity vs. Speed) A given impeller stage design will have a different characteristic depending on the relationship of its operating speed to the inlet sonic velocity of the gas. For higher ratios of speed to sonic velocity (N/Ao), the head or pressure coefficient curve will be steeper at flows higher than design.

Figure 17.57  Part 3. Stage performance of a compressor is usually represented in a pressure coefficient, µ or Mµ, and efficiency, η, versus Q/N (capacity vs. speed). A given impeller stage design will have a different characteristic depending on the relationship of its opening speed to the inlet sonic velocity of the gas. For higher ratios of speed to sonic velocity. N/Ao, the head or pressure coefficient curve will be steeper at flows higher than the design (used by permission: Bul. 423, © 1992, Dresser-Rand Corporation).

however, this arrangement becomes bulky to ship and handle for large sizes. For these, as well as the smaller units, separate base plates can be used, but here extreme care in alignment and in foundation design is necessary to avoid trouble. Usually, dual oil pumps are included, so that one pump failure will not shut down the compressor-driver unit. The first or main pump may be driven by electric motor, and the standby steam or gas may be driven by turbine. Any combination is acceptable as long as the selection takes into account the specific local conditions and service reliability. Figures 17.61A–C show an overall assembly, including accessories, and Figure 17.61D shows a photograph of a turbine for the crude distillation unit.

Shaft End Seals The sealing of process gas along the rotating shaft is a delicate and important problem. Many factors enter into the selection of the type of mechanical seal best for the service [43, 44] including the following: 1. P  roperties and the nature of gas in the case-corrosiveness, viscosity, abrasiveness, explosiveness, lubricity, temperature, and pressure. 2. Rotational speed of shaft and peripheral speeds of seal. 3. Mechanical limitations—dimensions of space required versus space available, shaft deflection and whip, shaft end play, shaft diameter, and maintenance. 4. Miscellaneous factors—cost, allowable bypass or out-leakage, allowable contamination of gas with air, inert gas, oil, and other fluid.

672  Petroleum Refining Design and Applications Handbook Volume 2 Arrow Showing Direction of Guide Vane Rotation

Intake Closing Ring Labyrinth Packing Ring

1st Stage Diffuser 1st Stage Diaphragm

Spacing Ring Power Wheel

1st Stage Impeller

Adjustable Guide Vane

Shaft Sleeve Shaft

Arrow Showing Direction of Shaft Rotation

Guide Vane Gear Supporting Ring

Rocker Ring Gear

Adjustable Guide Vane

Figure 17.58  Gas flow through inlet guide vanes; power wheel shows a head of first stage impeller (used by permission: Ingersoll-Rand Company. All rights reserved).

Figure 17.59A  Inlet prerotation vanes (used by permission: York International).

These factors are not necessarily all the guide-points in the final seal selection, as individual conditions may be so special or unusual as to justify a special design or a compounding of the features of several “standard” designs. Only rarely will any seal be “perfect” for the service or job application. Many types and designs of seals are available, each to fill a certain need. Table 17.7 lists a few for general applications. Figures 17.62–17.66 are summaries of the common types of shaft seals. For some, it is preferable to connect the vent opening between the seals to an area of low pressure, such as an ejector system, in order to draw the leaking

Compression Equipment  673

Figure 17.59B  Single stage blower with automatically controlled inlet vanes (used by permission: A. C. Compressor Corporation).

gases out of the seal, in preference to pressurizing the seal with contaminating oil, or other gas. Figure 17.67 can be used to estimate process gas leakage across a single or tandem gas seal arrangement.

Materials of Construction Tables 17.8 through 17.8F summarize the usual materials for the components of the compressor. In general these tables apply to medium pressure (125–400 psi) machines in noncorrosive hydrocarbon service (Table 17.8A). Other fluids may require the use of special steel, nonferrous parts, or nickel alloys [44, 45]. Note that many of the materials are limited by temperature (high or low), and some processes cannot afford for high temperatures to develop inside the compressor due to the risk of explosion, auto ignition, surface reaction with metals, and polymer formation, which can restrict impeller and other flow passages. For a chlorine dry gas compressor, for example, Figure 17.53 shows the results of extensive high temperature formation of ferric chloride and the resulting internal fire that melted some metal parts. This was SAE 4140 steel and indicates the importance of temperature control. This unit operated at 7050 rpm, was electric motor gear driven, had an inlet dry gas of 12.5 psia at 41°F, discharged at 165 psia with two sets of interstage cooling (for example, see Figure 17.51C), and at time of failure the discharge temperature was 275–320°F. The temperature then jumped to more than 320°F (off the chart and beyond). Rehrig [45] discusses the selection of materials; also see Tables 17.8A–17.8F. Several manufacturers have developed corrosion resistant coatings to apply to driven compressor components and industrial gas turbine parts to provide protection against corrosion and fouling. One example is low pH wet chloride environments as seen in steam turbines [46].

Figure 17.60A  Kingsbury-type thrust bearing (used by permission: Elliot® Company).

674  Petroleum Refining Design and Applications Handbook Volume 2 Shoes

Adjustment Shims

Leveling Plate

Seal Collar

Seal

Shaft

Oil Inlet

Oil Drain

Figure 17.60B  Kingsbury-type thrust bearing for centrifugal compressor (used by permission: Kingsbury Machine Works, Inc.). Hand Control Valve Check Valves Pressure Indicator

Safety Relief Valves

Auxiliary Positive Displacement Pump

Auxiliary Pump Driver Fill Opening

Pressure Control Valve Main Pump Drive Gate Valve Main Positive Displacement Pump Temperature Indicator Oil Cooler Oil Filter Oil Reservoir

Figure 17.61A  Centrifugal compressor auxiliaries–forced feed lubrication system (used by permission: A.C. Compressor Corporation).

Compression Equipment  675 PAL PSL

PALL PI

PSLL

6

6

PDISH

PDAH

TE

TE TE TAH

TSH

TI

ZE

5

5

XE

XE

PCV

FG

FG

TI

PI

4

LAL

4

PI

DH

PAH

LBL

PSH

3

A force feed lube oil system ensures that journal and thrust bearings are properly lubricated. The system is basically designed in accordance with API 614 and is suitable for continuous compressor operation. It generally comprises: a) oil reservoir; b) steam turbine or electric motor driven screw or centrifugal pumps; c) full-flow oil coolers; d) twin filter (5/10 micron) allowing cartridges to be changed during operation; e) automatic by-pass valve to control oil pressure at the journal bearing manifold; f ) monitoring and safety instrumentation.

3

2

TI

TSHL

LG

1

LEGENDA 1. Oil reservoir 2. Suction strainer 3. Oil pump 4. Relief valve 5. Oil cooler 6. Oil filter

LG LSL LAL PI PCV PSL PAH

- Locally mounted instrument - Panel mounted instrument - Level glass - Low level switch - Low level alarm - Pressure indicator - Pressure control valve - Low pressure switch - Low pressure alarm and stand-by pump start-up

PSLL PALL PSH PAH PDISH PDAH TI TE TSH TAH TSHL ZE XE FG

- Minimum pressure switch - Minimum pressure shut-down - High pressure switch - High pressure alarm - High diff. pressure indicator and switch High diff. pressure alarm - Temperature indicator - Thermoelement - High temperature switch - High temperature alarm - High/low temperature switch - Axial displacement probe - Radial probe - Flow glass

Figure 17.61B  A forced feed lube system ensures that journal and thrust bearings are properly lubricated. The system is basically designed in accordance with API 614 and is suitable for continuous compressor operation (used by permission: Bul. PROM 526/1-5/95-II. © Nuovo Pignone, S.p.a., Florence, Italy; New York; Los Angeles; and Houston, Texas. All rights reserved).

676  Petroleum Refining Design and Applications Handbook Volume 2 LT

5

PDAH

5 LC

PDSH

LSH

LAH

LSL

LAL

6 LG

LSLL

LALL

FG

TSH

PAH

PDISH

TAH

TSH

TI

4

4

PI

3

PI

3

FG

PSH

LAL

2

FG

PAH

2

LSL

LC

LG

LG

7 LG

TI

7

TSHL

A seal oil system supplies filtered oil to the liquid film rings or to mechanical type seals at the correct pressure and temperature. The system is basically designed in accordance with API 614 and is suitable for continuous compressor operation. It generally comprises: a) oil reservoir; b) steam turbine or motor driven screw or positive displacement pumps; c) full-flow oil cooler; d) twin filters (5/10 micron); e) overhead tank with level or pressure control; f ) automatic seal oil traps; g) monitoring and safety instrumentation.

Oil Gas Oil and gas

1

LEGENDA 1. Oil reservoir 2. Oil pump 3. Relief valve 4. Oil cooler 5. Oil filter 6. Overhead seal oil tank 7. Seal oil trap 8. Drain pot

LG LSL LAL LT LC LSH LAH LSLL

- Locally mounted instrument - Panel mounted instrument - Level glass - Low level switch - Low level alarm - Level transmitter - Level controller - High level switch - High level alarm - Minimum level switch

8

LG

LALL

- Minimum level shut-down PI - Pressure indicator PSH - High pressure switch PAH - High pressure alarm PDISL - Diff. pressure indicator and switch PDAL - Low diff. pressure alarm PDISH - High diff. pressure indicator and switch PDAH - High diff. pressure alarm TI - Temperature indicator TSH - High temperature switch TAH - High temperature alarm TSHL - High/low temperature switch FG - Flow glass

Figure 17.61C  The seal of oil system filtered oil to the liquid film rings or to mechanical-type seals at the correct pressure and temperature. The system is basically in accordance with API 614 and is suitable for continuous compressor operation (used by permission: Bul. PROM 526/1-5/95-II. Nuovo Pignone, Florence, Italy; New York; Los Angeles; and Houston, Texas. All rights reserved).

Specifications Centrifugal compressors are not items that the process company or its engineers should attempt to design in great detail. Rather, it is more important that they be in a strong position to (a) specify what is needed for the process, (b) understand the manufacturer’s recommendations, and (c) evaluate the recommended design and performance in the process situation. Also see Reference [47].

Compression Equipment  677

Figure 17.61D  A photograph of a turbine for the crude distillation unit.

Table 17.7  Index or rating leakages for single-sealing elements. High rating indicates high relative leakage past seal Seal

Out-leakage index**

Application

Figure no.

Straight-pass labyrinth

100

Low pressure, moderate temp.

17.62A, 17.62B

Staggered labyrinth, also stepped

56

Medium pressure, moderate temp.

17.63B, 17.63C

Restrictive ring, carbon ring

20

High temp. (700°F), medium pressure

17.62, 17.64

Mechanical wet-contact seal

0

High pressure, high speeds

17.65

Liquid film seal

0

High pressure, high speeds

17.66

Mechanical contact (running dry)*

2

**Used by permission: Koch, D. T. “Centrifugal Compressor Shaft Seals,” ref. 35, Jan. 3, 1958. © Cooper-Cameron Corp. *Reprinted with permission: Nelson, W. E. Hydrocarbon Processing, V. 5, No. 2, p. 91[97]. © Gulf Publishing Co., Houston, Texas. All rights reserved.

To do these things, the process engineer must establish the function of the compressor; its capacities under conditions of normal, maximum, and minimum load; the acceptable materials of construction for the parts exposed to process fluids; and the importance and effect on performance of various fluid seals. In addition to the important processcentered specifications, the layout and general service conditions should be established for evaluation purposes. In order to establish the initial inquiry, a specification sheet similar to Figure 17.68 can be used. API Standard 617 also has comprehensive data form and excellent performance and mechanical standards [48]. In general all of the information on these sheets need not be given to the manufacturer, just the basic performance data and known specifications. The manufacturer is expected to complete the information as it applies to its equipment. A summary of the essential information is as follows: 1. Flow rate and suction conditions. a.  Pressure psia at inlet suction flange

b.  Temperature, °F c.  lb per hour, or volume, cfm (state whether dry or conditions relative to liquid saturation.)

678  Petroleum Refining Design and Applications Handbook Volume 2 LABYRINTH

BUFFERED LABYRINTH

LIQUID BUFFERED BUSHING

Suitable For Adaptation to:

All muti-stage compressors

All Multi-stage compressors

All Multi-stage compressors

Buffering Media

None

Clean, dry, air or inert gas. 2

Water or oil. 3

Stainless steel

Stainless steel.

Bronze in stainless steel housing.

No leakage of process gas. Moderate leakage of butter gas to process and/or ambient.

No leakage of process gas to ambient. Leakage toward gas stream is trapped in baffle to prevent contamination of gas in compressor casing. This liquid may be recycled if not contaminated. Out leakage of liquid is recycled. Separate pressure system silmilar to lubrication system including pumps, cooler, filters, etc., or if buffering media is oil, sealing system can be combined with bearing lubrication system.

Applications where positive sealing is necessary. No in-leakage of ambient air and no out-leakage of process gas. Specially suited for higher pressure applications.

Material

1

Sealing Ability

Compressor duty—Moderate leakage of process gas. Exhauster duty—moderate in-leakage of ambient air.

Buffering System

None

Buffering media supplied direcly from customer’s source. Filter or pressure regulator may be required. In cases where inlet pressure is below atmosphere and in-leakage of ambient is undesirable, buffering media may be process gas from compressor discharge.

Applications and Limitations

Generally used in air applications or applications where moderate leakage is tolerable. Normally not used in high pressure applications.

Applications where positive sealing is desirable and an inexpensive buffering media is available. Normally not used in high pressure applications. Only gases may be used for buffering.

Notes: 1 2

Other materials available for special applications—consult factory. Process gas may be used as buffering media, if clean and dry, to avoid in-leakage of ambient for exhauster duty.

Figure 17.62A  Multistage centrifugal compressor shaft seal arrangements (used by permission: A.C. Compressor Corporation).  (Continued)

Compression Equipment  679 CARBON RING

BUFFERED CARBON RING

COKE OVEN SEAL

All muti-stage compressors

All muti-stage compressors

Coke oven exhausters and boosters

None

Clean, dry, air or inert gas. 2

If buffering is required, use steam process gas, water on inert gas. (Usually not neccessary.)

Carbon rings in stainless steel housing.

Carbon rings in stainless steel housing.

Stainless steel.

Compressor duty—small leakage of process gas. Exhauster duty—small in-leakage of ambient air.

No leakage of process gas. Small leakage of buffer gas to process and/or ambient.

Compressor duty—small leakage of process gas. Exhauster duty—small in-leakage of ambient air.

None

Buffering media supplied directly from customer’s source. Filter, pressure regulator, etc., may be required. In cases where inlet pressure is below atmosphere and in-leakage of ambient is undesirable, buffering media may be process gas from compressor discharge.

Buffering media supplied from customer’s source.

Applications where buffering media is not readily available and only small leakage is tolerable. Not suitable for very high speed or very high pressure applications.

Applications where positive sealing is desirable and only small amount of buffering gas leakage tolerable. Not suitable for very high speed or very high pressure application. Only gases may be used for buffering.

Applications where positive sealing is desirable and an inexpensive buffering media is available. Normally not used in high pressure applications. Only gases may be used for buffering.

Notes: 1 2 3

Other materials available for special applications—consult factory. Process gas may be used as buffering media, if clean and dry, to avoid in-leakage of ambient for exhauster duty. Other liquids may be used if suitable—consult factory.

Figure 17.62A (Continued)  Multistage centrifugal compressor shaft seal arrangements (used by permission: A.C. Compressor Corporation).

680  Petroleum Refining Design and Applications Handbook Volume 2 Dry Face

Labyrinth

Carbon ring Seal cartridge Shaft Seal Options. The dry face seal for optimum sealing. The Atlas Copco overhung impeller design is ideally suited to the use of a dynamic dry face seal — a proven technology which eliminates the need for an oil-film seal and expensive support systems. The dry face seal operates on the principle of a hydrostatic and hydrodynamic force balance. Spiral grooves on a rotating ring force process gas inward between the seal faces. The gas flow is restricted by a sealing dam, increasing the gas pressure on the outer portion of the faces. The pressure provides the opening force which allows the seal to work at minimum clearance and with minimum leakage. The dry face seal is recommended when leakage can be hazardous and/or costly. Labyrinth seals are available for low-pressure air applications or when leakage of process gas into the atmosphere can be tolerated. Buffered labyrinth seals permit injection of buffer gas between the labyrinths to help prevent leakage of process gas. Buffered carbon ring seals can be used in moderate pressure applications. They can be operated dry, buffered with gas, or buffered with liquid. Oil bushing seals or wet mechanical seals are also available.

Mating ring

Vent, Flare, etc.

Bearing

Oil drain

Floating oil seal

Oil drain

Buffered Labyrinth

Buffer gas injection Vent to atmosphere Bearing

Floating oil seal

Buffered Carbon Ring Vent, inlet, etc.

Vent or buffered port Carbon ring seal Vent, Flare, etc. cartridge Floating oil seal Bearing

Oil drain

Oil Bushing

Seal cartridge

Vent to atmosphere Vent, Floating oil seal inlet, etc. Bearing

Wet Mechanical Oil supply

Pressure reference (to head tank)

Seal cartridge Oil supply Floating oil seal Bearing

Floating oil seal Bearing

Carbon ring Spring

Oil drain Oil drain

Drain/Vent (to trap)

Figure 17.62B  Shaft seal options (used by permission: Bul. 2781005301, © 1988. Atlas Copco ACT).

Drain/Vent (to trap)

Compression Equipment  681 (A)

(B)

(C)

Figure 17.63  (A) Straight-pass labyrinth seal; (B) staggered labyrinth seal; (C) stepped labyrinth seal. Note: Materials usually are aluminum bronze, babbitt, other soft material; or steel (used by permission: Cooper-Cameron Corporation).

Packing Box Cap Steam, Air or Gas Seal Medium (Pressure Slightly Higher than Compressor Gas)

Case

Labyrinth Ring

Garter Spring

Compressor End

Shaft

Packing Box

Figure 17.64  Packing box arrangement.

682  Petroleum Refining Design and Applications Handbook Volume 2 ISO-CARBON SEAL (Cont’d.)

6

OIL

OIL

4

FUNCTION CAR ZONE

5

14 12

10

13

11

9

2

1

8

3

7

Internal Gas Pressure

1. Rotating carbon ring 2. Rotating seal ring 3. Stationary sleeve 4. Spring retainer 5. Spring 6. Shutdown seal piston 7. Gas and contaminated oil drain

8. Centrifugal oil separator 9. Floating babbit-faced steel ring 10. Seal wiper ring 11. Seal oil drain line 12. Secondary wiper ring 13. Bearing oil drain line 14. Bearing wiper ring

Figure 17.65  Mechanical wet contact type seal (used by permission: Elliot® Company).





d.  Gas Composition at suction conditions. (1) Molecular weight. (2) Isentropic exponent (if known). (3) Compressibility factor, (if known, or necessary). e.  Barometric pressure, psia or mm Hg (at installation site). f.  Request performance curves for design, 90%, 80%, 70%, 60%, and 50% of rated speed.

2. Discharge Conditions. a.  Pressure, psia. b. Temperature (if limitation exists; otherwise manufacturer will be controlled by his experience and the effect of temperature on materials of construction. Request temperature at rated pressure but 90–50% of rated volume). 3. Cooling water a.  Temperature in summer, winter, and design average. b.  Type (cooling tower, fresh, salt, etc.). 4.

 ompressor construction details. C a.  Type and location of inlet and outlet connections on case. b.  Type case (horizontally split, vertically split.) c. Cooling—diaphragm cooled, external intercoolers, liquid injection in case (this should be selected only on recommendation of manufacturer). d.  Minimum case design pressure. Request case test pressure. e.  Materials of construction:

Compression Equipment  683

OIL

FUNCTION CAR ZONE

Compressor End 9

11 10

7

8

1. Stationary seal sleeve 2. Rotating shaft sleeve 3. Spring 4. Seal casing partition 5. Centifugal oil separator 6. Gas and contaminated oil drain

2

1

4

5

6

3

7. Floating babbitt-faced steel ring 8. Seal oil drain line 9. Wiper ring 10. Bearing wiper ring 11. Bearing oil drain line

Figure 17.66  Liquid film seal (used by permission: Elliot® Company).



(1) Case (2) Shaft (3) Diaphragms (4) Impeller or rotor (5) Labyrinth seals f.  Overspeed rpm for each wheel, operating tip speed. g.  Critical shaft speed, rpm. h.  Noise level in decibels.

5. S haft seals and packing. Request detailed drawings of oil seals, shaft seals, and any purge gas or oil details. Request guaranteed seal air, gas, or oil leakage rates at a given buffering media pressure. 6. Driver (see the appropriate specifications in Reference [107]) a.  Steam turbine (give steam conditions). Request performance curves at varying speeds. b.  Electric motor (give power conditions). c.  Gas engine (give gas conditions). d.  Others (belt, gears, etc.) e.  Controls for speed Note: If driver economics are to be evaluated by the manufacturer, utility costs must be supplied. 7. C  ontrols. Request diagram of shutdown and alarm for over- or under-pressure, overspeed, high bearing temperature, lube oil system. 8. Pressure lubricating system for compressor and driver bearings.

684  Petroleum Refining Design and Applications Handbook Volume 2 17.00 12.00

10.00 8.00 6.00 SINGLE GAS SEAL

SINGLE GAS SEAL

4.00

4.00 2.00 EA L

TANDEM GAS SEAL

0.50 0.40

0.20 0.14 0.10

0.40

0.20

SS UR ES

HE RP

RE

EAL

0.60

HIG

1.00

1.00 0.80

LOW PR ESSUR ES

1.40

LEAKAGE - FT3/MIN (14.7 PSIA & 80°F)

2.00 LEAKAGE - M3/MIN (14.7 PSIA & 60°F)

This chart, based on nitrogen gas, is used to estimate process gas leakage across a single or tandem gas seal arrangement. For a single or tandem seal, the pressure drop on the abscissa represents the difference between suction pressure and atmospheric pressure. The chart can also be used to estimate buffer gas leakage across the faces of a double gas seal arrangement. Since the top seal is exposed to the full pressure drop from buffer gas pressure to vent pressure, the single seal curve can be used to estimate leakage across the top seal. The lower seal is exposed to a pressure differential represented by the difference between buffer gas pressure and suction pressure. The single seal curve can also be used to determine the buffer leakage rate across the lower seal into the process gas.

8.00

NOTE: FOR DOUBLE SEALS USE - AP ACROSS EACH SEAL TO DETERMINE LEAKAGE

0.10 0.08 0.06 0.04

0.06 0.04

0.02

0.02

0.01

0 0

200 400 500 800 DIFFERENTIAL PRESSURE - PSID 10

20 30 40 50 60 DIFFERENTIAL PRESSURE - BARD

1000 70

Figure 17.67  Estimates of process gas seal leakage using nitrogen as sealing gas for single and tandem gas seal arrangements (used by permission: Sundstrand Compressors Bul. 450 April 1995. © Sundstrand Fluid Handling Corporation).



a.  Oil pumps driven from governor end of turbine shaft. b.  Emergency oil pump (separate motor or turbine drive). c.  Oil reservoir with connection for air purge. d. Oil cooler using water coolant at a specific temperature. Specify tube and shell materials if manufacturer’s standard of admiralty, muntz metal, and steel (shell) is not acceptable. Specify water pressure.

9.

 ccessories usually include A a.  Main oil pressure gauge. b.  Bearing oil pressure gauge. c.  Temperature indicator at each bearing. d.  Shaft coupling, flexible, spacer type. e.  Coupling guard. f.  Tachometer, vibrating reed, or electric. g.  Baseplate, single or common for compressor and driver. h.  Steam, oil and water piping directly associated with connecting the compressor-driver unit. i.  One set special tools and wrenches for dismantling compressor and driver. j.  Operating instructions. k.  Dimensional drawings, including dimensions and details of all accessory equipment.

10. Additional details useful in most applications. a.  Impeller: Mach number at eye and at periphery. b.  Maximum possible speed of compressor, also of driver. c. Maximum horsepower possible for driver to develop, with any changes necessary to bring up to this maximum (such as changing nozzles, nozzle ring of steam turbine, changing blades or buckets).

Compression Equipment  685 Table 17.8A  General material specifications for noncorrosive applications. Also see Tables 17.8B–F Part

Material

Casing (low pressure)

Cast semi-steel or cast steel

(high pressure)

Cast steel or forged steel

Shaft

Carbon steel (AISI-CI045), 18-8 stainless, or alloy steel forging AISI 4340.

Impellera (discs, covers, blades)

Forging: SAE 1040, 1045, ASTM A-294 B-4, 18-8 stainless or AISI 4130, 316 SS.

Rivers

Forged AISI Type 410, or as previously listed.

Diaphragms (uncooled)

Cast iron, STM-A-48-CI 30

(cooled)

Cast iron, ASTM-A-48-CI 30

Inlet guide vanes

Cast iron, ASTM-A-48-CI 30

Shaft sleeves

Steel AISI-1010, or alloy steel, 316 SS

Labyrinths (internal)

Aluminum, lead (ASTM-B-23 gr. 8 high lead), bronze

(shaft)

Aluminum, lead (ASTM-B-23 gr. 8 high lead), bronze

Seals, rotating face

Bronze, carbon as required, tungsten carbide

Mechanical seals

316-Carbon

Bearings (journal, precision faced thrust)

Steel-backed, babbitt-faced, ASTM B-23 gr. 3 high tin as recommended by manufacturer.

Thrust balancing disc

Steel, AISI-1023, or ASTM-A-294 gr. B forging.

b

For tip speed of 1100 fps For high pressure

a

b

Titanum. 17-4Ph SS.

Table 17.8B  Cast casing materials for low-temperature applications. Cast casing material

Commercial designation

Minimum temperature limits—°F (°C)

Steel

ASTM A352 gr. LCB (0% nickel)

−50 (−46)

Steel

ASTM A352 gr. LC2 (2–3% nickel)

−100 (−73)

Steel

ASTM A352 gr. LC3 (3–4% nickel)

−150 (−101)

Steel

ASTM A352 gr. LC4 (4–5% nickel)

−175 (−115)

Stainless steel

ASTM A743 gr. CF3, CF8, CF3M, CF8M

−320 (−196)

Stainless steel

ASTM A351 gr. CF3, CF8, CF3M, CF8M

−320 (−196)

Used by permission: Rehrig, P. Hydrocarbon Processing, V. 60, No. 10, p. 137, ©1981. Gulf Publishing Company, Houston, Texas. All rights reserved.

Table 17.8C  Welded casing material for low-temperature applications. Welded casing material

Commercial designation

Minimum temperature limits—°F (°C)

Steel

ASTM A516 gr. 55

−50 (−46)

Steel

ASTM A537

−75 (−59)

Steel

ASTM A203 gr. A, B

−75 (−59)

Steel

ASTM A203 gr. D, E

−160 (−107)

Steel

ASTM A553 Types, I, II

−275 (−171)

Stainless steel

ASTM A240 Types 304, 304L, 316, 316L, 321

−320 (−196)

Steel

ASTM A353

−320 (196)

Used by permission: Rehrig, P. Hydrocarbon Processing, V. 60, No. 10, p. 137, ©1981. Gulf Publishing Company, Houston, Texas. All rights reserved.

686  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.8D  Impeller material for low-temperature applications. Impeller material

Commercial designation

Minimum temperature limits—°F (°C)

Titanium

ASTM B367 gr. C3, C4

−50 (−46)

Steel

AISI 3140

−50 (−46)

Stainless steel

ASTM A744/351 gr. CA6NM

−50 (−46)

Stainless steel

ASTM A747 gr. CB7CU-1, CB7CU-2

−150 (−101)

Steel

AISI 4320-4345

−175 (−115)

Steel

ASTM A543

−175 (−115)

Monel K500

AMS-4676

−175 (−115)

8% Nickel steel

ASTM A522 Type II

−275 (−171)

Stainless steel

ASTM A743/351 gr. CF3, CF3M, CF8, CF8M

−320 (−196)

Stainless steel

ASTM A473 Type 304, 304L, 316, 316L

−320 (−196)

9% Nickel steel

ASTM A522 Type I

−320 (−196)

Used by permission: Rehrig, P. Hydrocarbon Processing, V. 60, No. 10, p. 137, © 1981. Gulf Publishing Company, Houston, Texas. All rights reserved.

Table 17.8E  Materials for usual construction of components for process type gas applications. Gas

Casing

Impeller

Diaphragm

Shaft

Acetic acid

Titanium

Titanium

Titanium

C.S.

Ammonia

316 S.S.

Inconel

316 S.S.

C.S.

Wet carbon dioxide

316 S.S.

17-4PH

316 S.S.

C.S.

Wet chlorine

Titanium

Titanium

Titanium

C.S.

Cyanogen chloride

Hastelloy

Hastelloy

Hastelloy

C.S.

Dry hydrogen chloride

C.S.

Inconel

C.S.

C.S.

Wet hydrogen chloride

Hastelloy

Hastelloy

Hastelloy

C.S.

Hydrogen fluoride

316 S.S.

316 S.S.

316 S.S.

C.S.

Dry hydrogen sulfide

C.S.

17-4PH

316 S.S.

C.S.

Wet hydrogen sulfide

316 S.S.

Titanium

316 S.S.

C.S.

Nitric acid

316 S.S.

316 S.S.

316 S.S.

C.S.

Dry phosgene

C.S.

Inconel

C.S.

C.S.

Wet phosgene

Hastelloy

Hastelloy

Hastelloy

C.S.

Polyvinyl chloride monomer

C.S.

Titanium

C.S.

C.S.

Sulfuric acid

316 S.S.

316 S.S.

316 S.S.

C.S.

Wet sulfur dioxide

316 S.S.

316 S.S.

316 S.S.

C.S.

Notes

Temp.

400°F

Temp.

480°F

Used by permission: Rehrig, P. Hydrocarbon Processing, V. 60, No. 10, p. 137, ©1981. Gulf Publishing Company, Houston, Texas. All rights reserved.

Cast iron

Alloy steel

Alloy steel

Carbon steel

Carbon steel

Aluminum

Cast iron

Labyrinth with bleed-down for higher pressures

*Casing

Impellers

Shaft

Impeller spargers

Balancing drum

Interstage labyrinths

Diaphragms and guide vanes

Shaft seal type

Mechanical oil with automatic positive shut-off seal

Cast iron or cast Ni-iron

Aluminum

Carbon steel or nickel

Carbon steel or nickel steel

Nickel steel

Alloy steel or nickel steel

Cast Ni-steel

Refrigeration at −175°F

*Nodular ASTM A-338 castings may be furnished where service permits. Used by permission: Bul. P-11A, © 1966. Elliott® Company.

Air

Service

Mechanical oil or liquid film

Cast iron

Aluminum

Carbon steel

Carbon steel

Mechanical oil with sweet gas injection or labyrinth with gas ejectors

Cast iron

Aluminum

Carbon steel

Carbon steel or stainless steel

Alloy steel

Alloy steel or stainless steel

Alloy steel Alloy steel

Cast iron or cast steel

Wet gas

Forged steel

Hydrogen reforming

Table 17.8F  Typical materials of construction for selected centrifugal applications.

Mechanical oil or labyrinth with sweet gas injection or dry carbon rings

Cast iron

Aluminum, bronze, Teflon or stainless steel

Carbon steel or stainless

Carbon steel or stainless steel

Alloy steel or stainless steel

Alloy steel or stainless steel

Cast iron, cast steel, or cast stainless steel

Toxic and corrosive gases

Labyrinth with steam injection and automatic shut-off device

Cast iron

Aluminum or stainless steel

Alloy steel or

Carbon steel or stainless steel

Carbon steel

Alloy steel or stainless steel

Cast iron

Coke oven

Compression Equipment  687

688  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.68  Centrifugal compressor specifications.

Compression Equipment  689

d.  Paint specifications for exterior of unit. e.  Suitability of entire unit for outdoor erection (if required).

11. Statement of performance guarantee. Compressor performance at the rated or design point is normally guaranteed with an allowable variation of ±4% on speed and horsepower. 12. Parts warranty.

Performance Characteristics Figure 17.69 illustrates a pressure–capacity relationship for horizontally split centrifugal compressors (described earlier). Although specific ranges and pressure breaks vary between manufacturers, the chart shows a fairly representation range for multistage, horizontally split centrifugal applications [60] in standard case sizes or frames, either cast or welded (fabricated) case construction. From Figure 17.69 the capacity range extends through 360,000 actual cfm (suction conditions) for double-flow configurations, and single-flow cases would extend to 180,000 actual cfm. Figure17.70 illustrates a special type of single-stage vertical shaft/horizontal impeller, highspeed centrifugal compressor used at speeds to 33,900 rpm and with case pressures of 1000–2160 psia working pressure. The usual motor drive uses a high-speed gear to drive the impeller. These are used in many light hydrocarbon and light gas applications [49]. The fundamental characteristics of compression are the same for centrifugal and reciprocating compressors. The manner in which these fundamentals are interpreted must be adapted to the particular machine type and operating characteristics, and this accounts for the difference in design procedures. The general operation of a centrifugal compressor is like a centrifugal pump, except that the fluid is compressible. Theoretically, the head developed by a centrifugal impeller or wheel is the same regardless of the characteristics of the gas involved. This is more strictly true for single-stage wheels (units) than for the multistage machines. It is a satisfactory approximation for this latter condition when the changes in performance (from design) are not greater than about 20%. It is important to remember that the impeller wheel recognizes and acts only in terms of the number of actual ft3 per min (or unit of time) going through, and not the number of lb of gas or mol of gas, or even standard ft3 per min. The impeller (wheel) of the centrifugal compressor imparts kinetic energy to the gas by increasing the gas velocity through the rotation of the impeller. A static pressure rise in the impeller comes from part of this energy, and the balance is converted to velocity head, which in turn converts to additional pressure rise in the compressor wheel assembly (see Figures 17.54, 17.55B, 17.57I, and 17.58). The kinetic energy is a function of the square of the velocity; thus, the head produced by the rotating impeller is directly proportional to the square of the tip speed of the impeller. Then [50],

Hp α υ2/gc where Hp   υ  gc and Hp

= polytropic head, ft-lbf/lbm = ft = impeller tip speed, ft/s = gravitational constant, 32.174lbm/lbf (ft/s2) = Ψυ2/32.2 

(17.85)

where Ψ = head or pressure coefficient, see earlier discussion. Thus, Ψ is a function of any specific impeller. The variation of Ψ with flow defines the characteristic curve of the impeller. n = k (ratio of specific heats, cp/cv) for an adiabatic, isentropic process n = 0 for isobaric (constant pressure) processes n = ∞ for isometric (constant volume) process

690  Petroleum Refining Design and Applications Handbook Volume 2 CENTRIFUGAL COMPRESSOR PRESSURE - CAPACITY CHART ENGLISH UNITS 10,000

MAXIMUM WORKING PRESSURE - PSI

VERTICALLY SPLIT HORIZONTALLY SPLIT

1,000

100

10 100

1,000

10,000

100,000

1,000,000

MAXIMUM INLET CAPACITY - ACFM

Figure 17.69  Generalized centrifugal compressor pressure–capacity chart for vertical and horizontally split cases. This chart is representative of the general ranges of most major manufacturers. As shown, the flow range extends through 360,000 cfm. This flow is generally achieved in centrifugal compressors using a double-flow configuration. A single-flow configuration would extend to 180,000 cfm (used by permission: Bul. 423. Dresser-Rand Company).

The terminology will not be repeated here unless the interpretation must be supplemented or modified. The design details will serve as an aid for estimating operating characteristics and not as a final basis for design. Neerken [22], Lapina [51], and Fullemann [40] are useful references.

Inlet Volume The inlet or suction volume to a compressor can be determined in several ways, depending on the data available and the processing conditions. A common relationship is



Inlet or suction volume, Vi = (w1) (v1)

(17.86)

w1 = flow rate, lb/min, v1 = specific volume at suction conditions, ft3/lb



v1 =

ZRT1 ZR i T1 Z(1545)(T1 ) = = 144P1 144P1 144(MW )(P1 )

Z = compressibility factor, dimensionless R = universal gas constant = 1545 (ft) (lb force)/(lb-mol) (°R) Ri = individual gas constant = R/mol wt of gas MW = mol wt of gas Ti = inlet gas temperature, °R Pi = inlet suction gas pressure, psia

(17.87)

Compression Equipment  691 6.0 MOLE WEIGHT = 44.01 REF. GAS: CARBON DIOXIDE T1 = 100°F (38°C) INLET PRESSURE LIMITS DUE TO HP: 50 PSIA (3.4 BARA) 100 PSIA (6.9 BARA) 250 PSIA (17.2 BARA) 500 PSIA (34.5 BARA) 1000 PSIA (66.9 BARA)

5.5 5.0

PRESSURE RATIO DISCHARGE PRESSURE/SUCTION PRESSURE

4.5

HMC-5000

4.0 3.5 3.0 14 PSIA 0.9 BARA 2.5

LMC/BMC 311/331F 25 PSIA 1.7 BARA

LMC/BMC 311/331P

LMC/BMC 317/337

LMC/BMC 311/333

2.0

1.5

LMC-801P/F 1.0 0 0

800

400 500

1000

1500

1200 2000

1600 2500

2000 3000

3500

2800

2400 4000

4500

5000

3200 5500

3600 6000

4000 ACFM 6500 AM3/HR

INLET VOLUME FLOW RATE ACFM = ACTUAL OR INLET CUBIC FEET PER MINUTE AM3/HR = ACTUAL OR INLET CUBIC METERS PER HOUR T1 = INLET TEMPERATURE PRESSURES ARE SUCTION PRESSURE LIMITS BASED ON MAX. HP FOR GIVEN CONDITIONS PRESSURE RATIO IS IN ABSOLUTE PRESSURES ONLY

Figure 17.70  Performance ranges for special high-speed/high pressure, single-stage Sundstrand Compressor (except model HMC 5000) centrifugal compressors. Special impellers are available for performance outside the envelopes shown. Performance varies with the gas involved (used by permission: Sundstrand Compressors Bul. 450 © April, 1995. Sundstrand Fluid Handling Corporation).

Compressor Piping It is extremely important to have a careful (usually computer) analysis of the piping stresses and strains where the piping is attached to the compressor flanges. The American Petroleum Institute (API) and American Society of Mechanical Engineers (ASME), as well as the compressor manufacturers, have some established limits as to what forces the flange–nozzle connections on a compressor can withstand. Excellent piping stress analysis computer programs exist to evaluate these connections and the stresses transmitted back to the compressor from other parts of the immediate piping system. See Reference [52] for one illustration, and for a more detailed discussion, see Reference [53]. Large horsepower reciprocating compressors usually require the

692  Petroleum Refining Design and Applications Handbook Volume 2 installation of pulsation surge drums or pulsation bottles and/or specially designed piping systems associated with the compressor. The compression of a gas as it passes through a single or multistage centrifugal machine is shown in Figure 17.71. The diagram may look similar to a reciprocating compression card; however, the return or expansion stroke never takes place in a centrifugal machine. As gas enters the machine at P1Vo, the speed and corresponding volume increase until the steady state condition of P1V1 is reached. Compression, which has been taking place as the speed and volume increase, finally follows the “k” or polytropic “n” value line for the gas from P1V1 to P2V2. Gas is discharged continuously at P2 as long as the steady-state suction condition is maintained. The compressor is now operating, and each increment of suction gas enters at the rate of V1, keeping the machine in balance. The effect of changing operating conditions will be discussed later. The actual performance curves of Figures 17.72 and 17.72A–E represent a typical presentation from a manufacturer. The rated design point is established at 100% of the rated speed; then other expected performances at lower or higher speeds will follow the locus of rated points indicated by the dotted line. The 100% rated speed line is the single line that defines the performance of the machine with changes in volume at the fixed speed. When inlet guide vanes are used at a fixed operating speed, the performance curve at that speed takes the form of Figure 17.73, being dependent upon the position of the vanes. The discharge pressure developed by the compressor must be equal to the process gas’s total system resistance, of control valves, hand valves, orifices, heat exchangers, and any other process-related devices through which the discharge gas from the compressor must flow. As this resistance changes, the gas flow through the compressor will automatically adjust itself to equal the new resistance [60]. Referring to Figures 17.72 and 17.72A–C, the performance characteristic curve at any % speed tends to become vertical (right end of curve), which relates to the maximum volume that any compressor can deliver. At this point the flow cannot increase despite a significant reduction in the system resistance. As the flow decreases, the minimum point is called “surge,” below which the operation becomes very unstable. Vibration of the compressor most probably will result, even to the point of cracking anchor flanges or possibly compressor cases. On Figure 17.72, the region to the left of the “Approximate Surge Limit” is the unstable condition. All centrifugal compressors have a flow at which maximum pressure is possible, and further reduction in flow beyond this point results in decreasing discharge pressure. “Pressure is built up again by the compressor. The flow proceeds in the normal direction. Surge, or back-and-forth oscillation, continues until the discharge pressure (system resistance) is decreased. The compressor should be run in a stable region and any excess flow should be blown off or sent through a manual or automatic surge control valve if the process flow is less than the compressor surge. In air applications, blow this surplus off to the atmosphere; in applications where the gas cannot be lost, recirculate the excess through a cooler to the inlet of the compressor.” (Paraphrase from reference unknown.). When a variable-speed driver, such as a steam turbine, is used for the compressor, the compressor performance can be varied to meet various operating flows and pressures by moving up or down the rated point locus of Figure Isothermal Compression, n = 1

P2

Polytropic Compression, n < k, and n > l

Pressure

Polytropic Compression, n > k High k Value Gas Low k Value Gas P1

V0

V2 Volume Rate, cfm

Figure 17.71  Compressor in a centrifugal machine.

V1

Compression Equipment  693 140

110%

120 110 100 90 80

Appr oxim ate S urge Limit

Percent Rated Head or Discharge Pressure, psia

130

105% 100% S peed 95% 90%

Rated Point

85%

70 60

140

Effect of Speed on Rated Point

130

Appr

40

50

0%

110

ed

e Sp

Rated Point

10

100 90

%

80

90% 85%

70

95

Locus of Rated Points for Change in Operation

60

Percent Rated Compressor Bhp or Actual Horsepower

oxim a

te Su

rge L

imit

10 11 5% 0%

120

50

40 60 70 80 90 100 110 120 130 Percent Rated Inlet Capacity or Actual Speed, rpm

Figure 17.72  Manufacturer’s typical centrifugal compressor characteristic curve.

17.72. As will be discussed later, for a fixed system resistance, the flow varies directly with the speed; the head varies as the square of the speed; and the horsepower varies as the cube of the speed. This latter condition of horsepower requirements is one that can control the flexibility of the system, as the possibility of exceeding available shaft horsepower can be an important factor. The “surge limit” shown in Figures 17.72A–C is an important operating limit, as it is the minimum flow point below which the centrifugal or axial compressor becomes unstable through pressure and flow pulsations and results in a loud “roaring” noise. The forces involved can be great enough to rip compressor cases loose on their foundations. An anti-surge control system is necessary to limit the capacity to a point in a safe region away from the surge limit [60].

Surge Control Refer to Figures 17.72C, 17.72D, or 17.72E. Assume that the compressor is operating at the “Design Point” designated on the figures on the 100% speed curve, with the inlet flow as V1 and the head as H1. For example, if the external system resistance (friction, ΔP, etc.) increases while the speed remains constant, the flow decreases, and the operating line point will move along the 100% speed line to the left until it reaches the “Surge Limit” line. The flow has reached the appropriate value of V2; the head has increased to H2, which is the maximum head the compressor can produce at this speed. Here, the characteristic operating line is practically flat, and the compressor operation becomes unstable. This is called “surging,” and it produces rapid high frequency reversals in the axial thrust on the compressor shaft [54]. See Figure 17.72D for one instrument

694  Petroleum Refining Design and Applications Handbook Volume 2 control diagram; this presents a simpler diagram but similar in concept to Figure 17.72C [55]. References [56–59] present useful analyses of the problem, as well as other control schemes. The lower right end of the performance curve on the figures terminates before reaching a limiting condition known as the “choke limit.” Extension of the performance curve would be vertical at the choke limit. Controls are usually not required for this condition but should be considered in overall system control design [60]. A “choke” or “stonewalling” condition can develop as indicated in Figure 17.72C. This occurs when the flow velocity in the compressor approaches the velocity of sound in the gas (sonic velocity or Mach 1) at the specific point shown on the operating characteristic curve. Usually velocities are well below sonic, but for heavy gases, such as some refrigerants, this situation must be recognized, and the performance of the unit designed to avoid the condition [11]. Note that the right side of the characteristic curves begin to turn down vertically as the “choke” or “stonewall” condition actually develops in the unit. Tables 17.9A and 17.9B give a typical summary of multistage compressor selection The efficiency, head, and speed data cover orders of magnitude for several manufacturers; however, some designs normally are rated at values below or above those listed. Table 17.9C shows average polytropic and isentropic efficiencies for various flow range, and comparison between reciprocating and centrifugal compressor types. Gas compression is polytropic in practically all commercial machines. That is, it is not adiabatic or isothermal, but some form peculiar to the gas properties and the hydraulic design of the compressor. Actual machines may be rated on adiabatic performance and then related to polytropic conditions by the polytropic efficiency. Other performance rating procedures handle the calculations as polytropic. For reference, both methods are presented.

140%

120%

CA

% 76 % 74

PA CI TY

LIM

IT

DESIGN POINT

AP P

70%

78% TIM UM EFF . EFF ICI EN CY

80%

90%

OP

APP

80 60

HEAD

ROX

. SU

100

RGE

LIM

IT

SPEED 100%

RO X.

120

110%

20

40

60%

0

20

40

60 80 INLET FLOW

100

120%

Figure 17.72A  Typical performance map of centrifugal compressor (used by permission: Fullermann, J. Report, “Centrifugal Compressors,” © 1963. Cooper Energy Services, Cooper-Bassemer Rotating Products Div., Cooper-Cameron Corporation. Originally printed: Advances in Petroleum Chemistry and Refining, Interscience Publishers Div., John Wiley and Sons. No longer in publication. All rights reserved).

Compression Equipment  695

120

M.W. = 34.26 Pd1 − Ps1 = 110 PSID (7.7 kg/cm2) • = SURGE INITIATING STAGE

•2

C

B C

Hp = 33246 ft. lbs./lb.

80

A

Rc = 3.507 •2

DESIGN POINT

60 B

100

EL IN

E

•2 90

•2

RG

40

SU

% PRESSURE RISE, Pd1 − Ps1

100

•2

20

0

80 ED

PE %S

70

•2

60 50

A

20

40

60 80 100 120 140 FOUR STAGE COMPRESSOR NO.1 Percent Rated Inlet Capacity or Mass Flow

160

Figure 17.72B  Performance examination of one set of centrifugal compressor conditions. The pressure rise required by most applications exceeds the capability of a single state; therefore, multistage compressors are used far more frequently. Multistage compression ratios within the range of 3:1 to 15:1 are typical, but the ratio of a single stage usually is less than 2.5:1. The surge line shape of a single stage can be predicted adequately using the fan laws, but this is usually not true for a multistage machine (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

120

M.W. = 32.68 Pd2 – Pd2 = 345 PSID (24.3 kg/cm2) • = SURGE INITIATING STAGE •3

100

80

Hp = 33842 ft. lbs./lb. (101156 J/kg)

•3

GE

LIN E

60

40

100

•1

90

•1

20

0

DESIGN POINT

SU R

% PRESSURE RISE, Pd2 – Ps2

Rc = 3.294

•1

20

40

80

•1

%

70

EE

SP

D

KE

CHO

IT

LIM

60

50

60

80

100

120

140

160

FOUR STAGE COMPRESSOR NO.2 Percent Rated Inlet Capacity or Mass Flow

Figure 17.72C  Performance examination of a second set of centrifugal compressor conditions. The volume reduction per stage is less when operating at speeds lower than design; therefore, stages near the discharge are forced to handle more than their rated volume, and those nearer the inlet handle less than normal. The accumulated effect is that the surge line shape tends to depart from the fan law predictions as more stages are added. It is common for surge to be initiated by one of the latter stages when the compressor is operating at design speed but by an earlier stage at lower speeds. A distinct change in the surge line is evident at the point where this occurs (used by permission: Bul. 423, © 1992. Dresser-Rand Company).

696  Petroleum Refining Design and Applications Handbook Volume 2 Ratio station

Surge controller Set

×

P2T1 P1T2

h1

T1

measurement ∆P

Ch1

h2

×

×

T2

÷

T2

P2 P1

P1

÷

T1

P2 P2

∆P P1

T1

T2

h2

Figure 17.72D  Centrifugal compressor surge control schematic diagram shows instrumentation required when primary flow-measuring device is located in centrifugal compressor discharge line. Symbols: T = temperature; P = Pressure; Δ = differential across compressor outlet to inlet (used by permission: White, M. H., Chemical Engineering, p. 54, Dec. 25, 1972 © McGraw-Hill, Inc. All rights reserved).

Differential-pressure transmitter

Pd – Pi

Compressor

Orifice plate

Inlet

Discharge

Differential-pressure transmitter

h

Antisurge controller

Ratio station

Bypass

Kh

Figure 17.72E  Control system monitors discharge pressure and flow to prevent surging in gas compressor (used by permission: Magliozzi, T. L. Chemical Engineering, p. 139, May 8, 1967. © McGraw-Hill, Inc. All rights reserved).

Compression Equipment  697 120 110

Pumping Limit Vanes Wide Open

Percent Rated Head or Pressure Rise

100 0°

90

15°

80 70 60 50 60°

75° 40

30

40

50

45°

60 70 80 90 100 Percent Rated Inlet Capacity

30° 110 120

Figure 17.73  Representative centrifugal compressor performance with inlet guide vanes (used by permission: A. C. Compressor Corporation).

Compression Process If the gas to be compressed contains water vapor (saturated or only partially saturated), this water content must be determined by (1) test of the mixture or (2) calculation. Then the properties of the gas-water vapor mixture must be determined by the usual gas calculations for weighted average molecular weight, average lb/min (or h), “k” value or “n” value, and others as necessary.



y = Pw/Pt

(17.88)

where Pw = vapor pressure of water at temperature, psia Pt = total system pressure, psia y = mol fraction water vapor This value of “y” can be used to calculate the weighted gas properties noted previously.

Adiabatic Adiabatic compression (termed adiabatic isentropic or constant entropy) of a gas in a centrifugal machine has the same characteristics as in any other compressor. That is, no heat is transferred to or from the gas during the compression operation. The characteristic equation

PVk = C

(17.89)

applies, where “k” is the ratio of specific heats, cp/cv, for the gas. An increase in gas temperature accompanies the compression. The use of the adiabatic process in calculations enables the designer to work from Mollier diagrams. This is closer to being correct for an internally cooled compressor than an uncooled machine. It is still a theoretical operation [61].

C , C , and C‴ are constants Isothermal Isothermal compression takes place when the heat of compression is removed during compression and when the temperature of the gas stays constant. The characteristic equation is

698  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.9A  Summary of typical multistage compressor data. Machine series

No. of stages per case

Nominal overall efficiency %

Cfm intake volume range (approx.)

Nominal head per stage-ft

Nominal speed rpma

Max. case working pressure Cast iron

Cast steel

A

Up to 7

78

18,000 to 40,000

9000

4700

125

Special order

B

3

75

20,000 to 28,000

9000

5000

60

Not available

C

Up to 7

78

12,000 to 22,000

9000

6200

125

250

D

Up to 7

77

3500 to 12,000

8500

8100

250

400

E

Up to 8

73

1500 to 4500

8000

9800

250

500

F

Up to 8

73

1000 to 3500

8000

9800

Not available

1,200b

Maximum allowable continuous operating speed is 105% of values given. Forged steel. Used by permission: Bul A.I.A., No. 35-i-4, © Elliott® Company.

a

b

Table 17.9B  Summary of typical multistage centrifugal compressor data. 2 M-line and MB-line frame data

Frame

Nominal flow range (cfm)

Nominal max. no. of casing stages

Max. casing pressure (psig)

Nominal speed (r/ min)

Nominal polytropic efficiency

Nominal H/N2 (per stage)

Maximum Q/N

29M

750–9500

10

750

11,500

0.78

7.5 × 10−5

0.83

38M

6000–22,000

9

625

7725

0.79

1.52 × 10−4

2.85

46M

16,000–34,000

9

625

6300

0.80

2.28 × 10−4

5.40

60M

25,000–58,000

8

325

4700

0.81

3.85 × 10−4

12.34

70M

50,000–84,000

8

325

4200

0.81

5.67 × 10−4

20.

88M

70,000–135,000

8

325

3160

0.81

39.1 × 10−4

42.7

103M

110,000–160,000

8

45

2800

0.82

11.6 × 10−4

57.1

110M

140,000–190,000

8

45

2600

0.82

13.4 × 10−4

73.1

10MB

90–1600

12

10,000

18,900

0.77

2.6 × 10−5

0.085

15MB

200–2350

12

10,000

15,300

0.77

3.6 × 10−5

0.153

20MB

325–3600

12

10,000

12,400

0.77

6.2 × 10−5

0.29

25MB

500–5500

12

10,000

10,000

0.78

9.5 × 10−5

0.55

32MB

2000–8000

10

10,000

8300

0.78

1.39 × 10−4

0.96

38MB

6000–22,000

9

1500

7725

0.79

1.52 × 10−4

2.85

46MB

16,000–34,000

9

1200

6300

0.79

2.28 × 10−4

5.40

60MB

25,000–58,000

8

800

4700

0.80

3.85 × 10−4

12.34

70MB

50,000–84,000

8

800

4200

0.80

5.67 × 10−4

20.

Number of casing stages is determined by critical speed margins. These numbers are a general guideline only. These values are typical. Flexibility in types of available staging can allow final computer selections to have significant variations in head and efficiency. Used by permission: Elliott Co., © Bul. P-26.

1 2

Compression Equipment  699 Table 17.9C  Centrifugal Compressor flow range. Nominal Flow Range (Inlet m3/h)

Nominal Flow Range (Inlet ft3/ min)

Average Polytropic Efficiency

Average Isentropic Efficiency

Speed to Develop 30,000 N-m/kg (50,000 ft-lbf/lbm) head per Wheel

170 – 850

100 – 500

0.70

0.67

20,500

850 – 12,700

500 – 7,500

0.80

0.78

10,500

12,700 – 34,000

7,500 – 20,000

0.86

0.83

8,200

34,000 – 56,000

20,000 – 33,000

0.86

0.83

6,500

56,000 – 94,000

33,000 – 55,000

0.86

0.83

4,900

94,000 – 136,000

55,000 – 80,000

0.86

0.83

4,300

136,000 – 195,000

80,000 – 115,000

0.86

0.83

3,600

195,000 – 245,000

115,000 – 145,000

0.86

0.83

2,800

245,000 – 340,000

145,000 – 200,000

0.86

0.83

2,500

If available obtain efficiency values from the compressor manufacturer rather than from this table. (GPSA [114]).



PV = C

(17.90)

This process is not achieved in commercial units.

Polytropic The polytropic process is mathematically easier to handle than the adiabatic approach for the following: (1) determination of the discharge temperature (see later discussion under “Temperature Rise During Compression”) and (2) advantage of the polytropic efficiency:



 n      Ep =   n −1    k    k − 1  

(17.91)

which describes the relationship between “n” and “k”. Thus, the polytropic efficiency is independent of the thermodynamic state of the gas during compression [50]. Polytropic compression is characterized by being neither adiabatic nor isothermal but is a variable entropy process. Its relation is expressed

PVn= C‴

(17.92)

where “n” is the characteristic of the gas that determines its compression performance. The exponent “n” is determined by the actual conditions of the gas at inlet to and discharge from the compressor, or to and from a specific cylinder. When n = 1, the compression is isothermal; when n = k, it is adiabatic. The slope of the compression curve is a function of the exponent “n”. Figure 17.71 illustrates the effect of the “n” and “k” values on the gas compression and the work associated with this compression. The usual centrifugal compressor is uncooled internally, and hence, operates with polytropic characteristics having “n” greater than “k”; however, if the unit is internally cooled, then “n” will be greater than 1.0 but may be less than “k” The inefficiencies caused by internal losses (friction, etc.) keep the operation from being truly adiabatic; however, some compressions are close to this condition and may be used for approximations.

700  Petroleum Refining Design and Applications Handbook Volume 2 Woodhouse [108] presents the following relation for the polytropic exponent, “n,” based on actual inlet and discharge specific volumes of the gas being compressed:



n=

log10 (P2 / P1 ) log10 ( v 1 / v 2 )

(17.93)

This applies with good accuracy for single wheels and for the overall multistage compressor. This is extremely useful in determining polytropic efficiency. Values of “n” may be read from Figure 17.74 for approximate actual inlet flow capacity, cfm, to the suction of the compressor, or to individual wheels of a multistage unit, if the individual wheels are being evaluated. Usually the process engineer is concerned with estimating the overall performance and not the individual wheels. Specific volumes may be conveniently read from Figure 17.75.

Efficiency Adiabatic Efficiency. The ratio of theoretical adiabatic horsepower to actual brake horsepower required at the compressor shaft is adiabatic efficiency. It is equal to compression efficiency x mechanical efficiency [62, 63].

adiabatic work  (P2 / P1 )( k −1)/k − 1  =  polytropic work  (P2 / P1 )( n−1)/n − 1  theoretical adiabatic temperature rise Ea = actual temperature rise Ea =





T1[(P2 / P1 )( k −1)/k − 1] = T2 (actual) − T1

(17.94)

(17.95)

Adiabatic Shaft Efficiency. The Adiabatic and polytropic efficiencies do not include the losses of packing glands, oil pump, journal bearings, thrust bearings, etc. [64]. To account for these losses in horsepower and to relate these losses to the actual brake horsepower, an overall efficiency can be used and expressed as the adiabatic shaft efficiency, Eas. The manufacturers usually know these losses in horsepower, or the values may be summarized as approximately 1–3% for units of 500–1,500 hp (approximately) and larger for smaller horsepowers and about 1–1.5% for horsepowers greater than 15,000. Adiabatic efficiency is expressed as follows:





E ad =

Had (E p ) Hp

 k  ZRT1  [(P / P )( k −1)/k − 1]  k − 1  2 1 = (E p )  n  ( n−1)/ n [(P / P ) − 1] ZRT1   n − 1  2 1

(17.96)

(17.97)

The adiabatic efficiency is a function of the pressure ratio, and thus, dependent on the thermodynamic state of the gas undergoing compression [50]. Polytropic Efficiency. This is the ratio of theoretical polytropic horsepower to actual brake horsepower at the compressor shaft. The polytropic efficiency does not include packing, bearing, or other losses. This efficiency is a measure of the

Compression Equipment  701

(n−1)/n

0.5

Ratio of Specific Heats for Frequently used Gases Air 1.406 Oxygen 1.401 Nitrogen 1.407

Suction Volume 1,500 cfm 2,000 cfm

3–4,000 cfm

0.4

5,000 cfm 7,000 cfm

0.3

Isentropic or Diaphragm Cooled

15–30,000 cfm 60,000 cfm & Above

0.2 Methane Ethane Propane n-Butane Iso-Butane Carbon Dioxide Sulphur Dioxide

0.1

0

1.2

1.3

1.306 1.189 1.150 1.100 1.110 1.300 1.270

1.4

Cp Ratio of Specific Heats, k = Cv

1.5

Figure 17.74  Ratio of specific heats (n − 1)/n (used by permission: Dresser-Rand Corporation).

hydraulic perfection of the compressor, and the value remains the same for any gas and for any speed (within reasonable limits) [65]. For an uncooled compressor, the polytropic, hydraulic, and temperature rise efficiencies are the same [108].



Ep =

n( k − 1) k (n − 1)

(17.98)

Values of Ep usually average between 0.77 and 0.82. For estimates, a value of 0.72–0.75 is reasonable. Polytropic efficiency can also be defined as follows [108].



ep =

ln[(P2 / P1 )( k −1)/k − 1] ln(T2 (actual)/ T1 )

(17.99)

Figures 17.76 and 17.76A give the relationship between polytropic and adiabatic efficiencies. The adiabatic efficiency can be calculated from operating data, and the polytropic efficiency can be read from the curves. For other cases, Ep may be calculated from the preceding relation and the adiabatic efficiency may be determined from the curves. Figure 17.77 illustrates the relationships that may exist while evaluating a particular compressor design.

Head An important point to remember when calculating is that when you are using adiabatic head, use adiabatic efficiency; and when using polytropic head, use polytropic efficiency [50]. Adiabatic Head. The height in ft of gas “supported” at the compressor discharge as the gas discharges into a system at the desired pressure level is the adiabatic head. The compression of the gas column is adiabatic. The temperature and pressure of the compression column will be related by the adiabatic expression. Adiabatic head is expressed [50]:

702  Petroleum Refining Design and Applications Handbook Volume 2 100 90 80 70 50

0 15

60

V=

0 10

40

WHERE T = 460 + °F P = 144 × PSIA

50

SPECIFIC VOLUME (CU FT/LB)

0

30

1545 × T MOL. WT. P

20

TE

M

PE

RA TU

RE

10 9 8 7

(F

)

0

15

6

0

10

5

50

4

0

3

EI

50 PRESSURE (PSIA)

T GH

R LA

CU

40

W

6

7

8

9 0 1

12

E OL

M 30

20

10

Figure 17.75  Specific volume chart (used by permission: © Elliot Co.).

14 6 1 8 1 0 2 2 2 4 2 6 .9 2 8 2

60

60

A.

5

3 4 5 3 0 45 0 5 55 0

100 90 80 70

R

2

Compression Equipment  703 1.00 .98

.94

1.05 1.10 5 1.1 1.20

5 1.2 0 1.3

.92

0

1.4

.86

1.6

.88

0

1.5 0

.90

1. 1.8 75 0

Ratio:

Adiabatic Efficiency

Polytropic Efficiency

.96

φ = 1.0

.84 2.0

φ=

.82 .80 .60

P

( P21 )

k–l k

.80 .70 Polytropic Efficiency

.90

Figure 17.76  Relationship between adiabatic and polytropic efficiencies (used by permission: Woodhouse, H. Petroleum Engineer, Oct. 1953. © Hart Publications, Inc. All rights reserved).

68

70

72

74

POLYTROPIC EFFICIENCY (ηp) 76 78 80 82 84 86

88

66

7

66

AD

IAB

AT IC

EX

PO

NE

NT

(K)

1.

5 1.6 0 1.6 5 1.5

0

1.5

5

1.4

0

1.4

5

1.3

1.30

MOLLIER EXAMPLE

1.25

1.20 1.15 1.10 1.05

1.0 2.0 3.0 4.0 5.0

6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 PRESSURE RATIO (rp)

55

60

65 70 75 ADIABATIC EFFICIENCY (ηad)

80

Figure 17.76A  Polytropic to adiabatic efficiency conversion (used by permission: Bul. P – 26 and P-11A, © 1996. Elliot Co.).

85

90

704  Petroleum Refining Design and Applications Handbook Volume 2 Polytropic

80

Efficiency, %

78 Adiab at

ic

Over

76

all Ad

74

iabat

ic Sh

aft

72 70

1.0

2.0

3.0

4.0

5.0

Pressure Ratio

Figure 17.77  Comparative efficiencies of a 1550 bhp centrifugal compressor based on 80% polytropic efficiency (used by permission: Woodhouse, H. Petroleum Engineer, Oct. 1953. © Hart Publications, Inc. All rights reserved).

( k −1)/ k  Z + Z   k   P2  d   Ha = 144 P1 v s  − 1  s  , ft-lbf /lbm or ft    k − 1   P1  2  

(17.100)



( k −1)/ k  Z + Z   k   P2  d   s 1 Ha = RT1  −  , ft-lbf /lbm or ft  k − 1   P1   2   

(17.101)



( k −1)/ k   k   P2  1, 545   Ha = T2  − 1 Z1 , ft-lbf /lbm or ft  (mol wt )  k − 1   P1  

(17.101A)

or,

where Ha = total head in ft, equal to work of compression in ft-lbf/lbm or ft R = gas constant = 1545/mol wt T = temperature, °R = (°F + 460) k = cp/cv, for gas Z1 = compressibility factor, dimensionless P1 = inlet pressure, psia P2 = discharge pressure, psia vs = specific volume of gas at suction conditions, ft3/lbm 1 = inlet or suction 2 = outlet or discharge

Adiabatic Head Developed per Single-Stage Wheel The head developed by a single stage of compression, consisting of an impeller and diffuser, depends upon the design, efficiency, and capacity and is related to its speed [66].

(Had)s = Ha = μu2/g, ft. where μ

= pressure coefficient, values range 0.50–0.65 for radial and forward-swept blading

(17.102)

Compression Equipment  705 u g υ N π d (Had)s

= rotor peripheral velocity, ft/s, values range 600–900 ft/s = acceleration due to gravity, 32.2 ft/s2 = Nπd/720 = impeller tip speed, ft/s = rotational speed, rpm = 3.141529 = impeller tip diameter, in. = adiabatic head developed by a single centrifugal stage, ft-lbf/lbm, or ft

An average value is about 0.55 for the coefficient, μ. Peripheral velocities will usually vary between 600–900 ft/s; however, this varies with the gas being compressed and may run up to 1100 ft/s. The results of this head calculation will give values of 8000–12,000 ft for a single stage. From this value, the total number of stages in the compressor can be approximated.

Polytropic Head The polytropic head more closely approaches the conditions of an actual compressor and is the actual height of a gas column that can be maintained at the compressor discharge flange in order to support a particular pressure. The compression of the gas follows a polytropic path [11]. ( n−1)/ n  Z + Z   n   Pd  s d   H p = 144 P1 v s  − 1   , ft-lbf /lbm or ft  n − 1   P1  2  



(17.103)

or: ( n−1)/ n  ft-lb  n   Pd  f   Hap = Z1RT1  − 1 , or ft   n − 1   P1  lb  m  (17.104)           ( n−1)/ n       1, 545 Z1T1 n P2 ft-lbf − 1 , = or ft     (mol wt ) n − 1  P1   lbm

where Zm

= compressibility factor of gas, expressing deviation from perfect gas law, at suction conditions to each wheel, if multistage unit, (Zs + Zd)/2

Polytropic head = adiabatic head/ea vs = specific volume of gas at suction conditions, ft3/lb n = polytropic exponent Hp = polytropic head, ft-lbf/lbm= ft. Pd = discharge pressure, psia T1 = inlet temperature, °R Figure 17.78 is convenient to use in approximating the polytropic head.

Brake Horsepower The power requirement for compression (only) of an ideal gas [67].



hpid =

144 P1V1  n  ( n−1)/n − 1   R c 33, 000  n − 1 

(17.105)

706  Petroleum Refining Design and Applications Handbook Volume 2 9

8

6

7

5

4

3

2

1

10

20

30

40

50

60 70 80 90 100

8

6

7

0 50 10 15 0 0

14

9 10

12

TE N

0 50 10 15 0 0

SU

CT

IO

55

60

M

PE

RA TU

RE

24 26 35 28. 9 40 30 (A. R ) 45 50

16 18 20 22

M

OL

EC

UL A

RW

EIG

HT

5

HEAD (1000 FT)

1.6

1.7

1.8

1.1 1.2 1.3 1.4 1.5

9

n = 1.0

10

8 P2 7 P1

6 1.4

75

70

60

5

CY

80

4

1

Figure 17.78  Approximate head selection (used by permission: Elliot® Co.).

EF F

1.1

%

2

1.0

1.1

k 1.2

IC IEN

3

1.3

1.0 1.2 1.3 1.4 1.5 1.6 1.7

n

Compression Equipment  707 where hpid P V1 Rc n 1 2

= ideal compression horsepower = pressure, psia = inlet volumetric flow rate, ft3/min = compression ratio, P2/P1 = polytropic exponent of compression = inlet condition = discharge or exit condition

For several stages of compression the differences between the polytropic and adiabatic efficiency can become significant, due to the variation from the ideal compression, which gives an increase in the temperature of compression that results in an increase in the volume of gas at the exit from each stage. This requires the following stages to do more work when compared to all stages being ideal. For an ideal compression using enthalpy change [67]:

hpad =

where Δh v2 V1 Ep hpad

V1 (∆h ) 42.42 v 2 E p

(17.106)

= enthalpy change, Btu/lb, from condition 1 to condition 2 = specific volume, ft3/lb = volumetric flow rate, ft3/min = polytropic efficiency, fraction = adiabatic horsepower

The actual horsepower input to the compressor shaft is the sum of the gas compression horsepower plus losses from the compressor wheel friction, fluid friction, gas turbulence, gas by-passing internally, and seal and bearing friction.

Gas hp = (hpg ) =



       

 Btu lb hp ft − lbf  778(h 2 − h1 )W = ∆h W / 42.8  • • •  Btu  33, 000  lb min ft − lbf   min

(17.107)

 Gas hp = (hpg) = (W)(Hp)/(33,000)(Ep) (17.108)

 Actual shaft bhp = hpg/(0.99 to 0.97)

(17.109)

        ghp = gas horsepower net to shaft from driver,

     

ghp =

( W )(∆H) (33, 000)(E p )

(17.110)

Ep = polytropic efficiency Actual horsepower required by rating of driver (minimum),



= Hp = polytropic head ME = mechanical efficiency

Gas Horsepower ghp = Mechanical Eff . 0.99 to 0.97 est.

(17.111)

708  Petroleum Refining Design and Applications Handbook Volume 2 This is approximately correct because the mechanical losses in the compressor are only about 1–3% [65, 66]. The head determined from Figure 17.78 can be used for the polytropic gas horsepower relation given previously. If the polytropic head and efficiency are known, these values can be substituted in [40]

              hpg = HadW/(33,000)(ea) (17.112) For the adiabatic values:



Hideal = Had/ead = Hpoly/Epoly = work input/lb fluid

(17.113)

Because the H/e versus Q relationship is nearly linear, the HPg versus Q is essentially a straight line through the origin for a compressor with radially bladed impellers. For backswept impeller blades, the hpg versus Q curve is a flat parabola, peaking near or above the maximum flow [40]. Shaft horsepower is greater than gas hydraulic (hpg) horsepower due to the effects of bearings, seals, and windage (or wheel friction losses). Although these losses can be determined individually, the sum of all amount to 1–3% of rated gas (hpg) horsepower on large- to medium-size compressors [40].



 P  ( n−1/)n   (Z + Z )/ 2  2 − 1  1 P1V1[n / (n − 1)]  2   Z1  P1     bhp = 229(E a )

(17.114)

where W = flow rate of gas, lb/min h1, h2 = enthalpy, inlet and discharge, Btu/lb Δh = enthalpy change, Btu/lb hpg = gas horsepower = hydraulic horsepower Hp = polytropic head, ft of fluid, Eq. 17.103 Ep = Hydraulic or polytropic efficiency, usually 0.70–0.80 bhp = brake horsepower at compressor shaft Brake horsepower per 1 million ft3/day measured at 14.7 psia and suction temperature using 75% overall compressor efficiency is given in Figure 17.79, and a volume correction factor is shown in Figure 17.80.

Centrifugal Compressor Approximate Rating by the “N” Method Outline adapted by permission of Elliott Co. [68]. 1. D  etermine mixture properties of gas or gas mixtures 2. Determine inlet flow as Q taking into account the compressibility factor, Z. 3. Select a compressor frame as in Table 17.9B and note the average polytropic efficiency listed, speed, and head/stage. 4. Calculate average gas compressibility (inlet + outlet)/2. 5. Calculate polytropic head, Hp, using Eq. 17.103. Calculate discharge temperature to be certain that no internal or separate outside cooling is required, such as in Figures 17.51C and 17.51D. n−1 n



P  T2 = T1  2   P1 



T = °R = (°F + 460), and P = psi, abs



(17.115)

Compression Equipment  709

190 180 170 160 150 140 130 120 110 100 90

R = 2.9 R = 2.7

80 60 50 40 30

R = 4.30 R = 4.10 R = 4.0 R = 3.9 R = 3.8 R = 3.7 R = 3.6 R = 3.5 R = 3.4 R = 3.3 R = 3.2 R = 3.1 R = 3.0 R = 2.9 R = 2.8 R = 2.7 R = 2.6 R = 2.5 R = 2.4 R = 2.3 R = 2.2 R = 2.1 R = 2.0 R = 1.9 R = 1.8 R = 1.7

1.8 1.7 1.6 1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8 0.7 0.6 0.5

R = 1.5

0.4 0.3

R = 1.3

0.2 0.1

10 0

2.1

1.9

R = 1.5

20

R = 4.50

2.0

R = 2.5 R = 2.4 R = 2.3 R = 2.2 R = 2.1 R = 2.0 R = 1.9 R = 1.8 R = 1.7

70

2.2

R = 1.1

0

0.1

0.2

0.3 0.4 (n–1)/n

0.5

Compression Ratio

200

=β

Required Brake Horsepower/1 Million cu. ft./day Measured of 14.7 psia & Suction Temperature (Compressor – 75% Eff.)

210

R = 4.70

2.3

(n–1)/n

R = 6.9 R = 6.7 R = 6.5 R = 6.3 R = 6.1 R = 5.9 R = 5.7 R = 5.5 R = 5.3 R = 5.1 R = 4.9 R = 4.7 R = 4.5 R = 4.3 R = 4.1 R = 3.9 R = 3.7 R = 3.5 R = 3.3 R = 3.1

220

R(n–1)/n–1

230

R = 1.1

0 0

0.6

0.1

0.3

0.2

0.4

0.5

(n–1)/n

Compressor Bhp/M2 cfd Correction Factor

Figure 17.79  Brake horsepower per million ft3 per day for compressors as a function of (n − 1)/n value (used by permission: Dresser-Rand Company).

1.08 1.06 1.04 1.02 1.00 0.98 0.96 0.94

1.5

2.0

3.0

10 Suction Volume, Mcfm

20

30

40

60

Figure 17.80  Correction factor for compressor bhp/million ft3 per day at 14.7 psia and suction temperature versus volume (used by permission: Dresser-Rand Company).

710  Petroleum Refining Design and Applications Handbook Volume 2 6.



 etermine the number of casing stages required. D Using Table 17.9B, determine nominal speed. Calculate Q/N. Then, pick H/N2 from table.

H/stage = (H/N2)(N2), ft-lbf/lbm, or ft

(17.116)

Approximate number of stages = Hp calculated in (5); divide by H/stage calculated previously = No. stages

7. A  djust speed based on casing stages. No. stages from (6) must develop head from (5) or determine average head/stage = Hp/no. stages = head/stage, ft-lbf/lbm or ft, per stage From the Fan Laws, H α N2. N = Nnominal[H(avg/stage)/H], rpm 8. Approximate power required.

Gas horsepower =



( w 1 )(H p )(from (5)) (33, 000 E p )

(17.117)

9. Adjust for balance piston leakage.



= (ghp)(1.02) = corrected ghp = (a)

(17.118)

10. Add losses from Figure 17.81B = (b). 11. Total shaft or brake horsepower:



= (Corrected ghp, (a)) + (Losses, (b))

(17.119)

The use of an enthalpy diagram or Mollier chart is perhaps the most accurate and is an easy method for determining horsepower. Figure 17.81 illustrates the compression paths on an ammonia diagram.

Compressor Calculations by the Mollier Diagram Method Figure 17.81A illustrates the basic concepts of using the Mollier diagram to solve centrifugal compressor problems. The steps involved using this method are [68] as follows (adapted from Elliott® Co. Reference [68] by permission): 1. Determine inlet flow, Q. Q1 = v1(w), volumetric flow rate, ft3/min w  = mass flow rate, lb/min v1   = inlet specific volume, ft3/lb On Mollier Diagram, Figure 17.81A, locate inlet state point (1) at intersection of p1 (psia) and t1 (°F). 2. Select the compressor frame from Table 17.9B for a typical example, not attempting to promote any particular manufacturer (each manufacture has its own tables). Based on the inlet volume and the required discharge pressure, select frame size. 3. Calculate adiabatic heat (Had) Read inlet enthalpy, h, directly below point (1) (see Figures 17.81A and 17.76A). Follow the line of constant entropy (s) to discharge pressure, p2, locating adiabatic discharge state point (2ad). Read adiabatic enthalpy (h2nd) directly below point (2ad).



Then, Δhad = h2ad − h1, Btu/lb

Compression Equipment  711 Discharge Point

400 350 300

Critical Point

ali ty

200

Qu

Temperature, °F

250

150

d ui

100

ed

at

ur

t Sa

50

Liq

Adiabatic Isothermal

0 Sa tu rat ed Va p

–50 –100 –0.1

or

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8 0.9 1.0 S, Bfu/lb.–°R.

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

Figure 17.81  Entropy–temperature diagrams help to solve compression work problems. Data for ammonia provided (used by permission: Corrigan, T. E and A. F. Johnson, Chemical Engineering, V. 61, No. 1, © 1954. McGraw-Hill, Inc. All rights reserved).

CRITICAL POINT

2 2

12

204

P2 SATU R VAPO ATED R LIN E

V

2

2

V1

11

V

2

V

2

2

V

P1 1

ENTHALPY (BTU per LB) 35

CONSTANT VOLUME LINES

PRESSURE (psia)

V2

S INE YL OP TR EN NT STA

N CO

CONSTANT TEMPERATURE LINES 1 1 1 1

V

h204

h1 ∆h04

h2

∆h

Figure 17.81A  Basic concepts for solutions using the Mollier diagram of a specific process gas (or gas mixture when diagram is available) (used by permission: Bul. P-11A. © 1966. Elliot® Co.).



Conversion: 1 Btu = 778 ft-lbf  Btu ft − lbf Then Had = (∆h ad )(778),  •  lbm Btu



  ft , adiabatic 

At polytropic efficiency from Table 17.9B, using Figure 17.76A, read adiabatic efficiency, Ead.

(17.120)

712  Petroleum Refining Design and Applications Handbook Volume 2 LABYRINTH, DRY CARBON RING OR GAS FACE SEAL

ISO-CARBON OR ISO-SLEEVE SEAL

160

160

140

140

29-

46M

MO

60

LOSSES (HP)

38MB 3 R2 5-M 2-MB B

46MB

OR

OR 46M

60M

40

29M

38M

40

80

38M

OR

60MB

70MB

OR

60M

88M

100

70M

60

88M

80 110 103 M -M

LOSSES (HP)

OR

100

120

88MB

This chart for atmos. pressure. Add 5% for each additional 100 psi suction pressure.

70M

120

30

30 1000

2000 4000 OPERATING SPEED (r/min) For 10MB, 15MB and 20MB, use 40 HP for losses.

6000

8000 10,000

1000

2000 4000 OPERATING SPEED (r/min)

6000

8000 10,000

Figure 17.81B  Typical mechanical losses for seals on shafts of centrifugal compressors (used by permission: Bul. P-26. Elliot® Co.).

4. Polytropic Head (Hp)

Hp =



Had (E p ) , see + + in 7 E ad

(17.121)



Determine k for the specific heat for gas or gas/vapor mixture from Table 17.4 or other sources. Calculate the compression ratio, Pd/Ps = P2/P1 = Rc. From Table 17.9B for the compressor frame selected, select polytropic efficiency, Ep, and using Figure 17.76A, determine adiabatic efficiency, Ead. 5. Number of Casing Stages From Table 17.9B select the nominal speed for the size compressor casing (frame) established in Step 2.



No. Stages =

H p (from Step 4 ) [maximum head per stage (Table 17.9B)]

(17.122)

From Table 17.9B, H/N2 = x

Hp/stage = head/stage = (H/N2)(N2) = (x) (N2), ft-lbf/lbm**

(17.123)

N from Table 17.9B No. casing stages = Hp/(head/stage), stages rounded up to nearest whole number 6. Adjust speed. (No. stages from (5) must develop, Hp, ft (from Step 4) = ft-lbf/lbm Average head/stage = Hp/(no. stages) = ft-lbf/lbm per stage* From Fan Law, H α N2, then required speed, N = Nnominal (from Table 17.9B)

Compression Equipment  713 12

[Hreq'd avg ./stg .* , actual above ]     [H p.(calc . Step 5 ,** above) ] 



(17.124)

7. Gas horsepower

ghp =



w 1 (H p ) = horsepower , ghp, + + see Step 4 33, 000(e p )

(17.125)

8. Shaft horsepower



shp = total horsepower required to compressor shaft



shp = gas hp + bearing + oil seal losses + balance piston leakage



Balance piston leakage = 1.02 (ghp) (balanced piston hp)



Add losses from Figure 17.81B = y, then,



Total shaft horsepower = (balanced piston leakage, Bal PHP) + y

(17.126)

9. Actual discharge enthalpy, h2

 ∆h  h 2 =  ad  + h1  E ad 

Δhad = from Step 3.

(17.127)

Ead = from Step 4. 10. Discharge Temperature, t2 In Figure 17.81A (Mollier Diagram), plot vertically from h2 (Step 9) to discharge pressure, p2. At this point, read discharge temperature, t2, following temperature lines. 11. Discharge specific volume From Step 10 at point (2), in Figure 17.81A, read discharge specific volume, v2. (17.128) 12. Discharge flow, Q2 = (w) (v2), ft3/min at discharge conditions where Q = capacity flow, ft3/min w = mass flow rate, lb/min v1 = specific volume, ft3/lb, inlet v2 = specific volume, ft3/lb, outlet P = p = inlet pressure, psia H = head, ft-lbf/lbm = ft h = enthalpy, Btu/lb e or E = efficiency, fraction Rc = ratio of compression = Pd/Ps = P2/P1 t = temperature, °F T = temperature, °R = (°F + 460) N = speed, rpm, (revolutions/min) ghp = gas horsepower shp = shaft horsepower

714  Petroleum Refining Design and Applications Handbook Volume 2 Subscripts: ad = adiabatic p = polytropic 1 = inlet 2 = outlet d = discharge s = suction The initial and final enthalpy values can be located, and the Δh can be calculated.

Example 17.8: Use of Mollier Diagram (Reproduced by permission on Elliott® Co. Bul. P – 26, 15-194FL) An ethylene gas centrifugal compressor required the following operating conditions: Flow: w1  = 1769 lb/min Inlet pressure: P1  = 80 psia Inlet temperature: T1  = 90°F (550°R) Discharge pressure: P2  = 225 psia 1. Calculate inlet volume. v1 = 2.6 (from Mollier Diagram) Q = w1 × v1 = 1,769 × 2.6 = 4600 icfm (inlet ft3/min, which is actual ft3/min (acfm)): acfm = [scfm @ 60°F, 14.7 psia and dry] × Ps/P1 × T1/Ts × Z1/Zs where Ps = standard pressure, usually 14.7 psi absolute P1 = inlet pressure, psi absolute Ts = standard temperature, usually 520°R= (°F + 460) T1 = inlet temperature, °R = (°F + 460) Z = compressibility, 1 = inlet, s = standard, usually 1.0 2. S elect compressor frame size. Based on an inlet volume of 4600 icfm and knowing the required discharge pressure is 225 psia, select a 29M frame size from Table 17.9B. 3. C  alculate the required head. At given inlet conditions, determine inlet entropy (s) and enthalpy (h) from Mollier Diagram: P1 = 80 psia T1 = 90°F s1 = 1.75 h1 = 163 Btu/lb

At required discharge pressure and constant entropy (s1 = s2), determined h2 from the chart.

P2 = 225 psia T2i = N/A

Compression Equipment  715 s2 h2i Had Had

= 1.75 = 205 Btu/lb = head required = 778 (h2i − h1) = 778 (205 − 163) = 32,676 ft-lbf/lbm (adiabatic)

Check the discharge temperature for a need to intercool. (Cool if T2 > 400°F.) Step 1. Determine adiabatic efficiency. Rc = 225/80 k = 1.24 ηp = 0.78 (from Table 17.9B) ηad = 0.76 (from Figure 17.76A) Step 2. Determine actual (not isentropic) Δh.



Δh = (h2i – hi)/ηad = (205 − 163)/0.76 = 55.3 Btu/lb Step 3. Determine h2 and read T2 from Mollier Diagram.

h2 = h1 + Δh = 163 + 55.3 = 218 Btu/lb Plot vertically from h2 to P2 (225 psia) and read T2 along temperature lines (not on vertical or horizontal scales). T2 = 232°F (from Mollier Diagram) No isocooling is therefore required. 5. D  etermine the number of casing stages. From Table 17.9B, the nominal speed for a 29M is 11,500 rpm. Convert adiabatic head to polytropic head by the ratio of efficiencies.

Hp = 32,676 (0.78/0.76) = 33,536 ft From Table 17.9B, H/N2 = 7.5 × 10−5 Therefore,

H/stage = H/N2 × N2 = (7.5 × 10−5)(11,500)2 = 9,919 ft-lbf/lbm Determine approximate number of casing stages. Number of stages = 33,536/9919 = 3.38 ≅ 4 stages 6.

Adjust speed. Adjust the nominal speed according to the casing stages. 4 stages must develop 33,536 ft-lbf/lbm or an average of 33,536/4 = 8384 ft-lbf/lbm per stage Using Fan Law relationships, adjust speed:



H α N2



N = Nnorm [Hreq’d/H]1/2 = 11,500[8384/9919]1/2

  = 10,573 rpm 7. Calculate the approximate gas horsepower.

716  Petroleum Refining Design and Applications Handbook Volume 2



ghp 8.

w1 H 33, 000 e p

1769 33, 536 33, 000 0.78

2, 305 hp



S haft horsepower Total shaft or brake horsepower = (adjust, leakage plus losses) shp = total shaft horsepower = balanced piston leakage (Bal. PHP) + y = 2351 + 70 = 2421 shp Adjust for balanced piston leakage.



2,305 × 1.02 = 2,351 hp = (a)

Adjust losses from Figure 17.81B for assumed isocarbon seal. y = 70

9. Actual discharge enthalpy, h2; see Paragraph 3, Step 3. 10. Adiabatic head, see Paragraph 3. 11. Polytropic head, see Paragraph 5. 12. Discharge temperature T2. Plot h2 (Step 3) at discharge pressure of 225 psia on ethylene Mollier Diagram; read T2 = 235°F 13. Discharge specific volume. Read v2 = 1.15 ft3/lb at point of Paragraph 12. 14. Discharge volume. Q2 = (w)(v2) = (1769)(1.15) = 2,034 ft3/min at discharge conditions

Example 17.9: Comparison of Polytropic Head and Efficiency With Adiabatic Head and Efficiency A process system is planned to operate as follows: Inlet: P1 = 14.5 psia; v1 = 15 ft3/lb Discharge: Pd = 42.0 psia; k = 1.41 Polytropic efficiency = 75% Specific volume = 15.8 ft3/lb Determine: Polytropic head, adiabatic head, and adiabatic efficiency. Compression ratio: = 42/14.5 = 2.896



n/(n − 1) = k(Ep)/(k − 1)



n/(n − 1) = 0.75(1.41)/(1.41 − 1) = 2.579



n = 2.579n − 2.579



n = 1.633



(n − 1)/n = 1/(2.579) = 0.387 Polytropic head:



 = 144(p1v1)(n/(n – 1)) [pd/p1](n−1)/n – 1]; (omit “Z” for low pressure)



= 144(14.5)(15)(2.579)[2.8960.387 − 1]



= 41,122 ft

Compression Equipment  717 Assuming one pound basis:

[hpg/Ep] (No. lb, flowing/min)

Shaft work = 1(41,122)/0.75



= 55,000 ft-lbf/min



1 hp = 33,000 ft-lbf/min 55, 000 (Assum mech./hydraulic eff . = 0.98) 33, 000 = 1.70 hp

shaft horsepower =



Adiabatic head: Determine adiabatic k. From Eq. 17.98,



 k   n    E p =   k −1 n − 1  k  1  1.633    =   k −1 0.75  1.633 − 1 



= 3.439



k = 3.439k − 3.439



k = 1.41





(k − 1)/k = 1/3.439 = 0.291



Adiabiatic head = 144 k/(k − 1)(p1v1)[(pd/p1)(k − 1)/k − 1]



= 144(3.439)(14.5)(15)[(2.8960.291) − 1]



= 39,026 ft



Adiabatic efficiency: = (39,026/55,000)(100) = 70.9%



Adiabatic shaft work = 39,026/0.709 = 55,000 ft-lbf/min



Shaft horsepower = 55,000/(0.98) (33,000) = 1.70 hp



1 hp = 33,000 ft-lbf/min



718  Petroleum Refining Design and Applications Handbook Volume 2

Speed of Rotation The maximum speed of a compressor is fixed by mechanical or structural limiting of the peripheral velocity of the impeller wheels. The required velocity is established by the head to be developed. The capacity of the machine at suction conditions is a function of the individual wheel designs and the diameter [65, 66]. Peripheral velocity (or tip speed)



υ = πD (rpm)/720, ft/s



π = 3.1416

The tip speed of an impeller is a crude guide as to the relative conservatism in its rating in the compressor case when reviewed on a competitive basis between different makes or designs. The feeling exists that the lower the tip speed, the better the design, and the longer the unit will run with trouble-free service. This is only partially true, if at all, as the real factors lie in the structural design together with materials of construction. The rotor assembly life is a function of a bearing size and design.

rpm =

where rpm υ D H′ μ T

1300 H′ = 229.3 υ/D D µ

(17.129)

= rotative speed, revolutions per minute = peripheral velocity, ft/s = impeller diameter, in. = head per stage, ft of liquid = pressure coefficient, average value 0.55 = absolute temp., °R, t = °F

Temperature Rise During Compression Adiabatic discharge temperature, T2:

 P  ( k −1) k   2  − 1  P1   T2 = T1 + T1 E ad



(17.130)

Polytropic:

P  T2 = T1  2   P1 

where T Sub-1 Sub-2 R

= absolute temp. °R = suction or inlet = discharge = 1544/MW

( n−1)/ n



(17.131)

Compression Equipment  719 The values for polytropic conditions represent an uncooled compressor, that is, no internal diaphragm cooling, no liquid injection, and no external coolers for the pressure range being considered. Adiabatic [50].

T2 = T1



[(P2 / P1 )k −1/k − 1] + T1 E ad

(17.132)

The discharge must be the same regardless of whether the process is considered adiabatic or polytropic. Thus [50],

T2 = T1 (P2 / P1 )n−1/n =



T1[(P2 / P1 )k −1/k − 1] + T1 E ad

(17.133)

Relationship between adiabatic compression and polytropic compression [29].

( k )E p n = n − 1 ( k − 1)

where n k Ep Ead

(17.134)

= polytropic efficiency coefficient for compression = adiabatic efficiency coefficient for compression = ratio of specific heats, cp/cv = polytropic efficiency, fraction = adiabatic efficiency, fraction

Polytropic efficiency may range from 77–82%, from Elliott [29]. Figure 17.22 is convenient for solving for the temperature rise factor for either polytropic or adiabatic conditions, depending upon whether k or n is used. Figure 17.82 can be used to solve for polytropic discharge temperature directly. Note the temperature limit line of 450°F, applicable to most mechanical designs.

Sonic or Acoustic Velocity The velocity of sound, Vs, in any gas may be calculated from

Vs = [k(32.2)(R)(T)(Z)]1/2, ft/s

(17.135)

where k = ratio of specific heats, cp/cv R = gas constant = 1545/mol wt T = average absolute temperature of gas, °R, or may be calculated at suction temperature Z = compressibility factor for gas at temperature, T p = absolute pressure, lbf/ft2 abs γ = specific weight of gas, lb/ft3 g = acceleration due to gravity = 32.2 ft/s2 or, Vs = [kgp /γ]1/2, ft/s General design practice avoids using gas velocities near or greater than the sonic velocity. Figure 17.83 indicates the effect of temperature on the sonic velocity.

720  Petroleum Refining Design and Applications Handbook Volume 2

50

AT U

TEMPERATURE LIMIT

PE R

0 n–1 P2 n NOTE: T2 = T1( P ) 1

TIO N

TE

M

400

300

SU C

DISCHARGE TEMPERATURE – T2 (F)

RE

–T

500

10

1( F)

0

15

0

600

200

100

8

P2/P1

7

1.5

1.3

1.2

1.6

1.7

1.8

n VALUES

9

1.1

10

1.4

0

6 5 4 3 2

Figure 17.82  Polytropic compressor discharge temperature (used by permission: Elliot® Co.).

Example 17.10 A centrifugal compressor is to be specified for a gas plant. The unit is to compress 18,000 lb/h of gas mixture at 50 psia and 150°F to 200 psia. The gas mixture consists of 30% hydrogen (H2), 45% methane (CH4), 15% ethane (C2H6), 7% propane (C3H8), and 3% n-butane (nC4H10). Assuming a polytropic efficiency of 75%, Z1 = 0.97 and Z2= 0.93, calculate the polytropic head, total break horsepower, and the discharge temperature. Table 17.10 gives the properties of the gas mixture.



k=

MC p MC p = MC v MC p −1.986



k=

10.317 = 1.238 8.311

The average molecular weight, Mw = 17.162



Compression Equipment  721 6,000 5,500 n

roge

Hyd

5,000 4,500

Velocity, ft./sec.

4,000 3,500 3,000

droge 90% Hy

n + Hyd

rocarbo

ns

2,500 n Gas Coke Ove

2,000

Natural Gas

1,500

Air Carbon Dioxide

1,000

Propane

500 0

0

50

100

150

200 250 300 Gas Temperature, °F.

350

400

450

500

Figure 17.83  Sonic velocity of common gases (used by permission: Koenig, C. F.III. Refining Engineer, Aug. 1958. © Hart Publications, Inc. All rights reserved).

Table 17.10  Properties of the gas mixture.   Btu MCp  o  lb mol R  m 

Mole fraction

Molecular weight

Gas

y

Mw

yMw

psia

Tc (°R)

@ 150°F

@ 150°F

H2

0.30

2.01

0.603

188.1

60.2

6.94

2.082

CH4

0.45

16.04

7.218

666.0

343

8.95

4.028

C2H6

0.15

30.07

4.511

707

550

13.78

2.067

C3H8

0.07

44.09

3.086

616

660

19.52

1.366

nC4H10

0.03

58.15

1.744

551

765

25.81

0.774

Mw =

17.162

MCp =

10.317

Total

Pc

yMCp

Solution The computer program COMPIMP has been developed that calculates the polytropic and adiabatic heads of a compressor. Table 17.11 shows the input data and results of the gas mixture. The gas discharge temperature is 310.4°F, and the compressor polytropic head is 76,874 ft with a total brake horsepower of 912 hp. Table 17.11A shows the specification data sheet of Example 17.10.

722  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.11  Input data and computer results of Example 17.10. COMP.DAT Polytropic 18000.0 50.0 200.0 80.0 1.238 17.162 0.97 0.93 0.75 Polytropic compression calculation Type of service:

Polytropic

Gas flow rate, lb/h:

18,000.000

Inlet pressure, psia:

50.000

Outlet pressure, psia:

200.000

Compression ratio, Rc:

4.000

Inlet temperature, °F:

80.000

Polytropic exponent, n:

1.3447

Ratio of specific heat capacities, k:

1.2380

Molecular weight of gas, lb/lbmole:

17.162

Inlet density, lbm/ft^3:

0.1527

Inlet volumetric flow rate, ft.^3/min:

1964.937

Outlet density, lbm/ft.^3:

0.4464

Outlet volumetric flow rate, ft^3/min.:

672.056

Inlet compressibility factor, Z1:

0.9700

Outlet compressibility factor, Z2:

0.9300

Average compressibility factor, ZAV:

0.9500

Polytropic efficiency (%):

75.000

Calculated adiabatic efficiency (%):

71.577

Polytropic head, ft-lbf/lbm (ft).:

73,030.090

Adiabatic head, ft-lbf/lbm (ft).:

69,696.870

Outlet temperature, °F:

310.404

Work done, ft- lbf/lbm

461,906.200

Gas horsepower, hp:

885.213

Mechanical losses, hp:

26.556

Total brake horsepower, hp:

911.770

Compression Equipment  723

Mach Number [69] The ratio of the gas velocity at any point to the velocity of sound in the gas is known as the Mach number, M .

M = υ/Vs

(17.136)

υ = gas velocity at any point Vs = speed of sound in gas Usual practice uses the peripheral velocity υ, of the impeller as a criterion for establishing an approach to this number. This may not be the point of maximum velocity in the unit, and if it is not, the effects of the Mach number will show up with ratios less than 1.0. Values of 0.5–0.75 of M are usually used in the design as efficiency falls off near M = 1.0. At M values of 0.9–1.0 and above, the compressor wheel ceases to produce additional pressure and flow. The flow has reached its maximum. If the velocity of the gas/fluid equals or exceeds the speed of sound, shock waves are set up, and vibrations and other mechanically related problems may result, compared to the conditions when velocities are below the speed of sound [70]. For a Mach of 1.0, the gas velocity equals the velocity of sound in the fluid. For further details on compressible fluid (see Chapter 15).

Specific Speed Speed for centrifugal compressors as well as blowers, fans, pumps, and similar rotating and “pumping” equipment is a useful relative correlating factor. It is more important to detailed designers, although the concept is valuable in the performance evaluation of such equipment. At a given point, the specific speed correlates the important performance factors of adiabatic head, capacity, and rpm for geometrically similar wheels. The specific speed of all geometrically similar wheels is the same and does not change when the speed of the wheel size is changed. At the peak efficiency point, the wheels can be classified as to type and performance characteristics [1, 69].

Ns =

where V1 Ns Ha rpm

(rpm) V1 (Ha )0.75

(17.137)

= actual flow rate, cfm at suction conditions = specific speed, dimensionless = Total polytropic head of wheel, ft-lbf/lbm= ft. (adiabatic or polytropic) = actual speed of rotation revolutions/min

Specific speed is defined as the speed in revolutions per minute at which an impeller would rotate if reduced proportionately in size so as to deliver 1 ft3 of gas per minute against a total head of 1 ft of fluid [70]. Centrifugal compressors usually have specific speeds of 1500–3000 rpm at the high efficiency point. The axial flow fans and blowers are high specific-speed wheels; mixed flow units are lower; and the centrifugal compressor wheels are the lowest in specific speed range because they have narrow impellers.

Compressor Case and Impellers Tables 17.9A and 17.9B are a guide to a specific compressor case’s capabilities. This is not a standard for each manufacturer. On the contrary, they differ considerably. Figure 17.84 is also useful as a guide to inlet suction condition capacities for various case sizes. These case sizes have no relation to the cases in Table 17.9. Figure 17.85 is an approximate guide for the number of impeller wheels that will be required to develop the compression ratio, P2/P1, for a selected group of gases using uncooled compressors. That is, no diaphragm cooling or liquid

#3

Compressor Size

Compressor Size

724  Petroleum Refining Design and Applications Handbook Volume 2

#2 #1

2

4

6

8 10 12 14 Inlet Capacity, Mcfm

16

18

20

#7 #6 #5 #4

20

40

60 80 100 120 Inlet Capacity, Mcfm

140

160

Figure 17.84  Centrifugal compressor size versus capacity (used by permission: Dresser-Rand Company).

8

Compression Ratio

7 6

Suction Conditions: Pressure – 14.7 psia Temperature – 100°F Avg. “µ” Value – 0.55 Tip Velocity – 750 ft. /sec. Polytropic Eff. – 75%

5 4

ane Eth Air

3

al Gas Natur Methane

2 1

e

an

op Pr

1

2

3 Number of Impellers

4

5

6

Figure 17.85  Compression ratio versus number of impellers; uncooled compression (used by permission: Dresser Rand Company).

injection and no exterior cooling between wheels. This is the most common condition. Figure 17.86 is also useful in estimating wheel selection and head/stage or wheel, and the case numbers here agree with those in Figure 17.84. The need for and use of multiple inlets/outlets for centrifugal compressors become apparent when balancing process flow and pressure requirements. See the later discussion, and also refer to Figures 17.51B and 17.51D.

Example 17.11: Approximate Compressor Selection An air compressor is required to raise 4600 scfm of atmospheric air to 100 psig. The ambient summer temperature is 95°F dry bulb for 2 months and lower for the balance of the operating time. The air usually has a relative humidity of 65%, but during the “wet” season, the humidity may be 100% while the temperature is 95°F. The elevation is sea level; the barometer 14.7 psia. The continuity of air supply is very critical.

Approximate Selection for Preliminary Studies (Prior to Formal Inquiry to Manufacturers) Basis. 100% relative humidity at 95°F due to critical service. (For other applications an RH of 80% might be quite satisfactory.) 1. S uction Volume This volume, 4600 scfm (14.7 psia and 32°F), is dry and must be increased by the water vapor that will accompany it into the compressor suction [73].

Compression Equipment  725

 P  Vw = Vd  1   P1 − Pv′ 



(17.138)

where P1 = total pressure of system, psia Vw = volume of gas containing condensable vapor (water), ft3/min Vd = volume of dry gas (no moisture), cfm

10,000

Average “µ” Factors

9000

No. 1 No. 2 No. 3 No. 4 No. 5 No. 6 No. 7

8000

µ = 0.47 µ = 0.51 µ = 0.52 µ = 0.53 µ = 0.55 µ = 0.56 µ = 0.56

Head, ft/ lb./lb per Impeller

7000

6000 µ = 0.60 5000

µ = 0.58 µ = 0.56 µ = 0.54 µ = 0.52

4000

µ = 0.50 5000

2000

1000 300

400

500

700

600

800

Peripheral Velocity, fps 70 #7 – 66.0"

2,000 rpm 3,000 rpm

Impeller Diameter, Inches

60 #6 – 54.0" 50

4,000 rpm

#5 – 42.5" 40

5,000 rpm

#4 – 32.0" 30

6,000 rpm 7,000 rpm 8,000 rpm 9,000 rpm 10,000 rpm 11,000 rpm 12,000 rpm

#3 – 24.0" 20 #2 – 18.0" #1 – 14.75" 10 200

300

400

500

600

700

800

Peripheral Velocity, fps

Figure 17.86  Peripheral velocity or impeller tip speed versus head per impeller (used by permission: Dresser-Rand Company).

726  Petroleum Refining Design and Applications Handbook Volume 2



Pv′ = (Pv )(RH), psia Pv RH Pv Pv′

= vapor pressure of water vapor in the saturated gas at specified temperature, use steam tables, psia = relative humidity, fraction = 0.8153 psia at 95°F = (0.8153)(100) = 0.8153 (for 100% RH)

  14.7   460 + 95     14.7 Vw = (4 , 600)        14.7 460 + 32  14.7 − 0.8153   = 5494 scfm at 14.7 psia and 95°F



(17.139)



Suction volume also

V1 = Qs = Wv= W(ZRT1/144P1)

(17.140)

where W = mass flow rate, lb/min v = specific volume, ft3/lb R = gas constant, (ft-lbf )/(lbm)(°R) T1 = inlet temperature, °R P1 = inlet pressure, psia 2. Compression ratio

Rc =



14.7 + 100 = 7.8 14.7

This is too large for one wheel and indicates that an intercooler must be used between cases to cool the gas back to a reasonable temperature. Assume a 3% pressure loss between cases due to intercooling. The actual overall compression ratio for each of two cases will be

Rc =



or overall: R c =

7.8 = 8.04 0.97

7.8 = 2.84 0.97

3. Average molecular weight

Percent water vapor =



(0.0555)(18) = 1.0 (0.9445)(28.9) = 27.3



avg mol wt

= 28.3 (use this on chart)

4. Polytropic head (use chart in Figure 17.78)

(0.815)(100) = 5.55% ( volume) 14.7

Compression Equipment  727

For air, k = 1.40 Assume polytropic or hydraulic efficiency = 0.73 Reading chart, Figure 17.67, n = 1.65



From Figure 17.78, solving polytropic head equation:



At Rc = 2.84 and t1 = 95°F



H = 40,000 ft per case (two cases) 5. Discharge pressure from first case to intercooler



= (14.7) (2.84) = 41.7 psia

Pressure entering second case: Assume the 3% pressure loss (1% due to entrance and exit losses plus 2% due to intercooler and piping losses).



Suction pressure at second case:



= (0.97) (41.7) = 40.5 psia 6. Compression ratio across second case:



= (100 + 14.7)/40.5



= 114.7/40.5 = 2.83 7. Required polytropic head from second case:

Hp = 40,000 ft

This neglects the effect of moisture removal on molecular weight, assumes constant “k” and “n” values, and assumes the gas is cooled back to 95°F as it enters the second case.

8. Suction volume to second case: Assume intercooling of air down to 100°F.

  14.7   460 + 100     40.5 Volume = (4600)        40.5 460 + 32  40.5 − 0.9492  



V = 1942 cfm at 100°F and 40.5 psia saturated.

Reading Figure 17.78, Hp = 40,500 ft when the suction temperature is 100°F.

9. W  heel selection In actual design, the manufacturer uses wheel capacity data to properly select the sequence of wheels required to develop the head in each compressor case. Each wheel has its own efficiency at the rated speed (usually 70–75%). From Table 17.9, for an intake volume of 5494 cfm, Case No. D looks appropriate for the first case. Summarizing Case No. D:

728  Petroleum Refining Design and Applications Handbook Volume 2

No. stages per case max.: 7 Nominal overall eff, %: 77 Intake volume range: 3500–12,000 Nominal head per stage, ft: 8500 Nominal speed, rpm: 8100 Max. case pressure: 250 psi cast iron Number of wheels required per case before intercooling = 40,000/8500 = 4.7. Use five wheels in this case.



This requires a slight speed decrease or the selection of special impellers (at the rated speed) to ensure proper capacity and head. Uncorrected approximate speed





= nominal rpm required head /rated head 10. Uncorrected approximate speed



= (8100)

40, 000 = 7860 rpm (5)(8500)

This is acceptable. By returning the air after intercooling to the sixth wheel in the same case (when the case is so designed), or into the first wheel of a new second case, the following conditions exist. From Table 17.9A, the second case might be a No. E, based on inlet volume summarizing Case No. E:

No. stages per case max.: 8 Nominal overall eff. %: 73 Intake volume range: 1500–4500 Nominal head per stage, ft: 8000 Nominal speed, rpm: 9800 Max. case pressure: 250 psi Number of wheels required per case = 40,500/8,000 = 5.06. Use five wheels; the manufacturer can usually furnish wheels of sufficient capacity to make up the 1.2% increase in the five wheels. 11. Uncorrected approximate speed

= (8000)



40, 500 = 8050 rpm (5)(8000)

If the case were running below 100% speed, experience shows general multiplying correction factors must be applied to Factor Head

0.98

Efficiency

0.99

Compression Equipment  729

Corrections are necessary for the first case because its speed is below nominal. Therefore, total available head for Case 1:



= (0.98) (head summation of individual wheels)



= (0.98) [(5)(8500)] = 41,700 ft  40, 000 



Approximate speed case 1 = (8100)  = 7933 rpm  41, 700 

This is satisfactory. 12. For specific volume at suction conditions, use Figure 17.75. Mol wt at suction = 28.3 Temp. = 95°F Suction pressure = 14.7 psia Reading chart, specific volume = 14.3 ft3/lb 13. Mass flow rate



= (5494)/(14.3) = 384 lb/min, entering suction of first wheel of the first case. 14. Brake horsepower

bhp =



( W )(H) ufacturer's data for a specific case size) + Mechanical hp loss (from manu (33, 000)(e p )

Case 1 (384 )(40, 000) + 25 (assumed as a reasonable value) (33, 000)(0.77 ) = 630 hp

bhp =



If mechanical losses are assumed at 2%:

•

Bhp = (630 − 25)/0.98 = 617

This is about as close as approximate methods will check.

Case 2:

Mass flow rate = 384 lb/min





730  Petroleum Refining Design and Applications Handbook Volume 2

bhp =



(384 )(40, 500) + 25(assumed ) = 671 hp (33, 000)(0.73)

Total horsepower = 630 + 671 = 1301 bhp. 15. Alternate brake horsepower calculation: Using Figure 17.74 for air.



At k = 1.40



(n – 1)/n = 0.378

Solving:

n −1 k − 1 1.4 − 1 = 0.378 = = n kE p 1.4 E p

Ep = 0.756

n = 1.61

Case 1, using Figure 17.79:



bhp/MMCFD = 76 at Rc = 2.83, 14.7 psia and 95°F.

Flow at suction conditions:

MMCFD =



(5494 )(60)(24 ) = 7.91 106

Uncorrected bhp = (7.91) (76) = 601 hp (assumes 75% eff.) Correction factor from Figure 17.80. Suction volume = 5494 cfm Mcfm = 5.494 Reading curve:



Factor = 1.008



Corrected bhp = (1.008) (601) = 606 hp



Case 2:

bhp/MMCFD = 76 Suction to second case (actual conditions are 40.5 psia and 100°F):



 (1945)(60)(24)   40.5  MMCFD =    14.7  = 7.72 at 100°F and 14.7 psia 106  

Compression Equipment  731



Uncorrected bhp = (7.72)(76) = 587 From Figure 17.80, correction factor at 1.945 Mcfm Factor = 1.033 Corrected bhp = (1.033)(587) = 607 hp Total horsepower = 606 + 607 = 1213 hp Actually, because the alternate scheme is based on 75% efficiency, if the values are corrected for the differences in efficiency of the two individual compressor cases used, the results will be close enough for engineering application. As they stand, the bhp values cannot be resolved to a more accurate basis without specific data on case selection, efficiency, and losses.

16. Discharge temperatures From Case 1 with 95°F suction temperature, Rc = 2.84 P  Exit temperature = T2 = T1  2   P1 



( n−1)/ n



Use Figure 17.22 because this is an uncooled case, and compression is closer to polytropic.



At n = 1.61

Rc = 2.84

Temperature rise factor = R (cn−1)/n = 1.485 Exit temperature = (460 + 95) (1.485) = 824°R = 364°F



From Case 2, with 100°F suction temperature, Rc = 2.83

T2 = (100 + 460)(2.83(n−1)/n)

= 560(2.830.378)

T2 = (560)(1.48) = 830°R = 370°F

If the case had been cooled internally, then the isentropic “k” value can be used to calculate the temperature rise.

17. Estimating the number of wheels using Figure 17.84

First Case:



The polytropic head previously calculated = 40,000 ft At an inlet capacity to the case of 5494 cfm: Figure 17.84 reads greater than size No. 2, so use size No. 3. From Figure 17.86, it appears that about 9000 ft/stage is a reasonable maximum. The number of impellers based on this 9000 ft head per impeller = 40,000/9000 = 4.45, use 5. This is the same number reached by the other approach.



Head per stage = 40,000/5 = 8000 ft From Figure 17.86, the approximate wheel diameter for (first compressor) case size no. 3 is 24 in. dia. Peripheral Velocity. Figure 17.86

732  Petroleum Refining Design and Applications Handbook Volume 2

Because individual wheel information is not usually known, use μ (pressure coefficient) = 0.55; however, the data for case size No. 3 gives μ = 0.52.

Case 1: at 8000 ft/wheel and μ = 0.52 peripheral velocity = 710 ft/s Case 2: at 8100 ft/wheel, using case size No. 2 (Figure 17.84 for the second case). peripheral velocity = 720 ft/ s at μ = 0.51 for case No. 2 Speed. From Figure 17.86, the rpm is approximately 6800 rpm for a (first compressor) size No. 3 case. This is not unusual for different manufacturers to operate at significantly different speeds, as this is a function of wheel design.

Compressor Equations in SI Units Compressors are rated in kJ/kg of compression head developed. This is the energy conserved to a gas stream by a compressor. It is observed by the increase in gas pressure as the gas passes through the compressor. Centrifugal compressors more nearly follow polytropic operation and are widely used to handle large volumes of gas at pressure ranges of 7 bar to several thousand bar. There are two ways to carry out the thermodynamic calculations for compression, namely by assuming: 1. A  n adiabatic (isentropic) reversible path: a process during which there is no heat added or removed from the system. The entropy is constant. That is

pVk = constant

(17.141)

2. A  polytropic reversible path: a process in which changes in gas characteristics during compression are reviewed

pVn = constant

(17.142)

Relationships may be developed between the temperature, pressure and volume for a polytropic process between state 1 and state 2. The ideal gas law states that



pV = RT

(17.143)

p1V1n = p2 V2n

(17.144)

That is

or

p1 =



RT1 RT , p2 = 2 V1 V2

(17.145)

Rearranging p1 and p2 in Eq. 17.145 gives:



RT1  T  V  p1 V = 1 = 1 2 p 2 RT 2  T2   V1  V2

(18.146)

Compression Equipment  733 For a polytropic process between states 1 and 2, n

p1  V2  = p2  V1 



(18.147)

Substituting Eq. 17.146 into Eq. 17.147 gives: n

 T1   V2   V2   T   V  =  V  2 1 1



(17.148)

Therefore:

T1  V2  = T 2  V1 



n−1



(17.149)

or 1

 V2   T1  n−1  V  =  T  1 2



(17.150)

Substituting Eq. 17.150 into Eq. 17.147: n

n

p1  V2   T1  n−1 = = p2  V1   T2 



(17.151)

The compression work can be calculated from the pressure–volume relationship as follows: 2

∫

W = pdV



(17.152)

1

The amount of work required is dependent upon the polytropic curve involved and increases with increasing values of n. The path requiring the least of amount work is n = 1, which is equivalent to isothermal compression, a process during which there is no change in temperature. For isentropic compression, n = k = ratio of specific heat at constant pressure to that at constant volume. Therefore, most machines tend to operate along a polytropic path which approaches the isentropic (i.e., constant entropy).

pVn = C For a polytropic process 2



∫

W= C 1

dV Vn

(17.153)

734  Petroleum Refining Design and Applications Handbook Volume 2 Integrating Eq. 17.153 gives: 2

∫

W = C V − n dV =



1

1  C V21−n − CV11−n  1− n 

(17.154)

but C = p1V1n = p2 V2n , therefore Eq. 17.154 can be expressed as:



W=

1 [p2 V2 − p1V1 ] 1− n

(17.155)

Using the ideal-gas laws:

p1V1 = mRT1 and p2V2 = mRT2 Eq. 17.155 is given by:



W=

mR [T2 − T1 ] 1− n

(17.156)

For polytropic compression, work done is defined by



W=

nR [T2 − T1 ] 1− n

(17.157)

The polytropic compression work can be expressed as:



W=

n [p1V1 − p2 V2 ] n −1

(17.158)

p1V1n = p2 V2n

(17.142)

Since the process from 1 to 2 is polytropic, then

and

1

V1  p2  n = V2  p1 



(17.159)

From Eq. 17.158, the compression work is:



W=

 p V  n p1V1 1 − 2 2  n −1  p1V1 

(17.160)

Compression Equipment  735 and

p2 V2  p2  = p1 V1  p1 



n−1 n



(17.161)

Substituting Eq. 17.161 into Eq. 17.160 gives: n−1    p2  n  n  W= p1V1 1 −     p1   n −1  

where R c =

(17.162)

p2 = compression ratio, Eq. 17.162 becomes: p1 n−1   n W= p1V1 1 − R c n  n −1



(17.163)

Polytropic Compressor Real compression processes operate between adiabatic and isothermal compression. Actual compression processes are polytropic because the gas being compressed is not at constant entropy as in the adiabatic process or at constant temperature as in the isothermal processes. Generally, compressors have performance characteristics analogous to pumps (see Chapter 16). Their performance curves relate flow capacity to head. The head developed by a fluid between states 1 and 2 can be derived from the general thermodynamic equation: p2

∫

H = Vdp



(17.164)

p1

where H = head, kN-m/kg p = pressure, kN/m2 (bara). V = specific volume of the fluid, m3/kg. For a polytropic compression, the pressure–volume relationship is:

pVn = constant or



V=

C1 p1 n

where



V = mole volume, m3/kg mol

(17.165)

736  Petroleum Refining Design and Applications Handbook Volume 2 For the polytropic head, Hp, V can be substituted in Eq. 17.164. The polytropic head is defined by: p2

Hp =



C1

∫p

p1

1 n

dp

(17.166)

Integrating Eq. 17.166, Hp becomes: n −1   n   nn−1 n p p H p = C1  −    1 2  n − 1 



n−1  n −1   n  n  p2  n = C1  p − 1   n − 1  1  p1   

1n

1n

where p1 V1 = p2 V2 = C1 and R c =



p2 p1

(17.167)

(17.168)

(17.169)

Substituting these into Eq. 17.167 to eliminate C1 gives:

 n−1   kN − m   n  Hp =  p V R n − 1 ,    n − 1  1 1  c kg  



(17.170)

Using the gas law relationship:

p1 V1 =

where Z1 T1 Mw R

Z1 RT1 Mw

(17.171)

= compressibility factor at suction = absolute temperature at suction, K = molecular weight, kg/kg mole = Gas constant, 8.314 kJ/kg mole K

Substituting Eq. 17.171 into Eq. 17.170, the polytropic head, Hp becomes:



Hp =

n−1  Z1 R T1  n   n R    c − 1 , kN-m/kg Mw n −1

(17.172)

If the compressibility factor Z2 for the gas at discharge conditions is significantly different from that of the suction, then the average compressibility factor, Zavg is used to calculate the polytropic head.



Z avg =

Z 1 +Z 2 2

(17.173)

Compression Equipment  737 The polytropic head is defined by:

Z avg R T1  n   nn−1  Hp =   R c − 1 , kJ/kg ( kN-m/kg) Mw  n − 1

(17.174)

 8.314 Z avg T1   n   n−1  n Hp =    n − 1  R c − 1 , kJ/kg ( kN-m/kg ) Mw 

(17.175)

This can be expressed as:



The discharge temperature T2 is given by:

T2 =



(H p )(M w )  n − 1    + T1 (Z avg R )  n 

(17.176)

There is a limit on the temperature such as in olefin or butadiene plants to prevent polymerization. At temperatures greater than 230°C to 260°C, the approximate mechanical limit, problems of sealing and casing growth could occur. High temperature requires a special and high cost machine. Therefore multistage compressors are designed within the temperature range of 120°C to 150°C [72]. In industrial compressors or expanders, the compression or expansion path will be polytropic. Therefore, the polytropic work produced (or required) can be derived from Eq. 17.155.



(− W )poly =

n [p2 V2 − p1 V1 ] n −1

(17.177)

Since p1V1n = p2 V2n for polytropic condition, Eq. 17.177 becomes

(− W )poly

where R c =

n−1   n  n    p  2 = p V − 1   n − 1  1 1  p1   

(17.178)

p2 Z RT and p1V1 = 1 1 p1 Mw

Eq. (17.178) becomes



 n   Z1 R T 1   nn−1   kJ 1  (− W )poly =  R c − 1 ,  •K•   ( kJ/kg )      n − 1  Mw  kg   kgmole K  kgmole  

(17.179)

The negative sign shows that the power is put into the system. The actual work required is defined by:



(− W )actual =

(− W )poly , kJ/kg Ep

(17.180)

738  Petroleum Refining Design and Applications Handbook Volume 2 The power required is:

 (− W )actual • w  Power =   , kW 3600  



(17.181)

where w = mass flow rate, kg/h

Adiabatic Compressor The performance of reciprocating (piston) compressors with large valve area, or where valve losses are evaluated is considered to be as close to adiabatic behavior as can be measured. The thermodynamic definition of an adiabatic process requires that no heat be added to or removed from a system in which a change of state occurs. The adiabatic head produces the following equation, which is similar to the polytropic head of Eq. 17.172



(

)

 Z avg R T 1   k  k −1 k Had =    k − 1  R c − 1 , kJ/kg ( kN-m/kg )  M w

(17.182)

or



(

)

 8.314 Z avg T 1   k  k −1 k Had =    k − 1  R c − 1 , kJ/kkg ( kN-m/kg ) Mw 

(17.182A)

The discharge temperature is:

T = T (R ) , K



2

1

k −1 k c

(17.183)

The adiabatic work required is:



 k   Z1 R T 1   kk−1  (− W )ad =  R − 1 , kJ/kg  k − 1   M w   c

(17.184)

The actual adiabatic work required is:



(− Wactual )ad =

(− W )ad , kJ/kg E ad

(17.185)

The adiabatic power required by the compressor is:



 (− Wactual )ad • w  Power =   , kW 3600  

(17.186)

Compression Equipment  739

Efficiency The adiabatic efficiency, Ead assumes that work done in compressing the gas is reversible (that is, there is no heat loss or gain and on re-expansion to the original pressure, volume and temperature will remain the same as the original). The adiabatic efficiency, Ead is defined by k −1 k

E ad =



Rc −1 n −1 n



(17.187)

Rc −1 where

k=



Mw Cp M w C p − 8.314

(17.188)

The polytropic efficiency Ep is used to compare adiabatic with polytropic performance as defined by Eq. 17.98 or Eq. 17.134.

 k  n =  Ep n − 1  k − 1



(17.134)

The polytropic efficiency assumes as that heat is lost (radiation or conduction) or gained by friction during an actual compression process. Both polytropic and adiabatic efficiencies represent the difference in theoretical energy required in compressing a gas and the actual energy required. However, the adiabatic efficiency closely represents the power absorbed. The polytropic efficiency gives a better estimate of the temperature rise. Generally, polytropic efficiency is used in all centrifugal compressor computations. Figure 17.87 shows the relationship between the poly­ tropic efficiency and adiabatic (isentropic) efficiency of a perfect gas. Table 17.12 gives some typical polytropic efficiencies for different types of machines. The compression efficiency is the ratio of theoretical power to the power actually imparted by the compressor, and Table 17.13 shows compressor efficiency that accounts for mechanical losses in the compressor gears, bearings, etc. Additional efficiencies include the motor (or driver) efficiency and variable speed controller efficiency.

Mass Flow Rate, w The mass flow rate, w, kg/h can be determined from the volumetric rate, Q m3/h as:



w = Q ρ

(17.189)

where



ρ = gas density, kg/m3 ρ=

weight PM w = volume ZRT

(17.190)

Substituting Eq. 17.190 into Eq. 17.189, w becomes:



 PM  w = Q 1 w   Z1 R T1 

(17.191)

740  Petroleum Refining Design and Applications Handbook Volume 2 90 UNCOOLED COMPRESSORS RELATIONSHIP BETWEEN ADIABATIC EFFICIENCY AND POLYTROPIC EFFICIENCY BASED ON

88 86

P2 k–1 k –1 ( P1 ) ηad = n–1 P2 n ( P1 ) – 1

84 82

ADIABATIC EFFICIENCY ηad

80

ηpt =

78

X=0 X = 0.1 X = 0.2 X = 0.3 X = 0.4

k–1 k n–1 n

PVk = α Constant PVn = α Constant

76 74

P k–1 X = ( 2) k – 1 P1

72 70

X = 0.5 X = 0.6 X = 0.7 X = 0.8 X = 0.9 X = 1.0

68 66 64 62 60

60

62

64

66

68

70

72 76 78 80 82 74 POLYTROPIC EFFICIENCY ηpt

84

86

88

Figure 17.87  Uncooled compressor relationship between adiabatic efficiency and polytropic efficiency.

Table 17.12  Polytropic efficiencies for various types of machines. Machine

Condition

Ep

Centrifugal compressor

Best

0.80

Centrifugal compressor

Fair

0.72

Reciprocating compressor

Best

1.00

Reciprocating compressor

Fair

0.92

Axial or rotary vane compressor

Best

0.92

Axial or rotary vane compressor

Fair

0.85

Rotary lobe compressor

Average

0.57

Small bore or pipeline

Good

1.05

Good

1.45

Reciprocating compressor Internal combustion engine

90

92

94

Compression Equipment  741 Table 17.13  Approximate mechanical losses as a percentage of a gas power requirement. Gas power requirement English (hp)

Metric (kW)

Mechanical losses (%)

0–3000

0–2500

3

3000–6000

2500–5000

2.5

6000–10,000

5000–75000

2

10,000+

75000+

1.5

 12.0279 P1 M w  = Q  , kg /h Z1 T1 



(17.192)

The discharge volumetric flow rate Qd is defined by:

 p  T Z  Q d = Q  1   2   2  , m3/h  p 2   T 1   Z1 



(17.193)

The actual intake volume, Qs is the volumetric aspirated into a reciprocating compressor cylinder during the suction stroke, or drawn into the inlet of a centrifugal compressor impeller. Qs is defined by:

 1.01325   T1  3 Q s = Q s( st )    (Z1 ), m /s   p1  288.15



(17.194)

Mechanical Losses After the gas horsepower is calculated by either the polytropic or adiabatic compression method, horsepower losses due to friction in bearings seals and speed increasing gears should be added. Table 17.13 shows approximate mechanical losses as a percentage of the gas power requirement [73].



Mechanical losses = (Ghp) (% Mechanical losses)

(17.195)

The brake horsepower is:

Bhp = Ghp + Mechanical losses

(17.196)

SI units



Mechanical losses = (Power) (% Mechanical losses)

(17.195A)



The total power = Power demand by the compressor + Mechanical losses

(17.196A)

Bearings and seals losses can also be roughly determined from Scheel’s equation:



Mechanical losses = (Gp)0.4

(17.196B)

Bhp = Power + Mechanical losses

(17.196C)

To calculate the brake horsepower



742  Petroleum Refining Design and Applications Handbook Volume 2

Estimating Compressor Horsepower For large slow speed 300 to 450 rpm and compressors handling gases with a relative density of 0.65 and having stage compression ratios above 2.5, Eq. 17.197 is used to estimate the compressor horsepower as:

 ratio  Brake power = (0.014 ) (No. of stages)(Q )(F), kW  stage 

where Q F

(17.197)

= Compressor capacity referred to 100kPa (abs) and intake temperature, m3/h = 1.0 for single-stage compression = 1.08 for two-stage compression = 1.10 for three-stage compression

Eq. 17.197 provides an estimate for lower compression ratios and/or gases with a higher specific gravity, but it will tend to be on the high side. Allowing for this tendency, a multiplication factor of 0.013 instead of 0.014 is used for gases with a specific gravity in the 0.8 to 1.0 range. A factor in the range of 0.01 to 0.012 for compression ratios between 1.5 and 2.0. Figure 17.88 shows curves for estimating compression-horsepower requirements.

Multistage Compressors Single-stage compressors are employed for low pressure ratios. At high pressure ratios, the temperature rise is too high for efficient operation. To meet the need for high pressure generation, the compression is split into a number of separate stages, with intercoolers between each stage. The interstage pressures are normally selected to give equal work in each stage. For a two-stage compressor, the interstage pressure is defined by:

Pi = (P1 × P2 )

EFFICIENCY



90% 89% 88% 87% 86% 85% 84% 83% 82% 81% 80% 79% 78% 77% 76% 75% 74% 73% 72% 71% 70%

1.5

2

2.5

3

3.5

4

4.5

PRESSURE RATIO

Figure 17.88  Reciprocating compressor efficiencies.

(17.198)

5

5.5

6

6.5

Compression Equipment  743

Example 17.12 Determine the power required to compress 1500 m3/h air from ambient conditions to 800 kN/m2 gauge in a twostage reciprocating compressor with an intercooler.

Solution Take the inlet pressure, P1 as one atmosphere = 101.33 kN/m2, absolute. Outlet pressure, P2 = 800 + 101.33 = 901.33 kN/m2, absolute. For equal work in each stage the intermediate pressure, Pi is:

Pi = (1.0133 × 105 × 9.0133 × 105 )



= 3.022 × 105 N/m 2





For air, take the ratio of specific heats, k = 1.4

For equal work in each stage the total work will be twice that in the first stage. Take the inlet temperature to be 25°C; at this temperature the specific volume is:



v1 =

29 298 m3 × = 1.41 22.4 273 kg

k −1    k   pi  k   p v Isentropic work done, (− W )isen = 2  − 1 , J/kg  k − 1  1 1  p1   

 3.022  (1.4−1) 1.4   1.4  5 = 2 (1.0133 × 10 )(1.41)  − 1   1.4 − 1   1.0133   = 366, 492 J/kg (366 kJ/kg )



Compression ratio, Rc = Pi/P1 = 3.022/1.0133 = 1.99



From Figure 17.88, Isentropic efficiency = 78%, and the work required is:

(−W)isen = 366/0.78 = 469 kJ/kg The mass flow rate, G is:



G=

1500 kg = 0.3 (1.41)(3600) s

Power required = 469 × 0.3 = 141 kW



744  Petroleum Refining Design and Applications Handbook Volume 2

Example 17.13 Determine the power to compress 2500 m3/h of gas at 101.325 kPa (abs) and intake temperature through a compression ratio of 9 in a two-stage compressor.

Solution Ratio per stage = R c = 9 = 3 F = 1.08 for two-stage compression No. of stages = 2 Q = 2500 m3/h From Eq. 17.197, the brake power is:

 ratio  Brake power = (0.014 ) (No. of stages)(Q )(F), kW  stage  = (0.014 )(3)(2)(2500)(1.08) = 227 kW





From Figure 17.88 using a k of 1.15 for a two-stage compressor, we determine the power requirement to be 88 (W/m3/h) or 220 kW. For a k of 1.4, the power requirement is 97 (W/m3/h) or 243 kW total power.

Multicomponent Gas Streams Designing a gas compressor for a gas mixture involves estimating the thermodynamic properties. The procedure for calculating gas mixture properties is to use the weighted molal averages of the property. These thermodynamic properties are estimated as: n

Molecular weight , M w ,mixture =



∑y M i

(17.199)

i

i =1 n

Reduced temperature, Tr ,mixture =



∑y T i

r ,i



(17.200)



(17.201)

i =1 n

Reduced pressure, Pr ,mixture =



∑y P i

r ,i

i =1 n

Molal heat capacity , MC p ,mixture =



∑ y MC i

i =1

Ratio of molal heat capacities

p ,i



(17.202)

Compression Equipment  745

M Cp , mixture MC p ,mixture = MC v ,mixture (M Cp ,mixture − 8.314 )



k mixture =



Compressibility factor, Zmixture = f (Tr, Pr)

(17.203) (17.203A)

Case Studies Case Study 2 Compressors are used to move gases. The compressor increases the pressure of the gases. A mixture of natural gas (methane, ethane, propane, isobutane, n-butane, isopentane) at 75°C and 150 kPa is fed into a compressor with adiabatic efficiency of 75%. The flow rate of the natural gas is 8200 kg/h and its outlet pressure from the compressor is 550 kPa. Using Peng–Robinson equation of state as a fluid package, determine the outlet temperature of the natural gas and the variables. Using UniSim software package (Compression Case Study by A.K. Coker.usc). 1. D  ouble click on the UniSim Design R451 icon 2. Open a new case by using one of the following: a. Go to the File menu, select New, followed by Case or b. Press Ctrl N, or c. Click the New icon on the toolbar. 3. Defining the Simulation Basis a. From File New Case, the Simulation Basis Manager window opens (Figure 17.89). b. Click on the Add button and select the six components required (Figure 17.90). c. Click on the Fluid Pkgs button tab and select the thermodynamic property PR (Figure 17.91).



Figure 17.92 shows the composition tab on the worksheet with the mole fractions of the feed. 4. C  lick the Enter Simulation Environment button when you are ready to start building the simulation. 5. Installing A Stream There are several ways to create stream: a. Press F11. The Stream property view appears, or b. Double-click the Stream icon in the Object Palette. 6. Adding A Feed Stream Add a new Material stream with the following values. In this cell..

Enter

Name

Natural Gas

Temperature

75°C

Pressure

150 kPa

Flow rate, kg/h

8200 kg/h

Component mole fraction C1

0.9216

746  Petroleum Refining Design and Applications Handbook Volume 2 C2

0.0488

C3

0.0185

iC4

0.0039

nC4

0.0055

iC5

0.0017

7. A  dding a Compressor There are several ways to add unit operations. a. Press the F12 hot key. Select the desired unit operation from the Available Unit operations group b. Double-click on the unit operation button in the Object Palette. 8. O  n the Connection tab, add a Compressor and enter the following information as shown in Figure 17.93. In this cell...

Enter

Name

Compressor

Feed

Natural Gas

Outlet

Comp_Out

Energy

Work

Figure 17.89  The Simulation Basis Manager window of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  747

Figure 17.90  Component List View Component List-1 of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.91  Fluid Package of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

748  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.92  Composition tab of Worksheet window of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.93  Connection tab of Compressor of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  749

Figure 17.94  Parameter tab of Design of Compressor of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

9. Switch to the Parameters page as shown in Figure 17.94. Change the Adiabatic Efficiency to 85%. 10. Go to the Worksheet tab. On the Conditions page, complete the page as shown in Figure 17.95. The pressure for Comp_Out will be 550 kPa as shown in Figure 17.96. 11. Click the Solver icon on the menu bar and the simulation converges with blue lines and is solved as shown in Figure 17.97. The results of the compressor simulation are: Compressor duty Pressure increase Pressure ratio Outlet temperature Molar flow Polytropic efficiency Polytropic exponent Isentropic exponent Adiabatic head Polytropic head

= 645.26 kW = 400 kPa = 3.667 = 189.4oC = 462.3 kg mole/h = 86.6% = 1.2798 = 1.2367 = 2.455 × 104 m = 2.501 × 104 m

750  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.95  Conditions page of Worksheet tab of Design of Compressor of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.96  Worksheet tab of UniSim Design R451 (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  751

Figure 17.97  PFD of UniSim Design R451 (Honeywell® and UniSim® are registered trademarks of Honeywell Inc. All rights reserved). UniSim Design simulation software (Compression Case Study by A.K. Coker.usc) provides the simulation of Case Study 2.

Case Study 3: Two-Phase Compressor Simulation—Using UniSim Simulator A process stream of 10,000 kg/h containing a mixture of light alkanes is to be compressed from 300 kPa to 1000 kPa [145]. In this condition, it is common to flash the stream and use a pump to increase the pressure of the flashed liquid stream and a single-stage compressor to increase the pressure of the flashed vapor stream. Since the temperature rise in the compressor is highly significant, it is common practice to use a cooler after the compressor. Figure 17.98

VLP VHP VHP 1

Feed T = 70°C P = 300 kPa

Adiabatic flash vessel

Compressor

Cooler

LHP

HP-Feed

LLP Mixer Pump

Figure 17.98  Schematic flow diagram of a two-phase compression process.

752  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.14  The feed components and the mole fractions. Feed

Mole fraction

Methane (CH4)

0.01

Ethane (C2H6)

0.01

Propane (C3H8)

0.02

Iso-butane (iC4H10)

0.20

Normal butane (nC4H10)

0.17

Iso pentane (iC5H12)

0.16

Normal pentane (nC5H12)

0.14

Normal hexane (nC6H14)

0.15

Normal heptane (nC7H16)

0.10

Normal Octane (C8H18)

0.04

Total

1.00

shows the schematic of the two-phase compression process, and Table 17.14 shows the mole fractions of the feed components. In this case study, UniSim design R451 simulation package is used to simulate the two-phase compression process. The ten components are added in the Simulation Basis Manager window. Select the components by clicking Add Pure button in the Components Lists page. Close the window, and from the Simulation Basis Manage, click Fluid Pkgs to choose the required thermodynamic Property Package from Property Package selection menu. In this instance, Soave Redlich Kwong (SRK) equation of state is chosen, although Peng–Robinson (PR) is also suitable. Close this window, then press Enter Simulation Environment button, and the process flow diagram window appears. Enter the Feed stream by clicking on the arrow from the object Palette. SI units are selected from the Tools menu. Select Preferences and Variables button. Double click on the feed stream arrow on the PFD. This opens the worksheet page of the Feed stream window. Click on the edit button to input the feed stream compositions as shown in Table 17.20. Click on the mole fraction radio button to enter the feed stream mole fractions. The total is 1.0. Click on Conditions page of the worksheet and input the mass flow rate (kg/h) of 10,000 to complete the definition of the feed stream. The feed stream is 59% vapor, so an adiabatic flash vessel is chosen from the object Palette to increase the pressure. An adiabatic flash vessel is installed from the Object Palette having an inlet stream Feed, an outlet vapor stream VLP and an outlet liquid stream LLP. Figure 17.99 shows the worksheet of the adiabatic flash vessel showing the liquid and vapor streams calculated parameters. A pump icon is chosen from the Object Palette is installed at the outlet LLP of the adiabatic flash vessel. Double clicking on the icon gives the pump window with Design, Rating, Worksheet, Performance and Dynamics buttons. Clicking on the Connection page of the Design Window gives the inlet, outlet and energy of the pump. The input to the pump is LLP, and the outlet is LHP in the Connection page of the pump. The pump efficiency is 75%, and the pump pressure drop Delta P is 700 kPa. P-Duty is chosen as the pump duty in the Parameters page of the Design button. The window is closed to revert to the PFD. Click the Solver Active (showing green) in the menu of the PFD; this gives the pump power of 7274 kJ/h and Figure 17.100 shows the worksheet of the pump. A compressor icon is chosen from the Object Palette, and installed at the vapor outlet of the adiabatic flash vessel. Double click on the compressor icon to show the same windows as for the pump. In the connection page of the design button, the inlet stream to the compressor is VLP and the outlet stream is VHP, the Energy duty is

Compression Equipment  753

Figure 17.99  Worksheet window of the adiabatic flash vessel showing fraction of the vapor 59.1% (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.100  Worksheet window of the pump P.101 showing pump power of 7274 kJ/h (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

754  Petroleum Refining Design and Applications Handbook Volume 2 C1—DUTY. In the Parameters page, the adiabatic efficiency of the compressor is 75%. Close the widow to revert to the PFD. Click the Solver Active (showing green) in the menu of the PFD to give the compressor power of 8.393 × 104 kcal/h (3.511 × 105 kJ/h). The pressure from the VHP stream is 1015 kPa and the compression ratio Rc (1015/300) = 3.38, which is less than 4. This suggests that a single stage compressor is adequate. The vapor fraction is 0.9879 showing that the effluent is partially condensed, and to avoid damage to the compressor, a heat exchanger is added. The outlet temperature from the compressor is 114.2°C implying that a cooler is required to bring the temperature close to the feed (70°C). Figure 17.101 shows the worksheet of the compressor. Click on the cooler icon in the Object Palette and place it at the outlet of the compressor. Double clicking on the cooler icon gives the window E-100 of the cooler. In the Connection page of the design button, the input stream to the cooler is VHP and the outlet stream is VHP1. The heat duty is E-DUTY and in the Parameters page, the pressure drop of the cooler is 15 kPa. Figure 17.102 shows the worksheet of the cooler with a heat duty of 3.079 × 105 kJ/h. The outlet temperature of VHP1 is 70°C, and the pressure is 15 kPa. The almost completely liquid stream VHP1 at 70°C and 15 kPa from the cooler is combined with the high pressure liquid stream LHP from the pump into a single liquid product stream HP_Feed at the design pressure of 15 kPa. Figure 17.103 show the process flow diagram (PFD) of the simulation and the pertinent tables of results of the equipment items used in the two-phase compression exercise. UniSim Design simulation (Case Study-Compression process-akc.usc) shows the simulation exercise of Case Study 3.

Example 17.14 A centrifugal compressor is to be specified for a gas plant. The unit is to compress 8200 kg/h of gas mixture at 75°C from 1.5 bara to 5.5 bara. The gas mixture consists of 92.16% methane (CH4), 4.88% ethane (C2H6), 1.85% propane (C3H8), 0.39% i-butane (i-C4H10), 0.55% n-butane (n-C4H10), and 0.17% i-pentane (i-C5H12). Assuming a polytropic efficiency of 87%, adiabatic efficiency of 85%, suction compressibility factor, Z1 = 0.97 and discharge compressibility factor Z2 = 0.93.

Figure 17.101  Worksheet window of the compressor C1 showing compressor power of 3.511 × 105 kJ/h (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  755

Figure 17.102  Worksheet window of the Cooler E-1 showing the duty of 3.079 × 105 kJ/h (courtesy, Honeywell Process Solution. UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Calculate the adiabatic head, discharge temperature, actual work required and the total power. Table 17.15 shows the properties of the gas.

Solution The mixture specific heat ratio, k is defined by:

k mixture =

MC p ,mixture M Cp ,mixture = MC v ,mixture (M Cp ,mixture − 8.314)

40.585 = = 1.26 (40.585 − 8.3145)



(17.198)

The average molecular weight of the gas mixture:

Mw = 17.735 The computer program COMPSI has been developed that calculates the polytropic and adiabatic heads of a compressor, outlet temperature, power demand by the compressor, mechanical losses and total power. Table 17.16 shows the input data and results of the gas mixture. The gas discharge temperature is 201°C, the adiabatic head is 231 kN-m/kg, the polytropic head is 236 kN-m/kg, the actual work required is 277 kJ/kg, and the total power is 650 kW. Table 17.16A shows the specification data sheet of Example 17.14. Figures 17.104–17.107 show the connection of the streams and the process flow diagram of the simulation of Example 17.14 using UniSim simulation software package. The results of the simulation of Example 17.14 can be

756  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.103  Process flow diagram of the two-phase compression simulation (courtesy, Honeywell Process Solution, UniSim Design R451, Honeywell® and UniSim® are registered trademarks of Honeywell Inc.).

Table 17.15  Properties of the gas mixture. Determination of equivalent molecular mass

Determination of MCp, molar heat capacity

Determination of critical pressure, Pc and temperature, Tc

yM

Individual component MCp @ 75oC

y. MCp @ 75oC

Component critical pressure Pc, kPa (abs)

Component name

Mol fraction y

Individual component Molecular mass, M

Methane

0.9216

16.04

14.782

37.870

34.901

4604

4243.05

194

176.0

Ethane

0.0488

30.07

1.467

58.819

2.870

4880

238.14

305

14.9

Propane

0.0185

44.10

0.816

83.585

1.546

4349

78.61

370

6.8

i-Butane

0.0039

58.12

0.227

110.408

0.431

3648

14.23

408

1.6

n-Butane

0.0055

58.12

0.320

110.334

0.607

3797

20.88

425

2.3

i-Pentane

0.0017

72.15

0.123

135.581

0.230

3381

5.75

460

0.8

Total

1.0000

Mmix = 17.735

For values of MCp other than at 75°C, refer to Table 17.5A.

MCp,mix = 40.585

Pc,mix = 4600.66

y . Pc

Component critical temperature Tc, K

y. Tc

Tc, mix = 202.4

Compression Equipment  757 accessed from UniSim software (Example 17.14.usc). The compressor power in the simulation is 645.3 kW and from the computer program COMPSI is 649.7 kW with a percentage difference of 0.7%.

Case Study 4 A natural gas stream is compressed before entering a pipeline. The stream is first compressed to 12 bar and then to 26 bar. The liquid condenses in the compressor aftercoolers and is recycled back to the previous stage. The liquid product is removed from the feed flash. Use UniSim simulation to simulate the two-stage compressing process. Figure 17.108 shows the process flow diagram of the two-stage compression process, and the feed stream data are: Component

lb-mol/h

Flow rate kg-mol/h

Nitrogen (N2)

400

180

Carbon dioxide (CO2)

4230

1920

Methane (CH4)

32,000

14,520

Ethane (C2H6)

20,000

9070

Propane (C3H8)

16,000

7260

i-Butane (iC4H10)

1700

770

n-Butane (nC4H10)

6200

2810

i-Pentane (iC5H12)

2100

950

n-Pentane (nC5H12)

3600

1630

n-Hexane (nC6H14)

3400

1540

C7 plus (model as nC9)

7000

3180

Temperature

100°F

37.78°C

Pressure

70 psia.

4.83 bar

Solution UniSim simulation software (Two-Stage Compressor-Natural Gas.usc) was used to calculate the amount of liquid and vapor leaving the process, the compressor work required for each stage, the stream temperatures entering the aftercoolers and the duties of the aftercoolers, using Peng–Robinson (PR) as the thermodynamic property for the feed stream for the components. UniSim Design R460.1 uses the recycle operation from the object palette to solve the looped system iteratively. A set of conditions is assumed and used to solve the recycle loop. The assumed values are compared with the calculated values and updated. This is repeated until the values match within a specified tolerance. The recycle operation allows information to be transferred both forward and backward (i.e., the assumed value to be in either the outlet or inlet stream), although information is only transferred forward (i.e., assumed value in outlet). When the Recycle operation is first added, initial estimates need to be provided for all the assumed values. Typically, this is done by allowing UniSim Design to solve before closing the recycle loop. The following steps take place during the convergence process: • UniSim Design uses the conditions of the assumed stream (usually outlet) and solves the flowsheet up to the calculated stream (usually inlet).

758  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.16  Input data and computer results of Example 17.14. COMPI.DAT Polytropic 8200.0 1.50 5.5 75.0 1.26 17.735 0.97 0.93 0.87 **** Polytropic compression calculation Type of service:

Polytropic

Gas flow rate, kg/h:

8200.000

Inlet pressure, bara:

1.500

Outlet pressure, bara:

5.500

Compression ratio, Rc:

3.667

Inlet temperature, °C:

75.000

Polytropic exponent, n:

1.311

Ratio of specific heat capacities, k:

1.260

Molecular weight of gas, kg/kg-mole:

17.735

Inlet density, kg/m^3:

0.9475

Inlet volumetric flow rate, m^3/min:

144.241

Outlet density, kg/m^3:

2.6626

Outlet volumetric flow rate, m^3/min.:

51.329

Inlet compressibility factor, Z1:

0.9700

Outlet compressibility factor, Z2:

0.9300

Average compressibility factor, ZAV:

0.9500

Polytropic efficiency (%):

87.0000

Calculated adiabatic efficiency (%):

85.1928

Polytropic head, kN-m/kg:

235.943

Adiabatic head, kN-m/kg:

231.042

Outlet temperature, °C:

200.658

Work done, kJ/kg:

240.910

Actual work done, kJ/kg:

276.909

Power demand by the compressor, kW:

630.736

Mechanical losses, kW:

18.922

Total power, kW:

649.658

Compression Equipment  759

Figure 17.104  Stream information in the compressor connection of the Design page of UniSim simulation package (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.105  Specifying compressor adiabatic efficiency in the connection of the Design page of UniSim simulation package (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

760  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.106  Calculated results in the Worksheet page of the simulated compressor design (85 % adiabatic efficiency) (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

Natural Gas Temperature 75.00 C 1.500 bar Pressure Molar Flow 462.3 kgmole/h

Natural Gas

Comp_Out K-100

K-100 Speed

Power 645.3 Capacity (act feed vol flow) 8900 Product Pressure 5.500 Product Temperature 189.4 Dynamic Surge Flow Rate Molar Flow 462.3

work

Comp_Out Temperature 189.4 C 5.500 bar Pressure Molar Flow 462.3 kgmole/h

rpm kW ACT_m3/h bar C ACT_m3/h kgmole/h

Figure 17.107  Process flow diagram of Example 17.14 (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  761 S4

S2 Vapor

C-100

S5

S8

S6 C-101

E-100

S9

S10

Vapor

E-101

V -101

V-102

V-100

Natural S1 gas 37.78°C 482.6 kPa 4.383 x 104 kg-mol/h

S7 S3

S11

Liquid

Figure 17.108  Process flow diagram of the two-stage compression of natural gas.

• UniSim Design then compares the values of the calculated stream to those in the assumed stream. • Based on the difference between the values, UniSim Design modifies the values in the calculated stream and passes the modified values to the assumed stream. Add the first Recycle by double-clicking on the Recycle icon in the Object Palette and place it on the PFD as shown in Figure 17.113. Double on the icon gives the Connection Page. Supply the Name, Feed and Product information as shown in Figure 17.109. UniSim Design allows the user to set the convergence criteria or tolerance for each of the Recycle variables. Additionally, the direction of transfer of information can be set to Forwards or Backwards, or Not Transferred. In general, the user will want to leave the transfer as Forwards as default as shown in Figure 17.110.

Figure 17.109  Screen shot of the Connection Tab of Recycle RCY-1 (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

762  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.110  Screen shot of the Parameters Tab in the Connection page (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

The Numerical Page contains the numerical options for the Recycle, which controls how it is solved numerically as shown in Figure 17.111. The Monitor Tab page displays convergence information as the calculations are performed. Any variable that changes between iterations is displayed in this table. In order to view plots of variables as they change during the calculation of the recycle, the user must select the variables to view on the Setup page as shown in Figure 17.112. The calculation process repeats until the values in the calculated stream match those in the assumed stream within specified tolerances. Figure 17.113 shows the process flow diagram of the converged simulation. The results of the simulation are as follows:

Equipment

Inlet

Outlet

Temperature, °C

37.17

90.31

Pressure, kPa

482.6

1172

Adiabatic efficiency, %

74

Polytropic efficiency, %

75.5

Compression ratio, Rc

2.43

Actual work, kW

3.3 × 104

Compressor C-100

Compression Equipment  763

Figure 17.111  Screen shot of The Numerical Page containing the numerical options for the Recycle (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

Figure 17.112  Screen shot of the Monitor page (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

764  Petroleum Refining Design and Applications Handbook Volume 2 Heat exchanger (Cooler E-100) Temperature, °C

90.31

57.22

Pressure drop, bar

0.35

Duty, kW

2.47 × 104

Compressor C-101 Temperature, °C

52.68

102.7

Pressure, kPa

1139

2537

Adiabatic efficiency, %

72

Polytropic efficiency, %

73.6

Compression ratio, Rc

2.23

Actual work, kW

3.14 × 104

Heat exchanger (Cooler, E-101) Temperature, °C

102.7

Pressure drop, bar

0.35

Duty, kW

4.86 × 104

S2

S4 C-100

S1

V-100

E-100_Duty E-100

S6

E2-Duty

S5

S8

C-101

C-100_Duty

57.2

V-101

C-101_Duty

E-101

S9

S10 V-102

S3 S13

S12

RCY-2

S11

S7 RCY-1

A two-stage compression process of natural gas

Figure 17.113  Process flow diagram of the two-stage compression of natural gas (courtesy, Honeywell Process Solution. UniSim Design® R451, Honeywell®, and UniSim® are registered trademarks of Honeywell Inc.).

Compression Equipment  765

Treatment of Compressor Fluids The discharge from any compressor is a dirty corrosive liquid. Removing the sludge from a compressor air system can affect the following: • Reduce installation costs incurred or drain traps, pipe and fittings, filters and regulators. • Reduce maintenance of drain trap and the failure rate of pneumatic equipment, which is caused by dirt and moisture in the supply line. • Increase the life of pneumatic equipment. The cases of high performance equipment require high quality, clean, and dry compressed air. Compressed air contains water, oil and dirty particles, which affect the performance of pneumatic equipment. Compressed air dryers are used to remove water vapor and to dry the air. Two main types of dryers are used in the chemical process industries: refrigerant and desiccant dryers. Desiccant dryers use an adsorbent material, such as activated alumina, or molecular sieves to remove moisture from the compressed air. Also, desiccant dryers can be either heat regenerated or heatless. The main advantage of desiccant dryers is their ability to cool the air to a very low temperature. They are more expensive in terms of both capital and running costs. They are important when higher quality air is required. These dryers are widely used in offshore oil industry, where extreme ambient conditions are required. The design of desiccant dryers for removing water vapor from a nature gas is explained in volume 1.

Centrifugal Compressor Performance in Process System Wet gas compressor capacity limits feed rate or unit conversion in many fluid catalytic cracking (FCC) and delayed coker units. Understanding the performance of compressors and its interaction with process systems is essential during the revamps/modifications of these units. The connected process system and compressor performance require a detailed evaluation as a single system to ascertain the most cost effective way to increase compressor capacity where conventional process design approaches employ various equipment scopes to determine piping, heat exchanger and distillation systems independently. The opportunity to debottleneck the compressor with low cost process system changes is often unnoticed [74]. A reduction in the systems pressure drop or a decrease in the discharge pressure allows more gas to be compressed through the compressor without modifications. Golden et al. [74] expressed that the impact of suction and discharge system changes on compressor capacity is not the same. Suction pressure changes have a greater effect on compression capacity due to their effect on overhead receiver condensation, gas density and compressor head. Process system operating pressure and system pressure drop both affect wet gas compressor capacity. Compressor suction and discharge pressures are variables that could be controlled when it is necessary to increase compressor capacity. An increase in compressor suction pressure and a reduction in its discharge pressure will invariably increase its capacity. Determining cost effective solutions starts with field measurements of the current operation to identify high pressure drop components. Unit operation equipment, process piping, control valves and flow metering in the connected process systems must be modeled together with the compressor to quantify compressor capacity increases resulting from equipment modifications.

Compressor Head Centrifugal compressors do not develop a constant differential pressure as they develop a constant differential polytropic head at a given inlet flow rate. The compressor curves provided by the manufacturers show the performance curve as differential pressure versus inlet flow rate. These differential pressure curves represent one set of inlet operating conditions only. They are insufficient to determine the compressor and connected system performance. Understanding the components of this head term is essential when reviewing the influence of the process operating pressure and the system pressure drops effect on compressor capacity. The polytropic head is expressed by Eqs. 17.104 and 17.175; reducing the polytropic head will increase the magnitude of the inlet flow rate, resulting from a given polytropic head reduction. Process changes that move the operating point to the right include higher gas

766  Petroleum Refining Design and Applications Handbook Volume 2 molecular weight, raising suction pressure or lowering discharge pressure. Gas temperature changes have negligible influence on head. The compressor molecular weight is set by the coke drum or FCC reactor gas composition. Suction pressure changes of 5 psi or higher can also influence gas composition and molecular weight through the impact of condensation. Compressor suction and discharge pressures both affect the polytropic head. Compressor discharge pressure is set by the gas plant operating pressure and the pressure drop from the compressor discharge to the absorber pressure control valve. Common suction and discharge pressures are 10 psig and 220 psig (0.69 barg and 15.2 barg) respectively. Thus, the compression ratio (Rc = P2/P1) is 234.7 psia/24.7 psia or 9.5. Reducing the head requires a decrease in Rc [74]. Understanding how discharge and suction pressures influence the polytropic head term and compressor capacity is essential in evaluating potential connected process system modifications. Figure 17.114 shows the influence of a 1500 ft head reduction on compressor inlet flow rate for one compressor. Increasing the suction pressure P1 or decreasing the discharge pressure P2 will reduce the head (Hp). Quantifying the suction and discharge pressure changes that result in the same polytropic head reduction is beneficial. Increasing the suction pressure or decreasing the discharge pressure can be used to reduce the polytropic head by 1500 ft and increase the compressor inlet flow capacity by 6% [74].

Compressor Capacity: Driver Power Compressor driver power requirements can limit the compressor maximum flow rate. When the drivers are limited, turbine steam rate and speed or the motor-amps are at the maximum. The compressor driver power consumption is dependent on the mass flow, compressor polytropic head, compressor efficiency and gear efficiency. Compressor shaft horsepower (shp) is shown in Eqs. 17.109 and 17.126. Reducing the polytropic head lowers the compressor shaft horsepower [74].

Unit Operations Wet gas compressors increase the system operating pressure so that C3–C12 hydrocarbon components can be recovered as liquid product. Compressor system operating suction and discharge pressures will vary depending on reactor/regenerator, coke drum, gas plant, compressor and/or upstream equipment design and operation. The compressor takes suction from the main column and overhead receiver or downstream knocked drum, which operates at 1.5–3.0 psig (0.103–0.206 barg) and discharges to a gas plant absorber/deethanizer system operating at 160–240 psig (11.03–16.35 barg) as illustrated in Figure 17.115. The main column overhead receiver temperature and pressure determine the amount of wet gas production for a fixed reactor effluent or coke drum composition. Increasing the compressor inlet pressure and/or decreasing the temperature reduces the wet gas mass flow rate by changing the amount of condensation that occurs. Compressor suction pressures and temperatures vary from 1.5 to 30 psig (0.103 to 0.26 barg) and 80°F to 135°F (27°C to 57.2°C), respectively. Figures 17.116 and 17.117 show plots of suction

7,700 RPM

POLYTROPIC HEAD, FEET

28,000

REDUCED HEAD

27,000 26,000

1,500 FT HEAD

25,000 6%

24,000 23,000 11,500

12,000

12,500 13,000 13,500 VOLUMETRIC FLOW, ICFM

14,000

Figure 17.114  Compressor performance curve, head reduction (source: Scott Golden, et al.).

14,500

Compression Equipment  767 Stripper vapor Main fractionator vapor Primary absorber bottoms Wet gas Comp. Comp. driver

Primary absorber feed Overhead receiver

Interstage receiver

High pressure receiver Stripper/deethanizer feed

Primary absorber liquid feed

Figure 17.115  Compressor and connected system.

pressure and suction temperature versus wet gas production. The main fractionator pressure and temperature can be optimized through equipment changes and these plots show the effects of pressure and temperature on wet gas rate for one unit. Golden et al. [74] have provided examples that highlight the relationship between the connected process system pressure drop, compressor performance curve and wet gas compressor capacity. Dynamic process simulation provides many benefits such as integrating the turbomachinery controls into the dynamic simulation of a compressor system, thus enables the engineer to select properly sized equipment that can withstand transient conditions (e.g., surge conditions), reducing commissioning time through pretuning the regulatory controls thereby improving operator training by exposing operators to realistic simulated operating scenarios, and providing verified startup and shutdown procedures during acceptance testing before startup commences. A performance map describes how a compressor’s polytropic head and power vary with volumetric suction flow rate and rotational speed for a specific set of suction conditions (i.e. fluid molecular weight, pressure, temperature, compressibility, and isentropic exponent at the inlet of the compressor). Manufacturers provide performance maps as two sets of performance curves with a series of plots of polytropic heads versus volumetric suction flow rate, and a corresponding series of power versus flow plots. Each pair of curves corresponds to a different rotational speed, and all relate to the same suction conditions. Performance maps may be constructed for more than one set of suction conditions, where the top performance map corresponds to design operation, and the bottom map to derime operation, respectively. The bottom map removes rime (the granular ice that forms when supercooled droplets freeze rapidly on contact with a solid surface) from the compressor. These maps were generated from data obtained by manually digitizing the performance maps provided by the manufacturers, as the irregularities in the curves are a result of the manual digitization process. Process simulators combine the performance maps with material and energy balances and thermodynamic relationships to predict the performance of the compressor under various operating conditions. Stephenson [75] states that the performance maps by the manufacturers have not been broadly useful for process simulation because they apply only at the suction conditions and rotational speeds for which they were constructed. Process simulation

WET GAS PRODUCTION, ICFM

768  Petroleum Refining Design and Applications Handbook Volume 2 15,000

12,000

9,000

9

10 11 12 OVERHEAD RECEIVER PRESSURE, PSIG RECEIVER TEMPERATURE = 100°F

13

WET GAS PRODUCTION, ICFM

Figure 17.116  Suction pressure vs. wet gas production (source: Scott Golden, et al.).

18,000 15,000 12,000

100

110

120

130

140

OVERHEAD RECEIVER TEMPERATURE, °F RECEIVER PRESSURE = 8.5 PSIG

Figure 17.117  Suction temperature vs. wet gas production (source: Scott Golden, et al.).

requires prediction of the compressor’s performance not at these suction conditions and speeds, but over the compressor’s entire operating range, from surge to stonewall, at varying suction conditions and rotational speeds. Stephenson [75] has provided detailed review of how compressor performance maps can be integrated into process simulation.

Quick Approximation Method for Centrifugal Compressor Performance Cole [78] has summarized a basic approximation for evaluating compressor selection. Although certain details of design selection are not included, the results are quite good (within 2–5%) for the average application and will establish the required size unit within engineering estimating accuracy. It should be used for compression ratio greater than about 6 because this would not normally be designed in equipment used to establish the curves. This can be controlled by not allowing a discharge temperature greater than 450°F (232°C). At temperatures greater than 450–500°F (232–260°C), the approximate mechanical limit, problems of sealing and casing growth start to occur. A high temperature requires a special and more costly machine. Most multistage applications are designed to stay below 250–300°F (121–149°C) [3]. Intercooling can be used to hold desired temperatures for high overall compression ratio applications. This can be carried out between stages in a single compressor frame or between series of frames. Economics can also impact intercooling. For high compression ratio applications, the process cannot be carried out in a single compressor frame, as a frame will not contain more than about eight stages (wheels). There is a maximum head that one stage can handle. This depends upon the gas properties and inlet temperature. Usually this will run 7000 to 11,000 ft (2134 to 3353 m) for a single stage. In lieu of manufacturers’ data, use eight maximum stages per frame. Then subtract one stage for every side nozzle such as to and from an intercooler, side gas injection, etc. For many applications, the compression ratio across a frame will run 2.5–4.0 [3].

Compression Equipment  769

For Horsepower 1.  Use Figure 17.118. Intake volume must be expressed at cfm/1000, with cfm at actual suction pressure and temperature. Read “basic horsepower” at compression ratio, Rc. 2.  Read “k” value correction multiplier from Figure 17.119. 3.  Required bhp at coupling,



bhp = (basic horsepower) (“k” multiplier)



(actual intake pressure, psia/14.5) [Z1 + Z2)/2]

(17.204)

Note that compressibility Z may be neglected for many conditions, but if used Z1 is at intake condition and Z2 at discharge.

Number of Stages 1. 2. 3.

 se Figure 17.120. U Read “basic head” in thousands of ft using Rc and intake temperature. Read “k” value correction multiplier from Figure 17.119. Polytropic head

Hp = (basic head)(“k” multiplier) (28.95/mol wt)[Z1 + Z2)/2] 4. No. of stages = polytropic head/9500

(17.205) (17.206)

Discharge Temperature 1. 2. 3. 4.

 se Figure 17.121. U Read the “temperature rise multiplier.” Use “k” values. Temperature rise = (intake temperature, °R)(multiplier) Discharge temperature, °F = (temp. rise) + intake temp., °F

(17.207)

Compressor Speed Some experience indicates that the speed may be 5–10% lower than the lower curve, particularly in the low intake volume region, less than 10,000 cfm (use Figure 17.122).

Operating Characteristics Probably the most important of the fundamentals concerning centrifugal compression equipment is an understanding of the basic operating characteristics. Although some basic mathematical relations should be kept in mind, a graphical representation makes these points easier to understand. Figure 17.72 is a representation of typical operating curves for centrifugal compressor performance when the unit is driven by a steam turbine. Usually when a machine is purchased, only one curve representing the 100% speed line is furnished to the operator. The manufacturer will, on request, provide the other informational curves to give a better picture of practical performance [79]. These points can be calculated by the engineer from the 100% curve and the design point. The fundamental impeller operating efficiencies and performance characteristics should be known for a very exact representation. These can be obtained from the manufacturer [80]. References [79] and [81] present discussion of the same topic, but with varying detail.

770  Petroleum Refining Design and Applications Handbook Volume 2 10,000 9,000 8,000 7,000

Basic Horsepower

6,000

8.

0

5,000 7.

0

4,000

O

2. 0

3.

M CO

PR

ES

SI

ON

TI RA

Basic hp

1.

5

2.

3.

4.

0

5

2,000

0

5.

0

5

6.

0

3,000

1,000 900 800 700 600 500 400 300

200

100

CORRECT BASIC HORSEPOWER FOR: 1. INTAKE PRESSURE OTHER THAN 14.5 PSIA 2. K VALUE OTHER THAN 1.396 3. CHANGING SUPERCOMPRESSIBILITY 1

2

3

4

5 6 7 8 9 10 20 Intake Volume, thousands of cfm

30

40

50 60 70 80 100

Figure 17.118  Basic horsepower for a machine with intake of 14.5 psia, with “k” value for air (1.396) and super compressibility factors neglected (used by permission: Cole, S. L. Oil and Gas Journal, V. 58, No. 6 © 1960. PennWell Publishing Company, All rights reserved).

Because the general characteristic performance of a steam turbine and a centrifugal compressor are quite similar, they pair up excellently for many process applications. The effect of varying speed on capacity and brake horsepower is shown. At the surge point or limit, the operation of the machine is unstable. The machine vibrates and heats up if run at or near this point. Usually the surge point is designated to be one-third to one-half of the normal operating capacity of the unit. This will vary with some designs and may be one-fourth on the lower extreme to two-thirds on the upper extreme. It is important to know where this surge point (or region) is on any centrifugal machine. During start up, the machine must pass through this region, but it is important for the preceding reasons not to stop and allow the machine to run here, but rather to bring the speed and capacity on through. Usually a constant speed, motor-driven compressor will be equipped with inlet guide vanes to the first wheel to allow suction volume control. If the guide vanes are not used, some other throttling device should be available. Figure 17.73 presents the constant speed performance of a centrifugal machine with inlet guide vanes.

Affinity Laws The affinity laws express the relationship between the head, capacity, speed, and size of centrifugal blowers and compressors. In general these relations can be applied to inlet volume conditions for good preliminary designs, but all final designs apply these laws to the actual discharge volumes from the impeller [69, 77].

Compression Equipment  771 1.08 “K” Value Correction Factor

1.06 1.04

K=

1.02

1.6 K = 1.5

K = 1.396 = AIR

1.0 .98

K = 1.3

“K” Value Correction Factor

.96 .94 .92

K=

.90

1.2

.88 .86

K=

1.1

.84 .82 .80 .78 .76 1.0

2.0

3.0

4.0 5.0 6.0 Compression Ratio, P2 (psia)/P1 (psia)

7.0

8.0

Figure 17.119  “k” value correction factor (used by permission: Cole, S. L., Oil and Gas Journal, V. 58, No. 6, © 1960. PennWell Publishing Company. All rights reserved).

It is essential to remember that these “laws” do not act independently of one another, but a correction/change in one variable requires an evaluation of the other factors to properly present the new/corrected/revised performance of the compressor wheels.

Speed 1. The capacity varies as the speed for fixed diameter:

 (rpm)2  V2 = V1   (rpm)1 



(17.208)

Where sub-1 represents the first, and sub-2 the second condition of operation. The speed cannot be increased indefinitely due to mechanical stresses developed in the rotating impeller and due to the limit of Mach number of 1 for the tip speed and gas velocity. The limitations will vary according to the impeller designs of the various manufacturers.

772  Petroleum Refining Design and Applications Handbook Volume 2 RE

Basic Head

90

E ET

F.

° 20

80

1

70

M

PE

TU RA

K TA IN

F. 0° 10 °F. 80 °F. 60 °F. 40 F. ° 20 . F 0° F. 0° –2

Basic Head, thousands of ft.

60

50

40

CORRECT BASIC HEAD FOR: 1. “K” VALUE OTHER THAN 1.396 2. MOLECULAR WEIGHT OTHER THAN 28.95 3. AVERAGE SUPERCOMPRESSIBILITY OTHER THAN 1.0

30

20

10

0 1.0

2.0

3.0

4.0 5.0 6.0 Compression Ratio, P2 (psia)/P1 (psia)

7.0

8.0

Figure 17.120  Basic head for machine with “k” value for air (1.396), molecular weight for air (28.95), and super compressibility factors neglected (used by permission: Cole, E. L., Oil and Gas Journal, V. 58, No. 6, © 1960. PennWell Publishing Company. All rights reserved).



V = capacity, ft3/min 2. The polytropic head varies as the speed squared 2

 rpm 2  H p 2 = H p1   rpm1 



(17.209)

3. The theoretical horsepower varies as the speed cubed 3

 rpm 2  bhp2 = bhp1   rpm1 



(17.210)

A “new” or calculated point of performance is not defined until all three factors have been determined. It is insufficient to determine one point and draw conclusions, but rather the total effect of the change must be considered.

Compression Equipment  773

“K”

Temperature Rise Multiplier

.5

0

VA LU E

.6

1 .3

1.6 1.5

=1 .39 6

.7

0

1.2 .4

1.15 .3 1.10

.2

Temperature Rise Multiplier

.1

0 1.0

2.0

3.0

4.0

5.0

6.0

8.0

7.0

Compression Ratio, P2 (psia)/P1 (psia)

Figure 17.121  Temperature rise multiplier (used by permission: Cole, S. L., Oil and Gas Journal, V. 58, No. 6, © 1960. PennWell Publishing Company. All rights reserved).

12,000 11,000 10,000 Compressor Speed in Rpm

Compressor Speed, rpm

9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 0

10

20

30

40 50 60 70 Intake Volume, thousands of cfm

80

90

100

Figure 17.122  Compressor speed in rpm (used by permission: Cole, S. L., Oil and Gas Journal, V. 58, No. 6, © 1960. PennWell Publishing Company. All rights reserved).

774  Petroleum Refining Design and Applications Handbook Volume 2

Impeller Diameters (Similar) For two geometrically similar, same family, impeller wheels with the same specific speed and operated at the same rpm. 1. The head varies as the impeller diameters squared. 2

D  H 2 = H1  2  , ft  D1 



(17.211)

2. The capacity cfm varies as the impeller diameters cubed. 3

D  V2 = V1  2   D1 



(17.212)

3. The brake horsepower varies as the impeller diameters to the fifth power. 5

D  bhp2 = bhp1  2   D1 



(17.213)

Impeller Diameter (Changed) When an impeller diameter is reduced, but the speed is held constant, 1. The head decreases as the impeller diameters squared. 2

D  H 2 = H1  2   D1 



(17.214)



Note that diameter, D2, is always smaller in this series of evaluations than D1, the original size of the impeller before cutting or reduction in diameter. 2. The ft3 per min decreases as the ratio of impeller diameters cubed. 3

D  cfm 2 = cfm1  2   D1 



(17.215)

3. The brake horsepower decreases as the impeller diameters to the fifth power. 5

D  bhp2 = bhp1  2   D1 



(17.216)

These relations do not hold closely for large impeller cuts, as the head and capacity drop a little faster than the relations indicate. Allowance should be made by a “trial-and-error” approach when actually reducing an impeller size. Efficiency will remain nearly constant during all of the changes discussed.

Compression Equipment  775

Effect of Temperature For constant intake volume, compressor speed, efficiency, and no throttling, but with discharge pressure changing to reflect the effect of temperature.

T  bhp2 = bhp1  1   T2 



(17.217)

Affinity Law Performance For single-stage or single wheel compressors (sometimes referred to as blowers) the effect of changing inlet or discharge conditions can be rather closely predicted. However, in the case of the multistage machines, the variations in performance as well as the effects of preceding wheel conditions can have a marked effect on the final wheel performance. The last stage wheel gives the performance curve for the machine, but it is valid only when operating in conjunction with the other wheels. The first wheel discharges into the suction of the second; the second discharges into the suction of the third; etc., until the last stage is reached, and it represents the output of the machine. As the gas passes through the machine, its specific volume decreases, and each impeller, therefore, is usually smaller in the gas passageway than the preceding one. Head-Capacity Changes. For a given constant speed, the characteristic operating curve is fixed. The pressure differential between discharge and suction will change with varying suction or system conditions. The pressure differential will increase for any condition that causes increased suction inlet gas density [80]. 1. 2. 3. 4. 5.

I ncreased molecular weight. Increased inlet pressure. Lower or decreased inlet temperature. Lower or decreased gas compressibility factor. Lower or decreased gas “k” value (results in increased gas density entering the diffuser).

Curve 1-1 of Figure 17.123 represents the effect of the increased density inlet gas for a fixed operating speed. Curve 2-2 results from a decrease in the gas density as might be represented by the factors listed. Note that these Curves 1-1 and 2-2 might represent the new rated curve for a particular set of inlet operating conditions. Because most processes cannot fix the gas analysis and system conditions exactly, it is important to recognize the possible implications of changes in the suction conditions on the compressor performance. Figures 17.124 and 17.125 illustrate the effects of temperature and gas density changes on the pressure rise for a constant-speed operation. Constant-speed operation will be encountered, 1. W  ith a motor drive, with or without a gear box. 2. With another drive (such as a turbine), with control set for constant-speed operations. Variable-Speed Operation. Each of the performance curves shown in Figure 17.72 is for a different speed. This illustrates that the characteristics retain their “family” pattern with speed changes. The affinity laws will define all the calculations of performance for the different conditions. Thus, every point on the 100% speed capacity-head curve can be adjusted to the 105% or the 95% speed curves by these laws. The Operating System. Regardless of calculated centrifugal compressor performance, the machine will operate only on or along its operating curve to fit the system of which it is a part. This is quite similar to the system performance of a centrifugal pump. Friction, other pressure drops of the system, and how friction varies with operating conditions determine machine performance.

776  Petroleum Refining Design and Applications Handbook Volume 2

110 100

80

dC urve

Design or Rated Point

Performance Curve Lowers Due to Opposite Effects Listed Above

70 60 50

100

40

80

30 E

20

cy

ien

c ffi

60 40

10 0

Efficiency, %

Discharge Pressure, %

90

Rate

imit

Performance Curve Moves Due to: (1) Increased Suction Pressure (2) Increased Molecular Weight (3) Lower Inlet Temperature (4) Lower Compressibility Factor (5) Lower Ratio Cp/Cv = k

120

Surg eL

130

20 0

10

20

30

40

50

60

70

80

90

100

0

Inlet Volume to Compressor Suction, %

Figure 17.123  Effect of changing inlet conditions on performance curves. Fixed operating speed (adapted by permission: Hancock, R., Chemical Engineering, V. 63, No. 6, © 1956. McGraw-Hill, Inc., All rights reserved).

Figure 17.126A [80] illustrates a system with all line friction. Here, the operations would follow the system curve and operate at the intersection with the speed curve. For example, if the speed is cut 10%, the flow decreases 8%. Figure 17.126B shows a system with essentially constant back pressure. Following the operating system curve shows that a small speed cut back of say 10% results in a flow drop of 40%. Figure 17.126C represents a system comprised of both friction and back pressure resistance. In this case, a speed drop of 10% creates a flow drop of 15%. These examples are for constant suction conditions. For a variable-speed machine and a resistance comprised of friction and back-pressure, Figure 17.127 should be typical [71]. Here again it is important to remember that the compressor will operate only at the points of intersection of the system friction curve and the operating curves for the various speeds. The friction curve is obtained by calculating a few points for given flows using reliable methods for pipeline and equipment pressure drop calculations. This then is what the machine must operate against. At 100% speed the machine operates at Point 1. If the flow is to be reduced to 95% of point 1’s capacity, by the affinity laws, Point 5 would be calculated as x% rpm. The compressor cannot operate at Point 5 because the system head loss curve does not go through Point 5. The curve goes through Point 2, but Point 2 is less than 95% of capacity. Therefore, the machine must operate at about y% of rated speed, Point 3, in order to give 95% of rated capacity. At any constant or steady speed of operation of a compressor, the head-capacity and efficiency curves are characteristic of the impeller and casing design only. Those curves that are determined by test can be translated to other reasonable speeds and conditions of operation of the wheel-casing combination of the affinity laws. The operation of the compressor must meet or establish the desired point on the head-capacity-system curve, which requires a combination of controls.

Compression Equipment  777

Pressure Rise, %

140 120 100

0°F. 60°F. 100°F.

80 60 40

120 Bhp, %

100 80 60

0°F. 60°F. 100°F.

40 40

60

80 100 Inlet Volume, %

120

Figure 17.124  Relative effects of inlet temperature change on head and horsepower (used by permission: A.C. Compressor Corporation).

1.2

Pressure Rise, %

140 120

1.0 Air 0.8

100 80 60 40

120 Bhp, %

100 80 60 40

1.2 1.0 Air 0.8 40

60

80 100 Inlet Volume, %

120

Figure 17.125  Relative effects of inlet gas specific gravity change on head and horsepower (used by permission: A. C. Compressor Corporation).

Control of Performance 1. Speed control Figure 17.128 shows the effect of changing speed on the compressor characteristic curve. The speed can be adjusted to meet a desired point on the system curve. This is the most popular form of control. Centrifugal compressor controls can vary from the very basic manual recycle control to ratio controllers. The driver characteristics, process response and compressor operating range must be determined before the correct

778  Petroleum Refining Design and Applications Handbook Volume 2 (a)

(b)

(c)

100% rpm

90% rpm 100 System Curve 0

100

92 0

100% rpm Differential Pressure, %

Differential Pressure, %

Differential Pressure, %

100% rpm

90% rpm 6 0

0

100

0

Inlet cfm, % Pipeline

System Curve

100

0

100

Inlet cfm, %

105#

50

90% rpm 0

Inlet cfm, %

System Curve 100

100#

50# 100#

Figure 17.126  Effect of gas system flow resistance on comparative performance in same centrifugal compressor (used by permission: Hancock, R., Chemical Engineering, V. 63, No. 6, © 1956. McGraw-Hill Inc., All rights reserved).

Surge

Limit

120

100

y % rpm x % rpm

1 3 2

5 (By Affinity Lows)

+

Ba

ck

80

40

e Syst

20

0

0

ea d mH

20

s Los

r ic eF p i P

tio

n+

e m ip u Eq

4 m rpm z% 0% rp or 10 d e 1 t a R 3 rpm y% 5 rpm2 x%

100 80 Bhp, %

60

nt Lo ss

Discharge Pressure, %

4

100% rpm

40

40

60 Inlet Volume, %

Figure 17.127  System operation of variable speed centrifugal compressor.

80

95 100

120

106 104 102 100 98 96 94

2

1

110 100

1

90 3 80 3

Rated Bhp, %

Rated rpm, %

Compression Equipment  779

70 4 50 1–1 2–2 3–3 4–4

60

2 60

70

90 100 80 Rated Capacity, %

110

120

130

Capacity versus Speed Change Horsepower Change as Speed 1–1 Changes Horsepower Change using Discharge Throttling at a Constant Speed Horsepower Change using Suction Throttling at a Constant Speed All Curves for Compression Ratio of 8:1

Figure 17.128  Typical effects of capacity control on horsepower for centrifugal compressor (used by permission: Stepanoff, A. J., Turboblowers, © 1955. John Wiley & Sons Inc., All rights reserved).

controls can be selected. An efficient method to match the compressor characteristic to the required output is to change the speed in accordance with the fan laws (affinity laws, see Reference [107]). One of the principal advantages of using steam or gas turbines as drivers for compressors is that they are well suited to variable speed operation. With such drivers, the speed can be controlled manually by an operator adjusting the speed governor on the turbine or alternatively the speed adjustment can be carried out automatically by a pneumatic or electric controller that changes the speed in response to a pressure or flow signal. 2. Throttling inlet This is also a very common and simple way to vary the capacity, particularly when using a constant-speed drive. The gas density at the inlet is reduced by the throttling action, but the important point of the system characteristic after the discharge remains unchanged. Throttling takes place at constant enthalpy. An energy loss occurs with this operation; however, it is much less than the loss associated with throttling on the discharge side of the machine. “The pumping capacity in terms of inlet cfm (or mass flow rate) is reduced in proportion to the density decrease, whereas the pumping capacity based on the impeller discharge volume remains the same [71].” 3. Throttling on discharge The power consumption remains constant for this type of operation; thus, no savings are effected by a reduced flow. The pumping point remains unchanged as contrasted to a reduced point for inlet throttling. 4. Other schemes Stepanoff [71] discusses (a) operation at capacities below the pumping point, (b) recovery gas turbine, (c) cut-off capacity control, (d) double-flow blower, (e) power wheels, (f) adjustable diffuse vanes, (g) adjustable impeller vanes, and (h) two-speed gear increasers.

Example 17.15: Changing Characteristics at Constant Speed A constant speed air compressor has been designed for the following conditions:

780  Petroleum Refining Design and Applications Handbook Volume 2 P1 t1 V1 P2 ea Relative humidity. = dry

= 14.7 psia inlet = 90°F inlet = 12,000 cfm inlet (at actual temperature and pressure) = 38 psia discharge = 70% = 0%

After operating at essentially design conditions for one year, the process has been changed to have the inlet temperature drop to 50°F. What will be the new operating conditions: (1) discharge pressure or (2) brake horsepower (bhp)? The suction volume remains the same at 12,000 cfm.

Solution 1. Ratio of compression,



Rc =

38 = 2.58 14.7

2. Adiabatic head for initial operations, ( k −1)/ k   k   P2  53.5   Ha = (T1 ) − 1 Z1   k − 1   P1  sp. gr .  

 1.396  53.5 (460 + 90) [(22.58)(0.396 )/1.396 − 1]  1.396 − 1  1.0 = 32, 000 ft-lbf /lbm = 32, 000 ft. (adiabatic )



=

3. Brake horsepower for initial operations

bhp =



( W )(H) (33, 000)e p



From Figure 17.76, by trial-and-error interpolation, when ea = 0.7, ep = 0.735. Using Figure 17.78 to obtain polytropic head,

Hp = 34,000 ft

Specific volume = 13.85 ft3/lb at suction conditions; the mass flow rate, W:

W=



 ft 3 12, 000 lb  = 866.43 lb/ min  × 3 13.85  min ft 

Gas horsepower,



hpg = Shaft bhp = hpg/0.99 = 1215/0.99

(866.43)(34 , 000) = 1215 hp (33, 000)(0.735)

Compression Equipment  781

= 1230 hp

Alternate bhp by adiabatic calculation:

bhp =

P1V1 ( k / k − 1)[(P2 / P1 )( k −1)/k − 1 229ea

14.7(12, 000)(1.396 / (1.396 − 1))[(2.58)(1.396−1)/1.396 − 1] 229(0.70) = 1200 hp =





4. Discharge pressure for new conditions Speed remains constant, and head remains the same. ( 0.369 )/1.396   1.396   P2  53.5   32, 000 = (460 + 50) − 1   1.396 − 1   P1  1.0 





 P2   P  1

0.284

 P2   P  1

0.284

− 1 = 0.333 = 1.333

P2 = (1.333)1/0.284 = 2.75 P1





Discharge pressure: P2 = (2.75) (14.7) = 40.4 psia, with 50°F suction temperature.

5. Brake horsepower at 50°F, assuming constant polytropic efficiency. Specific volume = 12.7 ft3/lb at 50°F, the mass flow rate, W:

W=





12, 000 = 945 lb/ min 12.7

From Figure 17.76, by trial-and-error interpolation, when ea = 0.7, ep = 0.735. Using ep in the horsepower equation, convert adiabatic head to polytropic head using Figure 17.78.

H = 34,000 ft. (polytropic)



hpg =



(946)(34 , 000) = 1326 hp 33, 000(0.735)

Shaft bhp = 1326/0.99 = 1339 hp

For comparison, at 45°F, constant intake volume, efficiency, speed, and no discharge throttling:

782  Petroleum Refining Design and Applications Handbook Volume 2

 550  bhp = 1230  = 1326 hp  510 



This compares with 1339 bhp calculated by the gas horsepower relation. The values should agree exactly, and the difference may lie in the reading of charts to determine the polytropic head. Using the bhp cal culated with the adiabatic efficiency, ea,

 550  bhp = 1202  = 1296 hp  510 



for the new condition at 50°F suction.

Example 17.16: Changing Characteristics at Variable Speed The original design for a centrifugal compressor was as follows: Gas: process gas, chlorine mixture Condition: bone dry = 10.98 psia inlet P1 = 100°F inlet t1 = 9600 cfm at inlet V1 = 20.7 psia discharge P2 rpm = 7840 bhp = 466 k = 1.33 Gas mol wt = 69.8 Sp. gr. at inlet = 2.4 If process conditions change, and the gas temperature drops to 80°F, what will be the new speed to keep a constant discharge pressure at an intake volume of 8000 cfm? Refer to Figure 17.129. 1. Ratio of compression

Rc = 20.7/10.98 = 1.888 2. Adiabatic head at initial design conditions



 1.33  53.5 (1.333−1)/1.33 (460 + 100) − 1]  [(1.888)  2.4 1.33 − 1 = 8700 ft-lbf /lbm = 8700 ft

Had =

3. New discharge pressure Assuming a constant head from the impeller at 80°F.



8700 =

 1.33  53.5 0.248 (460 + 80)  [(P2 / P1 ) − 1]  2.4 1.33 − 1

(P2/P1)0.248 − 1 = 0.1793



Compression Equipment  783 23 8,000 cfm

Discharge Pressure, psia

22

7,840 rpm, 100°F.

21

7,840

A

20.7psia

20

Original Rated Point

7,050 rpm, 100°F.

19 18

B

6,270 rpm, 100°F.

7,000

7,690

rpm, 8

0°F.

rpm,

80°F.

rpm, 8

0°F.

17 16

500

405

Total Bhp

350

0 ,69

7

300

200 150

4

A

400

, rpm

F.

80°

B

Original 100% Speed 90% Original Speed 80% Original Speed

40

46

0 7,06

rpm

, 100

New Capacity 8,000cfm

52

58

, rpm

°F.

100

40 7,8 Original °F. Rated Point 0°F.

m, 8

rp ,000

7

m 0 rp

7,8

466

450

250

°F.

, 80

550

Original Capacity 9,600cfm

64 70 76 82 88 94 100 106 112 118 124 Inlet Volume, cfm (hundreds)

Figure 17.129  Changing characteristics with variable speed.

(P2/P1)0.248 = 1.1793 (P2/P1) = (1.1793)1/0.248 = 1.944 P2 = (1.944)(10.98) = 21.4 psia with 80°F inlet temperature and a speed of 7840 rpm. Plotted as point A on Figure 17.129. 4. Brake horsepower  560  = 483 hp for 80°F inlet temperature and a speed of 7840 rpm.  540 



bhp = 466 

5. To establish new bhp and performance curves, do the following Try 7000 rpm and related to the 7840 rpm and 80°F curve Vol at 7000 rpm = 9600(7000/7840) = 8600 cfm Had at 7000 rpm = 8700 (7000/7840) = 7800 ft



New discharge pressure:

7800 = (53.5/2.4)(460 + 80) (1.33/1.33 − 1)[(P2/P1)0.248 − 1

784  Petroleum Refining Design and Applications Handbook Volume 2

(P2/P1)0.248 − 1 = 0.1608 P2 = (1.82) (10.98) = 20.03 psia.

bhp at 7000 rpm and 80°F = 483 (7000/7840)3 = 344 hp.



7000 rpm is 89.5% of rated speed.

Plot point B at 8600 cfm, 331 bhp, 8600 cfm, and 18.68 psia. Draw the new lines parallel to the existing curves.

By continuing to calculate new values for pressures and horsepowers for several points of cfm from the 7840 rpm, 80°F curve, the new curve for the 7000 rpm, 80°F may be completed. 6. Obtain the desired rpm for 80°F and 8000 cfm by close calculation of many points or by interpolation from the new curves as established. By cross-plotting and interpolation, for 8000 cfm at 20.7 psia discharge, and 80°F inlet temperature:



Approximate speed = 7690 rpm



Approximate bhp = 405 hp

This can now be verified by calculation at the estimated point.

Side Load Compressors. The design of centrifugal compressors with more than one process stream entering and leaving the unit is common and is used extensively for units handling gaseous refrigerants from ethylene through propane and many other specialty applications. Peters [83] presents a discussion of the performance expected when various process gas streams enter a compressor with multiple wheels on a single shaft. See Figures 17.51B–D for physical illustrations. Some of the streams may be just an exit of the gas for cooling between wheels with the same process gas re-entering the unit and flowing on to the exit, and some streams may in effect be mixing with the initial gas entering the unit as shown in Figure 17.130 [83]. All operating parameters must be considered to make certain that an acceptable operating compressor and process “fit” exist. The key parameter must be evaluated as part of an overall operating analysis and considered independently. Peters [83] points out that the API Specification 617, the ASME codes, and other applicable codes may require some modification when applied to side load compressors. The following list of parameters may have a direct effect on compressor selection: • • • •

Head rise to surge, surge margin, and overload margin. See Figure 17.131. Head per compression section. Compressor parasitic flows (i.e., balance piston leakage, etc.) Excess margins on other process equipment.

Referring to the first bullet item, depending on other parameters specified, this addition of information may have no effect or little effect or may result in nonoptimum compressor selection. Referring to Figure 17.131, a 5% head rise to surge will result in non-optimum efficiency and overload [83], but the 2% level will yield the best efficiency and overload selection. A refrigeration system as shown in Figure 17.130 is one of the most used applications of side-load compressors and requires almost constant discharge pressure. Figure 17.132 indicates that with a required 5% high rise to surge (HRTS), the compressor would trip of stream at 97% of design flow. Even a 2% rise would make the surge margin immaterial. For some process applications, the overall flow ranges 40–50%, and the range on a refrigeration system may be closer to 20–30%. Thus, imposing an excessive HRTS and/or surge margin criteria may result in minimal overload capacity as noted in Figure 17.132 [83].

Compression Equipment  785 Condenser

Compressor

Receiver LC

LC

LC

Economizer 1

Main chiller

Economizer 2

Figure 17.130  Simplified multilevel refrigeration process; an example of three different composition streams entering a single multiwheel case (used by permission: Peters, K. L., Hydrocarbon Processing, V. 60, No. 5, p. 171, © 1981, Gulf Publishing Company. All rights reserved).

Flow selected to get 5% HRTS

Head

2% head rise

5% head rise

Efficiency

tic teris

cie

arac

n

Effi

d ch

Hea

r

ha

c cy

tic ris te c a

Flow selected to get 2% HRTS Flow

Figure 17.131  Effects of 2% and 5% “Head Rise To Surge” (HRTS) (used by permission: Peters, K. L., Hydrocarbon Processing, V. 60, No. 5, p. 171, © 1981. Gulf Publishing Company. All rights reserved).

The head per section is another important parameter, as the lower the number of impellers per section, the higher the head required per compressor stage. This leads to higher rotative speeds and operation at higher Mach numbers, which in turn, tends to limit the operating range, flatten the head rise characteristic, and reduce efficiency [83]. Compressor parasitic flow involves the re-entry of the seal equalization line flows into the main gas stream. If such flows are significant, re-entry at a point other than the main flow may be appropriate for better performance. The true operating point on the compressor section (group of wheels) characteristic may be considerably different when the side (or parasitic flow) is introduced. This situation can be modified by introducing the flow into the first side load [83]. When too many factors of safety are added to the true required design flows, excess margins may affect compressor stability. When the compressor manufacturer begins the design, therefore, unjustified excess capacity flows exist. Be realistic in regard to building in flexibility or capacity. Davis [4] discusses the evaluation of multistage compressors for conversion to new or different process applications.

786  Petroleum Refining Design and Applications Handbook Volume 2

Discharge pressure

Discharge pressure

Inlet pressure variation due to 2% HRTS

Required 15% surge margin Atmospheric pressure

Inlet pressure variation due to 5% HRTS Minimum flow with 5% HRTS

Minimum flow with 2% HRTS 80

90 % design flow

100

Figure 17.132  Effects on inlet pressure for HRTS variations (constant speed drives) (used by permission: Peters, K. L., Hydrocarbon Processing, V. 60, No. 5, p. 171, © 1981. Gulf Publishing Company. All rights reserved).

Troubleshooting. Gresh [85] presents useful mechanical troubleshooting factors to consider in setting up a centrifugal compressor. An important item is the coupling connecting the compressor to the driver (electric motor, steam turbine, gas turbine, gear train, etc.). Several good quality couplings carry the horsepower load between the driven compressor shaft and the driver or driver’s gear unit. These should be carefully evaluated for each specific application. Compressor troubleshooting and probable causes are reviewed later in the chapter.

Expansion Turbines Expansion turbines are related in many design features to the centrifugal compressor. The key exception being that the turbine receives a high pressure gas for expansion and power recovery to a lower pressure and is usually accompanied by the recovery of the energy from the expansion. For example, applications can be (1) air separation plants; (2) natural gas expansion and liquefaction (for gas let-down in pipeline transmission to replace throttle valves where no energy is recovered, see Figure 17.133); (3) generator applications to generate electricity; and (4) waste heat recovery applications that convert the waste to electricity or another useful energy [86, 87]. A Mollier Diagram is useful for the expansion of a specific gas/vapor or multicomponent vapor fluid. See Figure 17.133 for comparison (1) constant enthalpy (Joule–Thompson effect), isenthalpic, and (2) isentropic (constant entropy), which provides the colder temperature [120]. Note that the expander indicated on the figure is somewhere between isenthalpic and isentropic or polytropic. See Figure 17.134 [9, 28]. For best performance, ask the respective manufacturers to present the full energy recovery program for their design and evaluations. The choices of alternate power recovery approaches can be valuable in the final evaluation and performance of a process.

Axial Compressor The axial compressor is usually a single inlet, uncooled machine consisting essentially of blades mounted on a rotor turning between rows of stationary blades mounted on the horizontally split casing. A typical unit is shown in Figures 17.135, 17.136, and 17.137. The stationary blades can be either fixed or movable (Figure 17.138). The movable blades allow for better control of and increased flexibility in operations. Figure 17.139 shows a rotor assembly. Most units will have inlet guide vanes for at least the first row of blades and may have exit vanes. The general size of these machines, is often much larger than the centrifugal compressor, although this is not necessarily a firm

Compression Equipment  787 P1

P2

T1 Enthalpy

Throttling Process Expander Process

T2 (Throttling) T2 (Expander)

Isentropic Process

Entropy

Figure 17.133  Comparison of the energy potential of turboexpanders versus throttle valves (used by permission: Bul. 2781005601. © Atlas Copco Comtec, Inc.).

∫vdP

B.T.U./LB. – MOLE +2493

–2493

B

–844

+1557

–2441

C

–1707

+653

–2360

D

–2315

O

–2315

E

–3075

–856

–2219

V= 0.6 ./LB. 500 CU. FT 400

300

O

600

1.0

300

PATH A-ISENTHALPIC

ROPIC POLY T PATH B-

C

PAT HC

-PO

LY T R

OPI

TR O SEN

D -I PAT H

E-P PA TH

PIC

PIC

1.5

OL YT RO

180

T = 140°F.

220

260

A

INITIAL CONDITION

2.0

3.0

200

150

PRESSURE LB./SQ. IN ABS.

Q

340

∆H

380

EXPANSION PATHS FOR ETHANE PATH

100

FINAL CONDITIONS 400

500

540 ENTHALPY B.T.U./LB.

580

620

80

Figure 17.134  Section of ethane, pressure-enthalpy diagram illustrating five expansion paths (reprinted by permission: Edmister, W. C. Applied Hydrocarbon Thermodynamics, p. 66, © 1961. Gulf Publishing Company. All rights reserved).

788  Petroleum Refining Design and Applications Handbook Volume 2

TO AFTER COOLER OR PROCESS

FROM INTERCOOLER

HIGH PRESSURE CASE

LOW PRESSURE CASE

INLET FROM FILTER

STEPUP GEAR

STEAM TURBINE OR OTHER MECHANICAL DRIVE

TO INTERCOOLER

Figure 17.135  Typical geared-turbine-driven axial flow compressor unit (used by permission: Dresser-Rand Company).

CASE INLET GUIDE VANE STATOR BLADES ROTOR BLADES OIL INLET

THRUST BEARING

EXIT GUIDE VANE ROTOR DISC TIE BOLT SEAL OIL INLET

ROLLER BEARING PILOT RING

OIL SCAVENGE PROVIDED IM ATTACHED PARTS

Figure 17.136  Cross section of typical nine-stage axial flow compressor (used by permission: Dresser-Rand Company).

condition. The casings require extremely good casting to obtain the shapes usually associated with the arrangements of these machines. The sealing systems for the shaft are quite similar to those for the centrifugal; however, internal shaft seals are not necessary between stages. The materials of construction are similar to those for the centrifugal compressor.

Compression Equipment  789

Figure 17.137  Axial compressor Type AV 100-16, during erection. Note stationary and rotating blades. Two identical steam turbine-driven machines supply air to blast furnace at steel works. Suction volume = 560,000 Nm3/h; discharge pressure = 6.2 bar; power input = 52,000 kW each (used by permission: Bul. 26.13.10.40-Bh. © Sulzer Turbo Ltd.).

Figure 17.138  Stator blade control mechanism on four-stage axial compressor (used by permission: A. C. Compressor Corporation).

790  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.139  Axial rotor assembly (used by permission: A. C. Compressor Corporation).

140 100% Speed Sur ge Line

Pressure Rise, percent of Design

120 100

90% Speed 80 80% Speed 60 70% Speed 40 60% Speed 50% Speed

20 0

0

20

40 60 80 100 Inlet Volume, percent of Design

120

Figure 17.140  Performance of axial compressor at various speeds (used by permission: Claude, R. E., Chemical Engineering, V. 63, No. 6, © 1956. McGraw-Hill, Inc., All rights reserved).

Operating Characteristics The typical operating characteristic of the axial machine is shown in Figure 17.140, for a fixed stator blade unit capable of operating at variable speed. Figures 17.141, 17.142, and 17.143 show approximate speed-capacity comparisons with the centrifugal machine. Each stage consists of one stationary plus one rotating blade row. Figure 17.143 shows an axial compressor performance handling 100 psia air. The operation of an axial compressor accomplishes approximately one half its pressure rise as the gas passes through the stationary blades and the other half as it goes through the rotating blades. The static pressure and kinetic energy increase as the gas goes through the machine. The analogous comparison between an axial and a centrifugal machine is stationary blades to diffuser and diaphragm and rotor blades to impeller wheel.

Compression Equipment  791

Pressure Rise, percent of Design

140

All Curves for 100% Speed

120

Pumping Limit-min. Setting and Reduced Speed

100

Pumping Limit and Reduced Speed

80

60

40

Centrifugal

Axial

Pumping Limit-Base Setting and Reduced Speed Base Setting

Minimum Setting

Pumping Limitmax. Setting and Reduced Speed

Maximum Setting of Stator Blade, could be moved toward Base Setting to Approximate Centrifugal range even closer.

20 0 0

100 40 60 80 Inlet Volume, percent of Design

20

120

140

Figure 17.141  Stable volume range extended by stator blade control (used by permission: Claude, R. E., Chemical Engineering, V. 63, No. 6, © 1956. McGraw-Hill, Inc., All rights reserved).

140

ng tti Se

A

peed

90% S 0%

ed

peed

peed

90%

Spe

100% S

100% S

Pu mp Pu ing L mp im it C ing Lim entri fug it M al in. Se tti ng

100%

ing

ing

%

%

50

%

60

Speed ed

70%

gal 8

d Spee

100%

60 60%

80%

Cent rifu

Spe

trifugal

50

20

ng

%

g pinCen

m Pu

Centrifugal

Lim

.

ax

70%

80

%

80

40

it M

al

Setti

%

60

C

Centrifu g

.

90

B

ett

ett

Min

80

x. S

eS

Centrifugal

100 Pressure Rise, %

Ma

Bas

120

%

0 10

20

30

40

50

60 70 Inlet Capacity, %

80

90

100

110

120

Figure 17.142  Pressure – capacity characteristic compression of an axial compressor with adjustable stator blades with a centrifugal compressor (reprinted with permission: Lowell, W. O. Petroleum Refiner, V. 34, No. 1, © 1955. Gulf Publishing Company. All rights reserved).

Gas Velocities General guide lines for good design practice [88] indicate an axial velocity for air of 300–450 ft/s. For other gases, the axial velocity range is in direct proportion to the speed of sound of the gas compared to air. The internal shape of the machine is usually arranged to give constant gas velocity as the gas travels through.

792  Petroleum Refining Design and Applications Handbook Volume 2 140 RP M

100

130

F.

EF

120

90 PEAK PRESSURE RISE CURVE

110

PERCENT PRESSURE RISE

90

% RPM

DESIGN POINT

BHP

100

90% 80

90 95

100%

100

% OF PEAK EFF.

85

80%

95

70%

80

90

% BHP 60%

70

85 50%

70

60

80 75

50

70

40

60

30 50

20 10 0

0

10

20

30

40

50

60

70

80

90

100

110

PERCENT OF INLET FLOW

Figure 17.143  General axial flow compressor performance for typical 100 psia air compressor (used by permission: Dresser-Rand Company).

Stages As a general rule-of-thumb, the axial compressor will require about twice as many stages for a given requirement as the centrifugal compressor [88]. The maximum number of axial stages is approximately 16. The temperature rise limitations as well as structural problems also limit the maximum stages for a given application.

Volume The size is determined by the inlet volume. The unit will generally be smaller than the equivalent-rated centrifugal compressor [88]. The larger the inlet volume, the more advantage develops for the axial machine. The lower volume limit is approximately 5000 cfm, but the upper limit practically does not exist. That is, units have been built to handle well over a million cfm.

Horsepower The horsepower characteristic is shown in Figure 17.144.

Efficiency The efficiency of the axial is about 8–10% higher than the comparable centrifugal. Thus, the driver power requirements are lower for this type of unit [88].

Compression Equipment  793 20,000

Speed Determined by Gas Conditions and Desired Head

16,000 15,000 14,000 13,000

Axia

12,000

120

l

110 100

Horsepower

10,000 9000

90

al ifug ntr

80

Ce

8000

70

7000 Note: Inlet cfm is not only Factor in Establishing Rated Speed.

6000

60 50

5000 4000

Speed

3000

Axial

40 30

To 500,000 to 1,000,000 cfm

Centrifugal

2000 1000

Rated Hp, %

Compressor Speed, rpm

11,000

20 10

0

20

40

60

80

100

120

140

160

180

200

Inlet Capacity, Mcfm

Figure 17.144  Speed comparison between axial and centrifugal compressor (used by permission: A. C. Compressor Corporation).

Liquid Ring Compressors This type of compressor is unique in that a centrifugal action on the sealing liquid creates a reciprocating type of action on the gas or vapor being handled. Figures 17.145A–C and 17.146 show the multi-bladed rotor rotating in a ring of liquid in the elliptical casing. “The eccentric path of the revolving liquid ring produces an out and in, or reciprocating radial motion to each liquid piston relative to its rotor cylinder, which revolves about the fixed center [89].” As the unit operates, the liquid discharges with the gas or vapor through the discharge ports, and at the same time, make-up or seal liquid is admitted to keep the pump complete with the proper amount of liquid. Note in Figure 17.145A that the various operational sections of the functioning unit are indicated; however, these sections may vary mechanically between the competing manufacturers, but the general concept is the same. Generally this type of unit serves to compress gases from vacuum up to atmospheric pressure. Often after initial startup, the unit must pump-down the system (such as a closed process system of vessels) by gradually bringing down the absolute pressure to the desired operating level and then maintaining the status of the system by discharging to atmospheric pressure for air. In the case of the process gas or vapor compressor design, the maximum operating pressure may reach 130 psig. For a more complete discussion of this and other systems using this style of vapor compression, useful references are Huff [5] and Patton [96].

794  Petroleum Refining Design and Applications Handbook Volume 2

Operating Characteristics Capacity Compressors are available for vacuum as well as positive pressure service. Vacuums are obtained to 29 in. Hg abs and pressures up to 125 psig, with volumes of 2–25,000 cfm.

Temperature Rise The temperature rise during compression when using water as the sealing liquid is approximately 4°F for vacuum service to 21 in. mercury vacuum and entering air not greater than 59% saturated [89]. At vacuums above 21 in., the temperature rise is approximately 4°F plus 2°F for each in. of vacuum greater than 21 in. For a compression operation handling some condensable vapors, the temperature rise will be approximately 13°F. These values are considerably lower than for conventional polytropic compression. They are almost isothermal and demonstrate the contact cooling that takes place during compression.

Seal Liquid The seal liquid may be water or any other liquid suitable for cooling, sealing, or even neutralizing the vapors being compressed.

Horsepower The horsepower is established by the manufacturer by testing the various types of models. In general, the horsepower requirements will be a combination of the power to pump the liquid inside the compressor casing plus the power to compress the gas or vapor. If a recirculating seal liquid system is used, the recirculating pump horsepower is not reported as a part of the compressor requirements.

BODY INLET SECTOR

COMPRESSION SECTOR

ROTATING LIQUID COMPRESSANT

GE HAR DISC TOR SEC

INLET PORTS

ROTOR

GE HAR DISC CTOR SE

COMPRESSION SECTOR

DISCHARGE PORTS INLET SECTOR

SCHEMATIC SECTION AT INLET AND DISCHARGE SECTORS

Figure 17.145A   Functional operational schematic of Nash liquid ring compressor (used by permission: Bul. 474-D., p 3., © Nash Engineering Co.)].

Compression Equipment  795

Figure 17.145B  A partly disassembled Nash liquid ring compressor view shows the pump body, the rotor, the cone, and the separate bearing blocks (used by permission: Bul. 778-A2/89, p.5, © Nash Engineering Co.).

Figure 17.145C   In a compound pump, the gas is compressed in two stages. First, the gas is compressed in the larger low-pressure section and then transferred through the cross-over and internal passageways to be compressed in the smaller, high pressure stage (used by permission: Form 4114. © Kinney Vacuum Division, Tuthill Corporation).

Applications The outstanding applications include: 1. 2. 3. 4. 5. 6. 7.

 il-free process gas, such as air for sanitary uses, etc. O Hazardous and toxic gases. Hot gases and vapors. Jet and surface condenser. High vacuum, single-stage to 27 in. Hg vacuum; two stage to 29 in. Hg vacuum. Solvent recovery from seal liquid. Non-pulsating flow.

Figures 17.146 and 17.147 illustrate system connections for gas compression and vacuum service.

796  Petroleum Refining Design and Applications Handbook Volume 2 To Other Instruments Controller Air receiver

Dryer Equipment if Required Pressure Reducer Control Valve

C Drain Trap

Water Separator

Inlet Compressor

Figure 17.146  Liquid ring compressor as gas compressor (used by permission: Nash Engineering Company). Extra Priming Connection

Pump Inlet

Vacuum Priming Valve Compound Gauge Pressure Gauge Pressure Switch Discharge

Grade this Line Carefully No Pockets Permissible

Vacuum Gauge

Suction Line Avoid Pockets

Relief Valve

Outlet Check Valve Priming Pump

Seal Water Connection

Check Valve

Figure 17.147  Automatic operating of primer by pressure control (used by permission: Nash Engineering Company).

Rotary Two-Impeller (Lobe) Blowers and Vacuum Pumps Figures 17.148, 17.149, and 17.149A show an exploded view of a typical positive displacement blower. The impeller lobes rotate in opposite directions on parallel mounted shafts (Figure 17.149). One serves as the drive shaft and drives the other through the gears. A timing hub allows for adjusting the timing angle of the lobes. The rotation may be either for upward, downward, or side gas flow. When liquid is entrained in the gas, the downward flow is preferred to assist in case of drainage. The lobes do not touch each other or the casing during operation. The separation is a few thousandths of an inch. There is no internal lubrication; thus, the units can operate in a dry gas service. The bearings and gears are mounted externally to the gas chamber and are separated by stuffing box seals to prevent gas leakage along the shaft. The packing is usually vented to the suction, so that it is necessary to pack only against suction pressure. For atmospheric air intake, an air filter and silencer are required. The air filter is to keep out dirt in the air and the silencer is to reduce the local noise level.

Construction Materials Most units are good-grade cast iron for the casing and lobes. The shafts are high-grade carbon, alloy steel, or stainless steel. Conventional packing boxes are usually satisfactory because operating pressures are not extremely high.

Performance The discharge pressure on these constant-volume machines (at constant speed) is determined by the system pressure. No suction or discharge valves are on this type of machine, as it is not designed for a specific pressure. Being positive

Compression Equipment  797 Inlet or Outlet Case

Inlet or Outlet

Lobes

End Cover

Timing Gear

End Plate

Figure 17.148  Lobe-type blower construction (used by permission: Sutorbilt Corp., Div. Garden Denver Corporation).

displacement in principle, it discharges to match the controlled discharge side pressure. They may be operated as vacuum pumps or compressors. The rotating lobes push the constant volume of gas trapped between the lobes and the casing out of the discharge opening. With each revolution, the blower delivers a fixed amount of gas measured at the inlet conditions. The pumping or compression cycle repeats four times for every revolution of the drive shaft. Due to the operating clearances, some gas “slip” occurs. That is, some gas slips by the clearances back to suction as the lobes rotate, creating a loss in pumping efficiency. This slip is larger for high discharge pressure and low gas densities. The rate of gas delivery is



cfm = (blower rpm − slip in rpm) (D) , ft3/min

(17.218)

where D = blower displacement, ft3/rev. The slip is constant at constant pressure, and at high pressures and low speeds, it becomes a considerable percentage of the total capacity. Lower volumetric efficiencies result under these conditions. The discharge flow may have some pulsing characteristics depending upon the blower speed; the lower speed exhibits more pulsing. Typical performance curves for this type of machine are given in Figures 17.150 and 17.151 for constant-speed operation. The capacity and brake horsepower (bhp) for other constant speeds are also represented. Note that the capacity increases as the speed, and the bhp varies directly with the speed and pressure. Increasing the speed against a constant pressure increases the volume pumped by an amount directly related to Equation 17.218. As a guide, the temperature rise for rotary lobe units is 13°F per psi pressure. The maximum discharge pressure usually ranges from 14 to 18 psig and depends entirely on the back pressure into which the unit is discharging to develop its required head. The discharge pressure is limited by the design strength of the casing and other parts and by the available horsepower.

798  Petroleum Refining Design and Applications Handbook Volume 2

POSITION 1

POSITION 2

POSITION 3

POSITION 4

Conventional blower/gas pump 140% 100% DISCHARGE PRESSURE 60% Two ”Figure 8” lobe impellers, mounted on parallel shafts, rotate in opposite directions. As each impeller passes the blower inlet, it traps a definite volume of air and carries it around the case to the blower outlet, where the air is discharged. With constant speed operation, the displaced volume is essentially the same regardless of pressure, temperature or barometric pressure. Timing gears control the relative position of the impellers to each other and maintain small but definite clearances. This allows operation wihtout lubrication beingby permission: Bul. 12 x 95 Rev. 8/97 and Bul. B-5219 Rev. 1/97. © Roots Div. Figure 17.149  Operating principle for two-lobe blowers (used required inside the air casing. Dresser Industries, Inc.).

Capacity Units of this type are available for capacities of a few cfm to approximately 50,000 cfm. The capacity rating of blowers manufactured by most companies are similar; however, the basis of an inlet ft3 per min volume flow can vary depending on the design ratings published in the respective literature. It is therefore important to examine the particular reference standard carefully. Most units are rated for air and must be corrected by the factory representative for conditions of other process gases. a. U  sual pressure practice is a standard based on Compressed Air and Gas Institute and the American Society of Mechanical Engineers: 14.7 psia, 68°F and 36% relative humidity (RH), or the equivalent air density of 0.075 lb/ft3. b. Vacuum ratings are based on 68°F and a discharge pressure of 30 in. Hg, sp. gr. for air = 1.0 c. For conditions of the actual inlet flow to blower, convert to actual ft3/min (acfm):

Compression Equipment  799

POSITION 1

POSITION 2

POSITION 3

POSITION 4

Whispair blower/gas pump 120% 100% DISCHARGE PRESSURE 80%

The Whispair® blower operates on the same basic principle as all other rotary positive displacement blowers with one important advantage – units with the Whispair design offer reduced pulsation, operating noise and power loss by utilizing an exclusive wrap-around plenum to control pressure equalization. Whispair blowers have a proprietary jet to feed backflow in the direction of impeller movement, aiding rotation and lowering power requirements. Incoming air is trapped by the impellers and moved through the machine as in the basic rotary positive displacement principle. As pressure builds against the

wrap-around plenum due to system resistance, the Whispair blower jet equalizes the pressure between the trapped air and the discharge area. This action reduces shock and feeds the backflow in the direction of rotation. As the impeller completes its cycle, it discharges the trapped air, which now has the same pressure as the discharge line. Backflow is controlled, resulting in reduced proves efficiency, reduces noise level, and increases bearing and gear life.

Figure 17.149A  Roots Whispair ® Blower principle (used by permission: Bul. B-05 x 93, Rev. 7/97 and Bul. B5219, Rev. 1/97, © Roots Div., Dresser Industries, Inc.).

Bhp, %

140

peed

100

100% S 75 50

Horsepower

60

Inlet Volume, %

20

120

Capacity

100% Speed 75

80

50

40 15

30

45

75 60 Pressure Rise, %

90

105

120

Figure 17.150  Typical performance curve for lobe-type blower (used by permission: © 1961. Roots Division Dresser Industries, Inc.).

800  Petroleum Refining Design and Applications Handbook Volume 2 150

120% Pressure

Bhp, %

125

100

100

80

Horsepower

75

60

50

40

25

20

0

20% Pressure 40 60 80 100 120

Inlet Volume, %

125 100

Capacity

75 50 25 0 0

25

50

75 Speed Rise, %

100

125

Figure 17.151  Typical performance curve for variable-speed operation for lobe-type blower (used by permission: © 1961. Roots Division, Dresser Industries, Inc.).

acfm = scfm

where Ps Pb Pa RHs RHa PVs PVa Ts Ta scfm acfm

[Ps − (RH s × PVs )(Ta )(Pb )] [Pb − (RHa × PVa )(Ts )(Pa )]

(17.219)

= standard pressure, psia, 14.7 = atmospheric pressure, barometer (psia) = actual pressure (psia), suction = standard relative humidity, 36%, fraction = actual relative humidity, % fraction = saturated vapor pressure of water at standard temperature (psi)* = saturated vapor pressure of water at actual temperature (psi)* = standard temperature (°R); °R = °F + 460; °F = 68° = actual temperature (°R) = standard conditions of 14.7 psia, 68°F and 36% relative humidity = actual flow conditions, ft3/min * From water vapor or steam tables

Note: relative humidity values apply only for water vapor. Saturated process vapor (with water or process vapor) is to be omitted for most process gases. However, it is important to determine the correct total volume of vapor that the compressor is to handle by discussing the requirement with a qualified equipment manufacturer. The pressures in single-stage machines are limited to about 15 psig with a few models good for 20 psig. In a multistage arrangement, the pressures can go to 30 psig. In vacuum service, the inlet pressure can be down to 8 in. Hg abs. In some applications the clearances wear or change, and the lobes must be built up by metalizing or baking on coatings. In water seal units, the clearances may be maintained by allowing the seal water to deposit carbonate scale on the casing and lobes, under controlled conditions.

Compression Equipment  801

Efficiency The volumetric efficiency varies with the speed of operation, being lower at lower speeds and higher for low discharge pressures. As a general guide, the orders of magnitude of efficiencies are as follows: Speed, rpm

Volumetric eff.

Pressure range, psig

360

80–95

14 to 1.0

588

70–82

14 to 1.0

720

90–97

14 to 1.0

The maximum speed for these machines ranges from 500–4000 rpm, depending upon bearing design and unit size. For comparison selections refer to Huff [5] and Patton [96].

Rotary Axial Screw Blower and Vacuum Pumps These units are rotary positive displacement compressors that operate somewhat like the lobe-type blowers; however, in the case of the axial screw units, the gas passing through receives compression from the internal meshing of the screw-like rotors (Figure 17.152A). The resulting compression is a modified adiabatic process [90]. Several different units use screw designs as shown in Figures 17.152B and 17.152E. The screw surfaces do not touch each other or the casing wall as they rotate. The gas being handled flows axially through the unit, with most of the compression taking place just before discharge. The amount of this compression is determined by the arrangement of the discharge opening. By changing discharge valve positions, the internal compression can be changed to give improved performance or different discharge pressure. The spiral-lobe and helical-screw compressors are rotary positive-displacement machines and quite adaptable to a wide assortment of process and refrigeration gases. This class of equipment is usually built to comply with the American Petroleum Institute Standard #619. These units operate at higher “tip” speeds than the straight “lobe” type units and are capable of higher compression ratios.

Figure 17.152A  A typical cross-section showing the spiral screw rotors, lubricating system, and other details of internal construction (used by permission: © 1961. Roots Division, Dresser Industries, Inc.).

802  Petroleum Refining Design and Applications Handbook Volume 2 How Axi compressors work 1 Gas enters the intake ports and flows into

a pocket created between the rotors and the wall of the casing. 2 The pocket—now full of gas—rotates away from the intake and is ready to join its mating pocket. 3 Then, as the lobes and grooves roll into each other, the mating pockets merge and begin to shorten. Thus, the gas trapped inside is compressed as it is forced— axially—towards the discharge end. 4 As it continues its journey the gas is further compressed until it is pushed through the discharge ports.

1

2

3

4

Figure 17.152B   Type H Axi ® Helical Rotor positive displacement compressor. Applications include gases with entrained liquid, oil-free, low mol wt. gases and a wide range of operating conditions (used by permission: Form 11232-A, © 1987. Dresser-Rand Company).

COMPRESSOR OUTLET END COVER

ROTOR THRUST BEARING ASSEMBLIES

SUCTION

ROTOR THRUST BALANCE PISTONS ROTORS

DRIVE SHAFT SEAL ASSEMBLY

HYDRAULIC CYLINDER

CAPACITY DISCHARGE CONTROL VALVE ROTOR JOURNAL BEARING

COMPRESSOR MAIN CASING COMPRESSOR INLET END COVER

OIL INJECTION TUBE

Figure 17.152C  Exploded view of a screw compressor (used by permission: Price, B. C., Chemical Engineering Progress, V. 87, No. 2, p. 51, © 1991. American Institute of Chemical Engineers. All rights reserved).

Compression Equipment  803

Figure 17.152D  Rotor set for oil-free rotary screw compressor (used by permission: Bul. CCB-0057-3-295. A C Compressor Corporation).

The Type L axi compressor consists essentially of two mating helical rotors inside a casing. As the rotor sturn away from each other on the inlet side, air or gas is drawn into pockets formed between them and the casing wall. The pockets move helically along and around the axes, then join and diminish in size; thus the Axi provides internal compression, unlike the straight-lobe blower types. The result is significantly higher efficiency and less power cost.

INLET SIDE At the inlet, pockets form between the rotors and the casing wall, and draw in the air.

DISCHARGE SIDE As the rotors turn, mating pockets join and reduce in volume, compressing the air.

The pockets move along and around the axes while diminishing in size.

Figure 17.152E  Type L Axi ® Helical rotor assembly and rotation details (used by permission: Form 11193-F, © 1987. Dresser-Rand Company).

804  Petroleum Refining Design and Applications Handbook Volume 2 The general construction features and materials are quite similar to the lobe type units [91]. For comparison selections, refer to Huff [5], Patton [96], Price [92], Abraham [93], and Van Ormer [94].

Performance The general performance of units is shown by the curves of Figures 17.153, 17.154, and 17.155. The range of suction volumes is approximately, 175–35,300 scfm per minute, and the units are capable of discharging up to 580 psi. In vacuum application, the units can draw down to 1.3 psi abs [95]. Two types of these units are: 1. D  ry machines use shaft-mounted gears for proper meshing of the rotors and can compress gases free of entrained water vapor and other contaminants [95]. 2. Liquid injected units do not usually require gearing for proper meshing of the counter-rotating screws. The injected liquid, Figures 17.152A–F, can be clean demineralized water, oil, or other fluid that separates the two screws. Liquid injection has its advantages: (a) internal cooling that reduces potential explosion hazards or polymerization and (b) higher compression ratios (often one stage with liquid can do the job of two stages dry) [95]. The rotary screw compressor is designed for a specific compression ratio (i.e., discharge pressure divided by intake pressure). If the pressure rises on the system into which the rotary screw is discharging, the unit will perform up to the physical limits of strength of the casing and the available input power to the shaft. As the discharge pressure falls, the compression ratio falls for a fixed inlet condition, and the efficiency of the unit decreases. The total power input to the shaft is composed of the following [95]: a. E  nergy of adiabatic compression of the gas. b. Dynamic-flow power loss (typically 10–15% of the actual power). This is a function of the built-in compression ratio and the Mach number at the compressor inlet conditions. c. Mechanical losses (typically 8–12% of actual power). These losses include viscous or frictional losses due to bearing, timing, and step-up gears.

Inlet Volume, %

130 110

Inlet Volume

90

120

Bhp, %

100

Brake Horsepower

80 60 40

0

10

20

30

40

50 60 70 Pressure Rise, %

80

90

100

110 120

Figure 17.153  Typical constant-speed performance of spiral screw rotor compressor (used by permission: © 1961. Roots Division, DresserRand Industries, Inc.).

Compression Equipment  805 CFM Inlet Conditions

5000

78 %

8400

77 %

76 %

8600

Comp. Shaft RPM

7600

100

0H

.5% 79

7200

P

79 %

78 .5 %

8000

900

6800

%

80

800

4500

HP

HP

6400 700

6000

4000 HP

5600 3500

5200

% 80

.5%

%

79

79

4800 4400

tic

ba dia ll A

4000

%

78

.5%

78

%

77

%

76

cy ien

c Effi

600

3000

HP

era Ov

3600 500 450

3200 350

2800 2400

300

2.6

2.8

400

HP

HP

2000

HP

3.0

3.2

3.4

Absolute Compression Ratio Inlet Pressure 14.7 PSIA

HP

2500

HP

Gas Handled: Air

Relative Humidity 36%

3.6

3.8

4.0

Inlet Temperature 68°F. Cp/Cv = 1.4

NOTE: Curves are approximate. Use for preliminary compressor selection only.

Figure 17.154  Performance characteristics for a typical single-stage rotary helical rotor compressor, using matching helical rotors (used by permission: Fairbanks, Morse, & Co. for easier editions. [Company no longer exists producing compressors, 1998, per research information]).

Referencing to the comprehensive article [95] on this class of equipments by Bloch and Noack, an abbreviated listing of the advantages and disadvantages of this equipment is given in the following sections:

Advantages 1. 2. 3. 4. 5. 6. 7. 8.

 reatly reduced sensitivity to molecular weight change. G Greater tolerance for polymerizing conditions. Ability to accept liquid and fine solids entrainment. Higher efficiency and less maintenance than the liquid rings units. Estimated availability >99.5%. Smaller size and lower capital cost than same capacity range of reciprocating compressors. Higher pressure capabilities (compared to other types of rotary positive-displacement units). Oil-flooded units operate over wider range of compression ratios (compared to dry units), due to better temperature control.

80 70 60 50 3900 3800 3700 3600 3500 3400 3300 3200 3100 3000

Effic

ienc y VACUUM PERFORMANCE CURVES Based on 30° barometer 68°F inlet temperature and 36% relative humidity, except as otherwise noted* wer epo Hors

Vo lu

me

2

4

6

8

10

12

14

16

18

20

180 160 140 120 100 80 60 40 20

HORSEPOWER REQUIRED AT COUPLING

ACTUAL DELIVERED INLET VOLUME-CFM

OVERALL EFFICIENCY %

806  Petroleum Refining Design and Applications Handbook Volume 2

22

NET VACUUM-INCHES OF MERCURY *Note Performance based on water injection; 3 to 4 gallons per min. op ox.

Figure 17.155  Typical test results of a medium-capacity spiral lobe compressor vacuum pump using intermeshing lobes (used by permission: Ingersoll-Rand Co.).

Disadvantages 1. S ensitivity of close tolerances to discharge temperature, affecting operability. This problem can be solved by proper cooling and temperature control. 2. Affected by corrosion and erosion of the rotor and casing, increasing the gas-slip internal recycle. This problem is not serious for water-or oil-injected screws. 3. Requires pulsation suppression. 4. Selection of construction materials for rotors and casings is more limited than for centrifugal compressors. 5. Maintenance cost and length of down time are higher than for centrifugal units. 6. Flexibility in flow control is not as good as centrifugal or axial compressors. 7. High noise level, but this can be reduced.

Efficiency The overall compression and mechanical loss efficiency of these units average between 70% and 75%. Peak values will reach 78%, and on the extremes of the performance curves, the values reach 60–65%. The efficiency increases with the larger units and at higher speed operations.

Speed Usually these units are run at 1750–3600 rpm; however, they may be belt, gear, or steam turbine driven at any reasonable speed consistent with the rating of the compressor gears.

Capacity The capacity ranges up to 12,000 (and sometimes greater) cfm inlet volume with a discharge ranging from 3–20 psig in single case units. Special units reach 60–100 psig. Multiple cases carry the pressures to higher values. The units also handle vacuum service of 500–10,000 cfm from 5 in. Hg to 25 in. Hg vacuum (25–5 in. Hg abs). Water may be sprayed into the unit to help maintain the higher vacuums by keeping the temperature below 125°F.

Compression Equipment  807

Slip The slip for this type of compressor is similar to that of the lobe units; however, the passages are basically different, and this changes the approach to slip correction. The manufacturer should be consulted for data specific to a particular unit. The slip is dependent on the pressure differential across the unit and the gas density. It does not vary with speed or length of the rotor.

Total Capacity

VT = Vs′ + V1

(17.220)

where VT = total internal capacity pumped, cfm Vs′ = slip cfm V1 = intake volume, cfm

Temperature Rise Estimate as for usual adiabatic calculation.

Rotary Sliding Vane Compressor The sliding vane compressors and vacuum pumps have internal sliding vanes mounted longitudinally on an eccentric rotor in the body casing (Figures 17.156 and 17.157). The body cylinder is usually cast iron with integral internal water jackets for cylinder wall cooling. These water jackets are tested for tightness. The rotor (forged steel) may or may not be an integral part of the shaft. In any case the material for both rotor and shaft is usually a high-strength alloy cast iron. The rotor has radial slots machined along its entire length. The blades or vanes are of heat-treated phenolic resin, metal, or material that is suitable to withstand the gas and the pressure fit in these slots. Because these machines require internal lubrication of the sliding-vane surface, no extreme effort is made to arrange special bearing and shaft seals, except that a gas seal or the conventional mechanical design is usually used to prevent gas from escaping to the outside or to prevent air in leakage in the case of vacuum service. For hazardous or corrosive gases, extra care is used in the shaft seals. Lubrication is of the forced-fluid type for both the inside of the cylinder and the bearings. The oil or other lubricant is usually injected into the entering nozzle on the machine to ensure a running surface between the vanes and the cylinder wall. This also effectually seals against gas slippage between the compartments.

Performance These machines are positive pressure in operation because no internal means exist for the gas to bypass from discharge to suction. The units may be belt, gear, or direct driven. Single operating units generally can develop differential pressures to 60 psig maximum while being limited to a discharge temperature of 350°F. When applied as a booster compressor, the units can develop discharge pressures of 250 psig. These booster units are designed for the higher rated service. When two units are operated in series as a two-stage assembly, usually required intercooling of the gas occurs from the discharge of the first to the inlet of the second unit. Generally, the two-stage units can operate with larger throughputs and discharge pressure from 100 to 125psig. When used as a vacuum pump, these single-stage units can pull vacuum down to 27 in. of mercury vacuum (not absolute) and handle approximately 1800 ft3/min. As two-stage vacuum pumps they can pull vacuum to 29.97 in. mercury. Speed ranges for single-stage and two-stage units are from 500–1180 rpm. Consult manufacturers for design-­ capacity ratings. As the cycle starts, the vane passes over the intake port, and the space (A) in Figures 17.156 and

808  Petroleum Refining Design and Applications Handbook Volume 2

SEAL RING RETAINER

WATER JACKETS

NON-RETURN VALVE OUTLET

BEARING SHIMS CYLINDER HEAD GASKETS

CYLINDER HEAD GASKETS

RETAINER GASKET FRONT RETAINER

CYLINDER HEAD STUDS & NUTS

RETAINER GASKETS

ROTOR SLOTS

SPACER

HUB SEAL RING

BLADES NOT SHOWN ROTOR

FIXED END CLEARANCE

EXPANSION END CLEARANCE

REAR RETAINER

SPACER

BACKING-OFF PIN

LOCATING COLLAR REAR END CYLINDER HEAD

DOWEL PIN EXPANSION BEARING

CYLINDER-JACKET WATER OUTLET

NON-RETURN VALVE

COMPRESSION POCKETS

WATER JACKETS

CYLINDER INTAKE

NOTE! AXIAL MOVEMENT OF ROTOR IS NOT RESTRICTED

FRONT END CYLINDER HEAD

FIXED BEARING NOTE! AXIAL MOVEMENT OF ROTOR IS RESTRICTED

ROTOR

A

B

BLADES

INLET PORT

INLET

OUTLET

REGULATOR BODY

RELIEF LINE TO REGULATOR OUTLET PORT

CYLINDER-JACKET WATER INLET

BOTTOM CLEARANCE (ROTOR TO CYLINDER)

CYLINDER SUB BASE

Figure 17.156  Cross-section of sliding-vane rotary compressor (used by permission: Fuller Bulk Handling).

PIN TYPE COUPLING

Compression Equipment  809

Figure 17.157  Coupling drive end of Ro-Flo Sliding Vane compressor showing vanes in rotor or shaft slots and bearing and shaft seal (used by permission: Bul. CCV-0072-2. © A. C. Compressor Corporation).

17.157 fills with gas at suction conditions. The completion of the filling takes place near the point of maximum volume between the vanes. Then as the enclosed chamber (B) rotates toward the discharge, its volume becomes smaller as the vanes are forced to recede due to the eccentric position of the shaft. At the point of minimum volume and maximum compression, the gas discharges from the machine. These machines will not compress until the speed is sufficient to throw the vanes against the cylinder walls; thus, the machine always starts unloaded. These compressors have no inlet or outlet valves because they discharge against the system pressure. The operation is free from pulsing flow. Typical performance curves are shown in Figure 17.157A. For comparison selections, refer to Huff [5] and Patton [95].

Speed The units operate at an electric motor and/or internal combustion engine speeds of 450–3600 rpm but can be adapted to V-belt or gear for any driver speed.

Applications Typical process-related applications have included ammonia in refrigeration, pneumatic conveying, gas gathering and boosting, vapor recovery, flow gas recovery, and others in petroleum refining; air supply and methane recovery in the mining industry; aeration and methane boosting in sewage/biogas operation. For reciprocating compressors, efficiency is influenced by the following [111]: • Leakage—back flow through suction or discharge valves or around the piston. • Cylinder clearance—when the piston has reached the end of the compression stroke, some gas is retained in the clearance space in the Cylinder. When the compression cycle restarts, there is already a volume of gas in the cylinder that re-expands and reduces the available volume for suction gas. • Wiredrawing—as gas passes through the compressor suction valve, throttling takes place, reducing efficiency. • Cylinder heating—the compression process generates heat as work is transferred into the gas. The effect of this is that suction gas is heated, thus expanding as it enters the cylinder.

810  Petroleum Refining Design and Applications Handbook Volume 2 (a) 600 Inlet Volume, cu. ft./min.

Size A, 1,160 rpm 500 Size B, 865 rpm

400

300 Size C, 1,160 rpm 200 10

15

20 30 25 Discharge Pressure, psig

35

40

35

40

(b) 100

Brake Horsepower

80

Size A, 1,160 rpm

60

Size B, 865 rpm

40

Size C, 1,160 rpm

20

0 10

15

20 25 30 Discharge Pressure, psig

Figure 17.157A  Performance curves for rotary-vane compressor (used by permission: A. C. Compressor Corporation).

Oil Flooded Screw Compressors Oil flooded (wet) screw compressors have been in increasing demand in gas and refrigeration applications, which were once dominated by centrifugal and reciprocating compressors. The demand for refrigeration screw compressors has increased, partly driven by rapid growth of shale oil and gas production, mostly in North America. The US shale basin production growth has enhanced the demands for new infrastructure investment in gas processing. This subsequently favors screw compressor technology due to its unique operating characteristics. Most natural gas produced from wells contains water and various other hydrocarbons that must be removed from the gas stream by processing plants before it is injected into natural transportation pipelines. This happens with most shale gas production that contains heavier gas constituents (propane plus). In gas processing and low dew point control plants, natural gas liquid (NGL) components are recovered for two primary reasons. First, NGL recovery is done to meet pipeline specifications for hydrocarbon dew point for any natural gas entering the system (i.e., to prevent forming unsafe liquids during transport). Second, NGL recovery enables the customer to capture a profitable source of revenue. These high thermal unit (Btu) liquids often have greater value as separate value stream in liquid form rather than as part of the natural gas being sold [97]. The shale gas (i.e., rich gas) provides a valuable, steady stream of natural gas liquids. Pipeline quality gas has a lower thermal unit content of 1050 or less. Achieving this gas composition from shale gas requires many processing steps. For every 1000 ft3 of natural gas being processed with rich gas, it is not uncommon for 3 gallons or more of valuable hydrocarbon liquids to be extracted, even as the prices for ethane (C2H6), propane (C3H8) and butane (C4H10) have varied. The price trend is progressing upwards to often three to four times the price of the gas alone. Thus, liquid recovery is no longer an obstacle, but has become an integral part of the business strategy for downstream operators.

Compression Equipment  811 One of the natural gas liquid recovery processes involves mechanical refrigeration of the gas and McCormik [97] has provided a description of this process. The natural gas liquids that are transferred to storage tanks pose a challenging problem to the plant operator. This is because liquid hydrocarbon tanks require vapor recovery systems to capture emissions. The combination of lost gas revenue and increased regulatory demands related to gas venting and flaring have enhanced the development of emissions reduction technology. One tank emissions reduction solution known as a vapor recovery unit (VRU) has been effective as these compressor based systems are applied to capture conventional stock tank vapors and are applied to natural gas liquid storage tanks. However, traditional VRU designs and compressor technology have problems with maintenance at economic operating costs. Downstream operators are increasingly supporting rotating compressor technologies for their vapor recovery units. Oil flooded screws are a twin rotor design (Figures 17.158A–E) and their primary advantages include lower applied cost, higher reliability, flexibility in application and lower required maintenance. These factors have allowed the technology to gain the market throughout the hydrocarbon processing and transportation hubs. Injected screw compressors have gained acceptance because of their relative simplicity, high availability, good efficiency, low emissions, low noise, operation flexibility, and many inherent advantages such as high pressure ratio capability and slide valve capacity control [98]. However, they are noisy, and the wet screw type is not suitable for corrosive or dirty gases. A potential problem is the risk of process gas or refrigerant becoming entrained in the compressor oil system. Further, the oil dilution condition can cause premature wear or even catastrophic failure of the compressor bearings. One approach by manufacturers is to install a dedicated bearing lubrication oil system to isolate the bearings from the process gas stream. Additionally, hydrocarbon dilution can be addressed using process simulation software to reveal dewpoint risks in the compressor system, thereby directing packaging design considerations to avoid liquid formation. Larger screw compressor installations of over 500 hp and running at 3000 rpm can require ambient noise reduction and high frequency mechanical vibration damping in the packaged system. Table 17.17 shows the application in the natural gas compression in petroleum and petrochemical industries.

Integrally Geared Compressors Compressors are generally the highest producers of revenue among rotating driven equipment in upstream and downstream industries. They are usually un-spared and are considered as critical equipment item; their reliability is afforded a high priority as it is directly related to the company’s profit. Integrally geared compressors are employed for spared compressor applications. The typical applications of a multistage integral gear compressor casing are plant and instrument air and inert gas compressors. The casing comprises of a cast or fabricated gear case and bolted on individual stage cast casings. Some designs allow rotor removal without having to disconnect the process piping. The advantages of an integrally geared compressors are the reduced number of stages required and higher efficiency. This is because all stages are interconnected and the integral speed increasing gear enables all stages to operate at a higher specific speed. Generally, air separation plants use main air compressor (MAC), which is an atmospheric suction compressor that normally has a 70 to 100 psia (5 to 7 bara) discharge pressure. Flows are from 500 to 250,000 cfm (850 to 425,000 m3/h), but for liquid nitrogen and liquid oxygen production, nitrogen recycle machines are required. These compressors will take nitrogen product from the separation process and will discharge at about 400 to 500 psia (30 to 40 bara). These machines have been designed as integrally geared machines since the early 1970s. The power ranges on these machines can be as high as 20,000 hp (15,000 kW). In the last 15 years, booster air compressors (BAC) have been used in the industrial gas industry. These machines are similar to the recycle machines, but they take suction from the MAC discharge after a drying process and discharge at a pressure that is a function of the oxygen pressure delivered to a pipeline. The discharge pressures can be from 800 to 1200 pig (70 to 85 barg). Other services that often use integrally geared compressors are nitrogen product and oxygen product. The latter application requires special considerations with the materials of construction, seal system design, and instrumentation. Pressure and flows often vary widely on these services [98]. Figure 17.159A shows a cutaway of a typical integrally geared compressor, and Table 17.17A provides a summary of the services and sizes of integrally geared compressors used by industrial gas companies.

812  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.158A  Screw compressor in Howden process gas package (used by permission: Howden).

Figure 17.158B   Rotary twin screw compressor (used by permission: Howden).

Figure 17.158C  Screw compressor (used by permission: Howden).

Compression Equipment  813

Figure 17.158D  Single screw rotor forces (source: Mark McCormick).

Figure 17.158E  Single screw compressor (source: Mark McCormick).

814  Petroleum Refining Design and Applications Handbook Volume 2 A summary of the major reasons for the use of integrally geared compressors in gases industry is as follows [98]: • • • • • • • • • •

Efficiency due to interstage cooling, axial gas inlets, the use of two or more speeds for the impellers. Lower costs. Well suited for motor drives. Multiservice easily accommodated. High head impellers are an option. Easily accommodates a wide variety of seal types depending on service requirements. Compact design has a small installation footprint and simple foundation requirements. A significant degree of packaging is possible even on large units, which reduces installation costs. Elimination of the need for high speed couplings. Better access for maintenance and turnaround activities.

These compressor types have been used more often in petrochemical services and because of the growing use of these compressors, the API 617 (2002) standard for centrifugal compressors has been modified in the 7th edition to include a chapter for integrally geared compressors. Multistage integrally geared compressors are increasingly employed for hydrocarbon service. Before installation, it is essential to confirm satisfactory field operating experience on similar gases, the requirements for gas or oil seals, varying gas composition and flow rates and the possibility of fouling, which can reduce the reliability of the compressor as opposed to air and inert gas applications. Figures 17.159B–J show integrally geared type compressors and their applications. Integrally geared compressor has successfully been used in carbon dioxide (CO2) service for enhanced oil recovery (EOR). The compressed gas is delivered via a 205-mile pipeline, and as an added benefit to the environment, nearly all of the injected CO2 is expected to remain permanently sequestered in the depleted oil fields long after these fields have ceased operation. A motor plus integrally-geared compressor with four pinions (eight stages of compression) with a maximum pinion speed exceeding 26,000 rpm was used. After twelve years of service, the results show that integrally geared compressors in dry CO2 service could achieve several important benefits [99]: • • • • •

Requiring the lowest capital cost. Reducing footprint of compressor. Highest total efficiency. Providing simplest design, with high unit availability. Using a bull-gear driven main lube oil pump simplifies the lube oil system by eliminating oil-rundown tank. • Installing two 50% capacity 20,000 hp machines allows partial continuous production. • Using inlet guide vanes provides the highest compressor flow turndown. The selection process involves conducting a reliability design audit, lifecycle cost analysis and a sub-supplier preference reviews. During the comprehensive audit process, the shaft seals and long term reliability upgrades received considerable attention. Carbon-ring seals were used for all stages and the seal housing design would be capable of accepting dry-gas seals in the event of failure of the carbon-ring seals. Other mechanical features that were given adequate attention included “flexure pad” bearings, hydraulically fitted coupling hubs and diaphragm-spacer couplings at the driver connection. The motors were synchronous across the line starting design with liquid cooling. A control system manages speed and continuously monitors machine condition. This system is integrated into the plant’s digital control system (DCS) along with shaft vibration, thrust position and bearing temperature monitoring, all being arranged for automated alarm and shutdown. The over performance of these eight-stage compressors was satisfactory as the cost savings exceeded 10% as compared to the initial investment from the next best option. The machines achieved the lowest operating cost, along with 96% availability. This compressor type requires consideration with increased interests in CO2 sequestration projects, enhanced oil recovery and urea production.

Compression Equipment  815

Figure 17.159A  General cutaway of integrally geared compressor (source: Wehrman, Joseph G. et al.).

Figure 17.159B  General cutaway of integrally geared compressor (source: Wehrman, Joseph G. et al.).

Other Process-Related Compressors Several other types of compressors are used in the process industries for a wide variety of special applications that may not be suitable for the larger reciprocating or centrifugal compressor selections. One of the smaller compressors is a diaphragm compressor (Figures 17.160 and 17.161 and Table 17.18). These units are usually oilfree, noncontaminating, and leak-proof and are usually belt-or gear-driven. The ranges of capacities are 0.5–72

816  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.159C  Oxygen compressor, integrally geared design (source: Wehrman, Joseph G. et al.).

Steam Turbine

Geared Compressor

Gearbox

Figure 17.159D  Steam turbine driven integrally geared compressor with gearbox (source: Wehrman, Joseph G. et al.).

Generator Steam turbine

IG compressor

Figure 17.159E  Integrally geared compressor with pinion drive direct from steam turbine (source: Wehrman, Joseph G. et al.).

Compression Equipment  817 Table 17.17  Application in the natural gas compression, petroleum, and petrochemical industries. Reciprocating compressor

Screw compressor

Attribute

Lube

Non-lube

Oil flooded

Oil free

Centrifugal compressor

Maximum discharge pressure

300 barg (4500 psig)

100 barg (1500psig)

100 barg (1500 psig)

40 barg

200 barg

Maximum single-stage pressure ratio

3:1

3:1

>50:1

4:1 to 7:1

1.5:1 to 3:1

Maximum inlet flow

1500 m3/h (8000 cfm)

1500 m3/h (8000 cfm)

25,000 m3/h (15000 cfm)

70,000 m3/h (41,000 cfm)

400,000 m3/h + (240,000 cfm +)

Turndown

Suction valve

Suction valve

Slide valve

(None)

Inlet guide vane

Accomplished by:

Unloaders (step and stepless) Clearance pockets

Unloaders (step and stepless) Bypass

Stepless bypass

Polymer gas

Difficult

Difficult

Difficult

Possible

Difficult

Dirty gas

Possible

Difficult

Possible

Possible

Difficult

Bypass

*Bruce gives a maximum discharge pressure of 23 barg (350 psi) for screw compressors, stating that, “There are some screw machines available capable of operating at higher pressures by using cast steel casings but these are not yet commonly used in the natural gas industry due to capital cost and availability.”

Table 17.17A  General sizes of various compressors used in the industrial gas industry. Service

Inlet pressure psia/(bara)

Outlet pressure psia/(bara)

Flow rate icfm (m3/h)

Power horsepower/(kW)

Main Air Compressor (MAC)

14.5 (1.0)

70–100 (5.0–7.0)

500–250,000 (850–425,000)

1000–58,000 (750–43,000)

Recycle Compressor

90 (6.0)

400–500 (30–40)

2000–17,500 (3400–30,000)

2500–23,000 (1800–17,000)

Booster Air Compressor (BAC)

90 (6.0)

150–1000 (10.0–70.0)

1000–33,000 (1700–56,000)

500–33,500 (400–25,000)

Product Compressor

Various

Source: Gas Processors Suppliers Association (Engineering Data Book.), SI version, 12th ed., 2004.

cfm, and the gas is compressed by the action of a metal diaphragm that completely isolates the process gas from the displacing element driving the diaphragm. The motion of the displacing element is transmitted to a hydraulic fluid, and this fluid transmits its motion to one or more thin, flexible metal diaphragms or discs. As the diaphragm moves in the compression chamber, the gas pressure is increased by reducing the volume of the fluid (see Figure 17.160). Clearance volumes are approximately 4–7% depending on the size of the diaphragm cylinder. With pressure applications to 300 mpa (43,500 psi), the clearance volumes may be as high as 10–12% due to manufacturing tolerance limits in the valve pocket area [100]. Leakage from standard construction “O”-rings is approximately 1 × 10−7 std cc/s. For extremely low leakage, metallic “O” or seal welding can yield 1 × 10−8 std cc/s. [100]. Detection devices exist in case of a significant leakage or failure of the diaphragm to prevent oil loss to the process.

818  Petroleum Refining Design and Applications Handbook Volume 2 Note:

1 Pa 1 mpa 63 mpa

= 0.0001450 psi = 145.0 psi = 63(145) = 9135 psi

Advances in Compressor Technology The design of rotating equipment as compressors has covered a wide range of flow capabilities, and the development of various impeller types has enabled a wider flow range within a given compressor model. Since the 1960s, impeller efficiencies have greatly improved from 65% to 90%, and the range of flow has doubled [101]. The broadened flow range with the development of improved compressor stage head and efficiency has greatly enhanced a given compressor’s operating range as shown in Figure 17.162. Compressor design technology has advanced through the use of tools such as computational Fluid dynamics (CFD), finite-element analysis (FEA) and rotor dynamic analysis. Design engineers have modeled three-dimensional view of the aerodynamic flow path and the effects that design will have on overall compressor performance [102, 103]. Computational fluid dynamics analysis has been employed to create impeller stage ratings. Higher and lower flow stage ratings are derived from the tested components to form a family of stages. Within each family, impeller geometry is fixed, and blade heights are varied for lower and higher flows. Stage analysis results are continuously monitored and verified against actual aerodynamic performance and field tests, thus allowing the designer to match impeller performance in achieving optimum overall stage performance. Creating and extending impeller types, the application engineer can select from various impeller designs to optimize stage-to-stage performance throughout the compressor aerodynamic flow path. Figures 17.163A–C show compressors types in refrigeration, component upgrades and a typical steam turbine component upgrades.

Troubleshooting of Centrifugal and Reciprocating Compressors Tables 17.19 and 17.20 provide check lists for troubleshooting reciprocating and centrifugal compressors and how to identify and offer solutions to the situations. Lieberman [104] presents an experience of a common problem that he encountered:

First Stage Diaphragm Cylinder

Second Stage Diaphragm Cylinder

Drive Motor

Baseplate

Crankcase (Frame)

Figure 17.160  Diaphragm gas compressor. Gas remains oil-free capable of handling all clean gases (used by permission: Livingston, E. H., Chemical Engineering Progress, V. 89, No. 2 © 1993. American Institute of Chemical Engineers, Inc., All rights reserved).

Compression Equipment  819

Cavity contour is optimized for displacement and clearance volume.

Diaphragm stresses are equalized for longer life.

Process contacting materials are properly selected for each application with consideration of both structural and corrosion needs.

Gas and hydraulic plates are either forged or rolled plate and material conforms to Burton Corblin’s rigid specifications.

Pistons fitted with engineered plastic or metal piston rings for increased life and reduced blow-by.

Low-friction plate, disc or poppet-type check valves of stainless steel or engineered plastics optimize response and efficiency.

Elastomer “O” ring seal the diaphragm group to the gas and hydraulic plates ensuring a leaktight seal with low torque.

Full, integral flange produces even clamping forces on the gas and hydraulic plate seal areas.

Figure 17.161  Motion of the displacing element causes the diaphragm to move into the compression chamber to reduce the volume and, thereby, increase gas pressure (used by permission: Bul. BCHB-2D101. © Howden Compressor, Inc.).

Table 17.18  Typical diaphragm compressor process construction materials. Component

Material

Remarks

Gas plate

Carbon steel

Pressure to 63 mpa

Low alloy steel

Pressure to 200 mpa

304 SS, 316 SS

Pressure to 63 mpa

17-4 PH, A286

Pressure to 200 mpa

High nickel alloys

Pressure to 63 mpa

20 Cb-3

Pressure to 63 mpa

301 SS, 316 SS

Standard for most service

Ni-cu alloy

Oxidizer service

Diaphragms

Used by permission: Livingston, E. H. Chemical Engineering Progress, V. 89, No. 2, © 1993. American Institute of Chemical Engineers. All rights reserved.

820  Petroleum Refining Design and Applications Handbook Volume 2 Impeller efficiencies (approximate) 0.9

Polytropic efficiency, %

0.85 0.8 0.75 Mid-1990s --> Today 1980s Mid-1960s and 1970s 1950s and 1960s

0.7 0.65 0.6 0.0

0.05

0.1

0.75

0.2

Flow coefficient

Figure 17.162  Evolution of impeller performance (source: Renard, D.).

Figure 17.163A  Refrigeration compressor with multiple side streams (source: Renard, D.).

“My most vivid experience of this common problem occurred at the Laredo compression station in south Texas in 1986. We were compressing natural gas from 600 psig to 1100 psig using a centrifugal compressor comprised of four wheels. The gas contained entrained brine (i.e. salt water). After several months of operation, I would begin to notice a gradual loss of compressor capacity. Not only would the compressor’s capacity and efficiency diminish with time, but when the compressor lost is about 30% of its capacity, the compressor would start to vibrate and then trip off on the high rotor vibration automatic shutdown switch. When, subsequently the machine was disassembled, I observed that:

• • • •

The first wheel was very clean. The second wheel had minor salt deposits. The third wheel was badly encrusted with both salt and a heavy grease. The final and fourth wheel was very slightly fouled with salt.

Clearly, the brine was drying out on the third wheel. The resulting deposits were restricting the gas flow through the machine: thus the loss of capacity”

Compression Equipment  821 Add spray nozzles for cleaning and/or cooling Replacement balance pistons seals with abradable seals to improve efficiency

Replace shaft seals to Replace impeller seals with Replace impellers and abradable seals to improve diaphragms with advanced improve efficiency efficiency aerodynamic technology for significant efficiency improvement

Figure 17.163B  Typical compressor component upgrades.

Upgrade nozzle ring to optimize performance at actual steam conditions

Replace or supplement existing seals with brush-type seals

Upgrade diaphragms with improved nozzle profiles

Upgrade blades Install tip seals for with improved improved efficiency aerodynamic profiles

Figure 17.163C  Typical steam turbine component upgrades (source: Renard, D.).

Lieberman provides steps in suppressing salt formation on a centrifugal compressor’s rotor in a refinery by determining the amount of the liquid injection to the suction of the compressor. These are: • Assume that the entrainment rate is zero from the KO drum. • Select the type of liquid to be employed. Use the naphtha stabilizer bottoms rather than an expensive specialty aromatic chemical. • Calculate the amount of naphtha that is required in the compressor’s suction to reach the dew-point temperature at the discharge from the final wheel of the stage. • Note that each stage of compression (i.e., not each wheel) should be treated separately. • To calculate the amount of naphtha required, take into account both the latent heat of vaporization of the naphtha and the increase in the dew-point temperature of the compressed gas, due to the gas’ increased molecular weight, from the injected naphtha.

822  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.19  Troubleshooting checklist for reciprocating compressors. Symptoms

Possible causes

Compressor will not start

1. 2. 3. 4.

 ower supply failure P Switchgear or starting panel Low oil pressure shutdown switch Control panel

Motor will not synchronize

1. 2. 3. 4.

 ow voltage L Excessive starting torque Incorrect power factor Excitation voltage failure

Low oil pressure

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.

 il pump failure or trips when started O Oil foaming from counterweights stricking oil surface Oil temperature low (cold oil) Dirty or plugged oil filter Interior frame oil leaks Excessive leakage at bearing shim tabs and/or bearings Low oil pressure switch calibration disturbed or improperly set Low setting of oil gear pump bypass control or relief valve Defective pressure gauge Defective relief valve (stuck-open) Plugged oil sump strainer

Noise in cylinder

1. 2. 3. 4. 5. 6. 7.

 oose piston L Piston hitting outer head or frame end of cylinder Loose crosshead lock nut Broken or leaking valve(s) Worn or broken piston rings or expanders Valve improperly seated/damaged seat gasket Free air unloader plunger chattering

Excessive packing leakage

1. 2. 3. 4. 5. 6. 7. 8. 9.

 orn packing rings W Improper lube oil and/or insufficient lube rate (blue rings) Dirt in packing Excessive rate of pressure increase Packing rings assembled incorrectly Improper ring side-or-end-gap clearance Plugged packing vent system Scored piston rod Excessive piston rod run-out

Packing overheating

1. L  ubricating failure 2. Improper lube oil and/or insufficient lube rate 3. Insufficient cooling

Excessive carbon on valves

1. 2. 3. 4. 5.

Relief valve popping

1. F  aulty relief valve 2. Leaking suction valves or rings on next higher stage 3. Obstruction (foreign material, rags), blind, or valve closed in discharge line

 xcessive lube oil E Improper lube oil (too light, high carbon residue) Oil carryover from inlet system or previous stage Broken or leaking valves causing high temperature Excessive temperature due to high pressure ratio across cylinders

(Continued)

Compression Equipment  823 Table 17.19  Troubleshooting checklist for reciprocating compressors. (Continued) Symptoms

Possible causes

High discharge temperature

1. E  xcessive compression ratio on cylinder due to leaking inlet valves or rings on next higher stage 2. Fouled intercooler/piping 3. Leaking discharge valves or pistion rings 4. High inlet temperature 5. Fouled water jackets on cylinder 6. Improper lube oil and/or lube rate

Frame knocks

1. 2. 3. 4. 5. 6.

Crankshaft oil seal leaks

1. F  aulty seal installation 2. Clogged drain hole

Piston rod oil scraper leaks

1. 2. 3. 4.

 oose crosshead pin, pin caps, or crosshead shoes L Loose/worn main, crankpin, or crosshead bearings Low oil pressure Cold oil Incorrect oil Knock is actually from cylinder end

 orn scraper rings W Scrapers incorrectly assembled Worn/scored rod Improper fit or rings to rod/side clearance

Table 17.20  Troubleshooting checklist for centrifugal compressors. Symptoms

Possible causes

Low discharge pressure

1. 2. 3. 4. 5.

Compressor surge

1. I nadequate flow through the compressor 2. Change in system resistance due to obstruction in the discharge piping or improper valve position 3. Deposit buildup on rotor or diffusers restricting gas flow

Low lube oil pressure

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.

 ompressor not up to speed C Excessive compressor inlet temperature Low inlet pressure Leak in discharge piping Excessive system demand from compressor

 aulty lube oil pressure gauge or switch F Low level in oil reservoir Oil pump suction plugged Leak in oil pump suction piping Clogged oil strainers or filters Failure of both main and auxiliary oil pumps Operation at a low speed without the auxiliary oil pump running (if main oil pump is shaft-driven) Relief valve improperly set or stuck open Leaks in the oil system Incorrect pressure control valve setting or operation Bearing lube oil orifices missing or plugged (Continued)

824  Petroleum Refining Design and Applications Handbook Volume 2 Table 17.20  Troubleshooting checklist for centrifugal compressors. (Continued) Symptoms

Possible causes

Shaft misalignment

1. 2. 3. 4. 5.

 iping strain P Warped bedplate, compressor, or driver Warped foundation Loose or broken foundation bolts Defective grouting

High bearing oil temperature

1. 2. 3. 4. 5. 6. 7. 8. 9.

I nadequate or restricted flow of lube oil to bearings. Poor conditions of lube oil or dirt or gummy deposits in bearings Inadequate cooling water flow lube oil cooler Fouled lube oil cooler Wiped bearing High viscosity Excessive vibration Water in lube oil Rough journal surface

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16.

I mproperly assembled parts Loose or broken bolting Piping strain Shaft misalignment Worn or damaged coupling Dry coupling (if continuously lubricated type is used) Warped shaft caused by uneven heating or cooling Damaged rotor or bent shaft Unbalanced rotor or warped shaft due to severe rubbing Uneven buildup of deposits on rotor wheels, causing unbalance Excessive bearing clearance Loose wheel(s) (rare case) Operating at or near critical speed Operating in surge region Liquid “slugs” striking wheels Excessive vibration of adjacent machinery (sympathetic vibration)

Note: Lube oil temperature leaving bearings should never be permitted to exceed 180°F (82°C)

Excessive vibration Note: Vibration may be transmitted from the coupled machine. To localize vibration, disconnect coupling and operate drive alone. This should help to indicate whether driver or driven machine is causing vibration

Water in lube oil

1. C  ondensation in oil reservoir 2. Leak in lube oil cooler tubes or tube-sheet

Appendix D shows the construction commissioning start-up checklists in the process data sheets of rotary equipment such as pumps, compressors, and others such as blower, fans, and mixers. • A typical spray wash flow is 1 wt% of the gas flow. Do not add any safety factor to the amount calculated above, as ignoring the effect of entrainment in the feed gas in effect adds a safety factor to the calculation. Lieberman [104] presented another interesting scenario relating to a troubleshooting problem with centrifugal and axial compressors with four wheels, where the compressor had a reduced amp load due to fouling of the motor of the compressor. As the rotors fouled, the gas flow would be reduced. Further, as the rotor fouled with salt and a thick greasy substance, the compressor spun faster, resulting in wastage of energy employed to drive the turbines. An inspection discovered that not all the four wheels were equally dirty, as the first was clean; the second slightly fouled; the third wheel was terribly clogged with black greasy gook and dirty white salt. The fourth wheel was dirty, but not as bad as the third wheel. This was because the heat of compression caused the gas to be hotter, which subsequently dried out on the wheels. Lieberman [104] suggested that the wheels be kept wet and sprayed with heavy gasoline into

Compression Equipment  825 the compressor suction to keep the wet gas from drying out. He further opined that the compressor be sprayed with enough gasoline to push the calculated dry-out point past the last wheel, based upon: • • • • • •

Temperature Pressure Gas composition Gasoline composition used as a spray Compression ratio Ratio of the specific heats capacity (k = cp/cv) of the wet gas.

Determine how much of gasoline spray is required so as not to reach the dew point conditions inside the compressor. A suitable misting type of spray nozzle at the inlet to the compressor is also required [104]. Reciprocating compressors serve the industries well when properly designed, installed and operated. However, problems often occur with liquids from condensation of saturated vapor streams entering the suction side of the compressor. The compressors can be severely damaged with the possibility of blowing the compressor heads off, if they are subjected to incompressible fluids. Professor Keltz provides an account about a packaged unit containing a reciprocating compressor where the compressor was started in error. The discharge valve was in the closed position, and as the pressure increased, the unit in the packing around the cylinder rod blew out [105]. This compressor was equipped with a relief valve that was merely a sentinel to warn the operator to take action. However, the sentinel was incapable of relieving the full output of the equipment. This is not an acceptable design standard today, but the example supports the need for available process-safety information on all equipment. In another case, a compressor head water jacket violently ruptured and blew apart. A hand-sized fragment of metal propelled about 50 yards. This chunk of metal flew across an in-plant road and an open area before striking a storage tank. The iron missile bent a hoop on a large acid tank’s ladder cage and caused some superficial damages to a large acid tank. The propellant was pent-up water and steam pressure. The destructive pressure buildup occurred as the compressor operated for over 5 h with no cooling water flow. Cooling water was trapped in the water jacket on the compression head as the compressor piston continued operating. The investigating team concluded that the fragmentation of the compressor water jacket was a consequence of the operating condition, and a metal failure analysis of the compressor head was not required. The damage was apparent and limited, but there was no release of gas, and the incidence did not require the attention of the available on-site emergency personnel. In another incidence, the lead operator, accompanied by two operator trainees, started the No. 1 and No. 3 compressors to supply a feedstock to a unit that had been shut down during most of the day shift. The second step of the startup procedure was to “put water on the compressor water jacket”. That step was inadvertently omitted in the start-up of the No. 1 compressor, and the temperature must have risen slowly (Typically the water valves were not operated during brief shutdowns, so it might not have been checked). This was a simple mistake as the cooling water inlet, outlet and drain valve were left in the closed position. The heat energy developed by the operating compressor created an overpressure condition within the compressor’s water jacket. The friction energy so generated heated the water and burst the outside compressor’s head water jacket. The investigating team observed that the metallic head washers on the compressor valve caps had melted, which along with discoloration of the paint on the valves, confirmed the high temperature [105]. Figures 17.164A–B show the reciprocating compressor with ruptured water jacket, and a close-up of ruptured water jacket on the compressor.

Case Study Repeated Rich Gas Compressor Failure in a Continuous Catalytic Reformer Unit (CCRU) The rich gas compressors are a continuous catalytic reformer unit (CCRU) were having frequent problems [112]. The compressors were the reciprocating type, with two stages driven by the same motor. Typically, the rich gas is produced from the separator of a CCRU and compressed, cooled, and refrigerated to condense the hydrocarbons and improve the H2 purity of the gas. A CCRU produces typically around 3% weight of H2 and very pure H2 (95% mole) is recovered as a by-product from the CCRU through recontacting and chilling.

826  Petroleum Refining Design and Applications Handbook Volume 2

Figure 17.164A  Reciprocating compressor with ruptured water jacket (source: Roy Sanders).

The rich gas compressors in this CCRU had many problems. One compressor broke and the other two needed frequent repairs. The rich gas compressor piston rings were frequently getting worn, sticky material was found in the suction valves leading to passing of the compressor valves and high discharge temperature, and the compressors experienced high vibrations and frequent tripping. The unit was visited by the compressor vendor and an engineering contractor, and it was felt that the compressors needed to be replaced. The problem was revisited and the following observations are: Figure 17.165 shows the compressor suction line arrangement. The elevation of the main suction line was lower than the suction drum top; therefore the suction line was not self-draining toward the separator and no loop was allowed in the suction line, which is the primary requirement as per API 618. Individual suction lines had loops before entering the suction volume bottle in the existing arrangement. Outlet from the suction volume bottle to the casing was drawn from the bottom of the volume bottle (no protrusion) in one of the compressors that broke. A continuous draining provision from the volume bottle is normally provided, but as the suction pipe from the volume bottle was not extended (extension of 2 in. is suggested to avoid condensate entry into casing), the liquid ingress to the volume bottle had direct entry to the compressor casing, which could damage the compressor (Figure 17.166). In the other two compressors, the protrusion was present as required. It was further found that the casing coolant water temperature was lower than the suction vapor temperature, which can condense the liquid as the vapor is saturated. API recommends that the water temperature be 6°C higher than the vapor temperature to avoid condensation of

Compression Equipment  827

Figure 17.164B  Close-up of ruptured water jacket on compressor (source: Roy Sanders).

the vapor due to the low temperature of the cooling water. The compressor suction valve deposits were analyzed and tests showed that the content was mostly NH4Cl. It was found that the stabilizer off-gas was connected to the second-stage suction, presumably for the recovery of H2 and higher hydrocarbons from stabilizer off-gas. It was suspected that chloride from the stabilizer off-gas was getting into the system and that the NH4Cl was getting deposited in the compressor valves. The suction line needed to be self-draining toward the suction knockout drum. If this could not be done, as an improvised solution, a continuous drain was provided in the common suction line to drain any condensate formed or carried over from the suction knockout drum (Figure 17.167). The steam tracer can be isolated in the common suction line to facilitate draining the condensate from the common suction header through a continuous drain. Loops in the individual suction lines needed to be eliminated but the steam tracing and insulation had to be kept in service so that no liquid could condense and get into the suction volume bottle. The casing cooling water temperature had to be increased by 6°C above the suction temperature to avoid the condensation of gas in the compressor casing. The volume bottle needed to be modified to raise the suction pipe inside the volume bottle by 2 in. in order to avoid any liquid entering the compressor casing. This would also ensure draining (integral draining) of the liquid through the volume bottle drain if there is only liquid ingress. The stabilizer off-gas line was routed to the fuel gas after a caustic wash to remove chlorides. Finally, it was suggested to install a chloroguard in the stabilizer off-gas line so that the gas could be rerouted back to the suction of the second stage compressor. Alternatively, a chloroguard could have been installed at the feed inlet of the stabilizer to remove all the chlorides from the stabilizer feed, but that would have been a costlier option. All the modifications were implemented and the compressor is operating without any problem.

Suction knock-out drum

828  Petroleum Refining Design and Applications Handbook Volume 2

h1

h2

Gas Ex RG compressor

To suction volume bottle of rich gas compressor

h3 ST ST - Strainer

Figure 17.165   Compressor suction line arrangement [112].

Suction Vapor/Gas

Suction volume bottle

2"

Reciprocating Compressor casing

Condensate drain vessel Level indicator

Figure 17.166  Correct suction volume bottle arrangement of a compressor [112].

Compression Equipment  829

From suction drum NGC-C

NGC-B

NGC-A To volume bottle at suction

Vent

N2

Continuous draining

Strainer

NGC - Net Gas Compressor

Figure 17.167  Existing suction piping of the compressor [112].

Nomenclature A Ad Ap Ar acfm B bhp bhp/ MM CFD BNV C C* C' cfr cp cv c , cc , c‴ D D’ D’ D1 db Ep Ev E ′v ead or ea ear eas ecm ep es

= constant = cross-section area of duct, ft2 = cross-section area of piston, in.2 = cross-section area of piston rod, in.2 = actual ft3/min, actual temperature and pressure = constant = brake horsepower = brake horsepower required/1,000,000 ft3/day of gas = measured at a base pressure of 14.4 psia and suction temperature = blower net volume at inlet conditions, ft3/min = capacity of gas to be compressed, referenced to 14.4 psia and suction temperature, ft3/day = constant = experimentally determined dynamic loss coefficient = ft3/ revolution, displacement of blower = specific heat at constant pressure, Btu/lb(°F) = specific heat at constant volume, Btu/lb(°F) = constants in compression process = impeller diameter, in. or fan wheel diameter, in. = blower displacement, ft3/revolution = wheel diameter, ft, or = impeller diameter, in. = I.D. of duct, ft = decibels sound level = polytropic efficiency = m/m = volumetric efficiency (actual) used as a fraction, but may be calculated in equation as Percent = theoretical volumetric efficiency, fraction = adiabatic efficiency, fraction = combined adiabatic and reversible compression efficiencies, fraction = adiabatic shaft efficiency, fraction = combined compression and mechanical efficiencies of a compressor (not including driver), fraction = polytropic or hydraulic efficiency, fraction = static efficiency of fan, fraction

830  Petroleum Refining Design and Applications Handbook Volume 2 et Fan size FL Fw f ghp g H H' Ha Had Hp (hp)a hpg (hp)t (hp)s h hf hfs ho hs hv h1, h2 Δh hp ihp i J K k k' Lo 1 M MMcf M' Mcp MW m m' N Nm Ns n P or p Pc Pf Pr Ps2 Pt

= total efficiency of fan, fraction ≅ wheel diameter = frame loss for motor-driven compressors, fraction = theoretical horsepower factor = friction factor dependent upon Reynolds number and relative roughness of the duct, dimensionless = gas horsepower = gravitational constant, 32.2 ft/s2. = total head in ft, equal to work of compression in ft-lbf/lbm = head/stage, ft of fluid = adiabatic head, ft-lb/lb, or ft (kN-m/kg) = adiabatic head, ft (kN-m/kg) = polytropic head, ft-lb/lb, or ft (kN-m/kg) = air horsepower = gas compression horsepower = fan horsepower based upon total pressure (or hp) = fan horsepower based on static pressures (or hp) = enthalpy of gas, Btu/lb = head loss due to friction, ft of fluid flowing = friction or head loss under standard air conditions, same as ho = friction or head loss for actual operating conditions, ft or fluid, or other consistent units = friction or head loss for standard air conditions, ft of fluid, or other consistent units. = total shock pressure loss, in. of water = enthalpy of inlet gas and exit gas respectively, Btu/lb = enthalpy change, Btu/lb = horsepower = indicated horsepower = interstage pressure at stage discharge conditions, psi = Joule constant = 778 ft-lb/Btu = constant = adiabatic exponent, ratio of specific heats, = cp/cv = pseudo-compression coefficient correcting for deviation from ideal gas law = loss factor, comprised of losses due to pressure drop through friction of piston rings, rod packing, valves, and manifold (Figure 18.19). = length of duct, ft = mass flow, lb/min = one million ft3 gas at 14.7 psia and 60°F. = Mach number, dimensionless = molal heat capacity at constant pressure, Btu/lb-mol(°R) (kJ/kmol.K) = molecular weight = isentropic or adiabatic exponent = polytropic exponent, or n = polytropic exponent = number of lb-mol, or rotational speed, revolutions/min, rpm = number of lb-mol gas/h = specific speed, dimensionless = polytropic exponent or coefficient for compression or expansion, or n = rpm, speed in Fan Laws = pressure, absolute, psia, or inlet pressure, psia (bara) = critical pressure, absolute = final pressure of multistage set of cylinders = reduced pressure = P/Pc = fan outlet static pressure, in. water abs = total system pressure psia

Compression Equipment  831 Pv Pv′′ P1

= fan outlet velocity pressure, in. water abs = vapor pressure of moisture in saturated gas, psia = atmospheric pressure or fan inlet pressure (if not atmospheric), in. water abs, or initial suction condition, abs = discharge pressure, abs P2 PD = piston displacement, ft3/min PD' = piston displacement, in.3 Psi = pounds per in.2 P = static or total pressure, in. of water p' = pressure, lb/ft2, abs Prime (') = interstage discharge condition, reduced by the pressure drop through the intercoolers, valves, piping, etc., represents actual pressure to suction of successive cylinders in multistage compression system = fan static pressure, in. water ps Pfs = ps = fan static pressure, in. water = fan total pressure, in. water Pft = fan velocity pressure, in. water Pfv = total pressure, in. water Pt = velocity pressure, in. water Pv p = pressure drop through intercooler, psi Q and Qs = inlet (or volume) flow of gas (or suction), ft3/min, or ft3/s (as marked), also = Q1, or = heat Qa or Qb = fan capacity, ft3/min (cfm) R = universal gas constant = 1545 ft-lbForce/(lb-mol)(°R), units depend upon units of pressure, volume, and temperature = 1.986 (Btu)/(lb-mol)(°R) S.I. units: 8.314 kJ/kmol.K = 213.6 kg.m/kmole. K = 8.314 kPa(abs)m3/kmol.K Ri, or R = specific gas constant for gas involved = 1545/mol wt = universal gas constant = 1545 = same for all gases using P = lb/ft2abs, or = lb-in.2 abs (see “R”) Ro = ratio of compression across a single cylinder, or total compressor r or Rc rpm = revolutions per minute, or = n in Fan Laws RH = relative humidity, fraction = overall ratio of compression across multistage unit = Pf/P1 Rt r = radius of elbow, in. S = stroke, ft = entropy, Btu/lb S’ = slip rpm rotary positive blower = slip rpm at a specific discharge pressure for rotary positive blower. Sp cfm s = standard ft3/min at 14.7 psia, 68°F and 36% relative humidity shp = shaft horsepower input to fan, or compressor SP, or sp = static pressure, in. of water (or in. water gage) s = stroke length, in. T = temperature, abs, °R = °F + 460 = critical temperature, °R Tc = air or gas temperature at fan inlet, °Rankine T1 = pseudo-reduced temperature Tr = °R/[(mol avg Tc (abs)] = °R/°Tc t = temperature, °F = temperature after adiabatic compression, °F tc = water temperature, °F tw u = peripheral velocity of wheel, ft-s u’ = gas velocity at any point, ft/s V = volume, ft3 (Note: may be ft3/min, when stated) VP or vp = velocity pressure, in. of water

832  Petroleum Refining Design and Applications Handbook Volume 2 Va Vc Vd Vp Vpc Vpc′ Vs Vs′ Vw V1 v vf vm W or w w y Z

= actual capacity or actual delivery, referenced to intake or suction conditions of cylinder, ft3/min = clearance volume, in.3 = volume of dry gas, cfm = peripheral velocity of fan wheel, ft-min = % clearance or used as a fraction = fraction clearance = % clearance/100 = sonic or acoustic velocity, ft/s = slip, cfm = volume of gas containing moisture or other condensable vapor, cfm = suction or inlet volume, ft3/min = specific volume, ft3/lb = fluid velocity, ft/s = fluid velocity, ft-min, or = v = mass flow of gas, lb/min or = power = vapor pressure of water at temperature, psia = mol fraction of a component in the vapor phase = compressibility factor, dimensionless

Greek Symbols α γ Φ or ϕ ψ μ δ Δ ν υ ν η ρ ρg ρo ρs π

= blade angle, with plane of rotation, degrees = number of compression stages, or specific weight of gas, lb/ft3, or isentropic coefficient = flow coefficient = pressure or head coefficient = pressure or head coefficient = relative density of gas referred to air standard conditions = change, interval = pressure coefficient, ft/s = tip speed of impeller or rotor wheel, ft/s = gas velocity, ft/s = total fan efficiency = density, lb/ft3 = gas density, lb/ft3 = density of air under actual operating conditions, lb/ft3 = density of air under standard conditions, lb/ft3 = 3.1416

Subscripts 1 2 ad f d i ib m p

= first condition = second condition = adiabatic = final or last stage = discharge condition = interstage condition = fan input power = mean value = polytropic

Compression Equipment  833 s T or t y

= suction condition, or = static = total = conditions of gas across a cylinder, represented by 1 for first stage, 2 for second stage, etc.

References 1. Scheel, L. F., Gas Machinery, Gulf Publishing Co. (1971). 2. Scheel, L. F., “New Piston Compressor Rating Method,” Hydro Proc, V. 46, No. 12, p. 133 (1967). 3. Hall, S., Rules of Thumb for Chemical Engineers, 5th ed., Gulf Professional Publishing (Imprint of Elsevier), (2012). 4. Monroe, E. S., “Vacuum Pumps Can Conserve Energy,” Oil and Gas Jour., p. 126, Feb. 3, (1975). 5. Huff, Jr. G. A., Selecting a vacuum producer. Chem. Eng., Mar. 15, p 83, (1976). 6. Leonard, S. M., “Increase Reliability of Reciprocating Hydrogen Compressors,” Hydro Proc., V. 75, No. 1(1996). 7. Bauer, F., “Valve Pocket Losses in Reciprocating Compressors,” Hydro Proc, V. 86., No. 10, p. 55 (1989). 8. Bunn, L. S., “Consider Poppet Valves for Compressor Retrofits,” Hydro Proc., V. 67, No. 2, p. 53 (1988). 9. Edmister, W. C., Applied Hydrocarbon Thermodynamics, Gulf Publishing Co. (1961). 10. Bulletin bctb-302 gas compressibility. Burton Corbin ® North America, Inc., (1990) 11. Gibbs, C. W., Ed., Compressed Air and Gas Data, Ingersoll-Rand Co. (1969). 12. Brown, G. G., “Enthalpy–Entropy Charts for Natural Gases,” Tr. AIMME, Tech Paper No. 1747, July (1944). (See also NGSMA Engineering Data Book, pp. 104–108 (1957). 13. Edmister, W. C., Part VI, “Improved Mollier Charts for Hydrocarbons,” April (1958). 14. Pfennig, H. W., and McKetta, J. J., “Compressibility Factor at Low Pressures,” Pet. Refiner, p. 309, No. (1957). 15. Brown, G. G., D. L. Katz, G. G. Oberfell, and R. C. Alden. “Natural Gasoline and the Volatile Hydrocarbons,” Section One, Natural Gasoline Association of America, Tulsa, OK (1948). 16. Edmister, W. C., and R. J. McGarry, “Gas Compressor Design,” Chem. Eng., Prog., V. 45, No. 7, p. 42 (1949). 17. Palmer, E. Y., “How to Catch Compressor Troubles without Shutting Down the Engine,” Pet. Processing, p. 884, June (1954). 18. Gill, T. T., Air and Gas Compression, John Wiley and Sons, Inc., New York, NY (1941) 19. Jorgenson, R., Ed., Fan Engineering, 8th ed., Buffalo Forge Co., Buffalo, NY (1983). 20. Dimoplon, W., “What Process Engineers Need to Know About Compression,” Hydro Proc., V. 57, No. 5, p. 221 (1978). 21. Perry, R. H., and C. H. Chilton, Eds., Chemical Engineers Handbook, 5th ed., McGraw-Hill Book Co. (1973). 22. Neerken, R. F., “Compressor Selection for the Chemical Process Industries,” Chem. Eng., p. 78, Jan. 20, (1975). 23. “Plain Talks on Air and Gas Compressors,” Bul. L-600-B9-2: Bul. L-600-B9-4, Dresser-Rand Corp., Worthington Div.; (1943). 24. Compressed Air Handbook, 1st Ed., Compressed Air and Gas Institute, New York, NY (1947). 25. “Reciprocating Compressor Data Book,” Cooper-Bessemer Corp., Mount Vernon, OH (1956). 26. Boteler, H. M., “Reciprocating Compressor Performance Characteristics,” Pet. Ref., Nov. (1956). 27. Edmister, W. C., “Applied Hydrocarbon Thermodynamics,” Pet. Ref., V. 38, No. 4, p. 161 (1959). 28. Edmister, W. C., “Applied Hydrocarbon Thermodynamics,” Pet. Ref., V. 38, No. 5, p. 195 (1959). 29. “Selection Guide for Multistage Centrifugal Compressors,” Elliott Co., Bul. P026 15-194-FL, pub. Date not available. 30. Hartwick, W., “Improve Your Compressor Design,” Chem. Eng., p. 204, Oct. (1956). 31. Segeles, C. G., Ed., Gas Engineers Handbook, 1st ed., Industrial Press (1977). 32. “Horizontal, Balanced/Opposed Process Compressors,” Cooper-Cameron Corporation, Cooper-Bessemer Reciprocating Products Div., Bul. 9-201 B (1991). 33. Schaefer, R. A., “Improve Your Compressed Air Supply,” Power and Fluids, Summer, Dresser-Rand Co., Worthington, Corp. (1995). 34. Skrotzki, B. G. A., “Compressed-Air-Systems Pay Off,” Power, p. 72, Jan. (1958). 35. Rice, William T., “You Can Simplify Calculations For Humidity and Air Compression,” reprint RP-383 of Worthington Corp., ©W. T. Rice. 36. Nissler, K. H., “Keeping Turbo Compressors in Top Shape,” Chem. Eng., V. 98, No. 3, p. 104 (1991). 37. Macaluso, C. A., “A New Concept in Centrifugal Compressor Design,” Power and Fluids, V. 8, No. 2, Dresser-Rand, Worthington Corp. (1965). 38. “Multistage Centrifugal Compressors,” Bul. 150. Clark Bros. Div., Dresser-Rand Co., pub. date not available. 39. Cameron, J. A., and F. M. Danowski, Jr., “How to Select Materials for Centrifugal Compressors,” Hydro Proc., V. 53, No. 6, p. 115 (1974).

834  Petroleum Refining Design and Applications Handbook Volume 2 40. Fullermann, J., “Centrifugal Compressors,” Technical Report, Cooper-Bessember Industries, Cooper Energy Service, Rotating Products Div., Cooper-Cameron Corp., (Nov. 1963). 41. “Centrifugal barrel turbocompressors,” Sulzer, Ltd., Thermal Turbomachinery Div., Bul. 27.24.10.40Bhi 50. 42. “Centrifugal Compressor, Single Stage,” Bul., A-C Compressor Corp. 43. Koch, Donald T., “Centrifugal Compressor Shaft Seals,” Cooper-Bessemer Corp., Jan. (1958). 44. Boyce, M. P., “How to Achieve On-Line Availability of Centrifugal Compressors,” Chem. Eng., p. 115, June 5 (1978). 45. Rehrig, P., “Selecting Centrifugal Compressors Materials for Harsh Environments,” Hydro. Proc., V. 60, No. 10, p. 137 (1981). 46. “Elliott Pos-e-coat,” Bul. 02-895, Elliott Co., pub. date not known. 47. Lowe, R. E., “Specifying Evaluating and Procuring Dynamic Compressors,” Hydro. Proc., V. 65, No. 8, p. 46 (1986). 48. Centrifugal Compressors for Refinery, Chemical and Gas Services Industries, 6th ed., American Petroleum Institute (1995). 49. “Sundyne® Sunstrand Compressors,” Sunstrand Fluid Handling, Bul. 450, April (1995). 50. Lapina, R. P., “Estimating Centrifugal Compressor Performance,” Process Compressor Technology, V. 1, Gulf Publishing Co., Book Div., Houston, TX. 51. Lapina R. P., “Can You Rerate Your Centrifugal Compressor,” Chem. Eng., p. 95, Jan. 20, (1975). 52. Kannappan, S., “Determining Centrifugal Compressors Piping Loads,” Hydro. Proc., V. 61, No. 2, p. 91 (1982). 53. Burns, R. C., “The Casing Nozzle, and Auxiliary Piping,” Hydro. Proc., p.79, Oct. (1971). 54. White, M. H., “Surge Control for Centrifugal Compressors,” Chem. Eng. p. 54, Dec. 25 (1972). 55. Magliozzi, T. L., “Control System Prevents Surging in Centrifugal Flow Compressors,” Chem. Eng., p. 139, May 8, (1967). 56. Tezekjian, E. A., “How to Control Centrifugal Compressors,” Hydro Proc and Pet. Refiner, V. 42, No. 7, p. 169 (1963). 57. Daze, R. E., “How to Instrument Centrifugal Compressors,” Hydro Proc., V. 44, No. 10, p. 125 (1965). 58. Staroselsky, N., and L. Ladin, “Improved Surge Control for Centrifugal Compressors,” Chem. Eng., p. 175, May 21, (1979). 59. Gaston, J. R., “Antisurge Control Schemes for Turbocompressors,” Chem. Eng. V. 89, No. 8, p. 139 (1982). 60. “Turbocompressors,” Bul. 423, Dresser-Rand Co. (1992). 61. Rogers, A. N., “Fans and Flowers,” Chem, Eng., V. 63, No. 6, p. 202 (1956). 62. Erb, H. A., Centrifugal Compressor Symposium, “Theory of Operation,” Pet. Ref., V. 34, No. 1, p. 123 (1955). 63. Gerlitz, R. A., “Watch Static Pressure—Match Fan to System,” Plant Eng., p. 59, Jan. 9, (1969). 64. Schuder, C. B., “Air Temperature Rise Through f-d Fan” Power, p. 111, May (1957). 65. Leonard, S. M., “Increase Reliability of Reciprocating Hydrogen Compressors,” Hydro Proc., V. 75, No. 1(1996). 66. “Centrifugal Compressors,” Bull. No. 150. Clark Bros. Co. (1958). 67. Hansen, R. E,. “Power Calculations for Nonideal Gases,” Hydro. Proc., V. 44, No. 10, p. 122 (1965). 68. Bul. P-11A. Compressors calculation by the Mollier method, Elliott Co., (1966). 69. Stepanoff, A. J., Turboblowers, John Wiley and Sons, Inc., New York, NY. Incl. p. 321 (1955). 70. Welch, H. J., Ed., Transamerica Delaval Engineering Handbook, 4th ed., compiled by engineering staff of Transamerica, Delaval, Inc. McGraw-Hill Book Co. (1983). 71. Escoe, A. K., Mechanical Design of Process Systems, Vol. 2, Gulf Publishing Company, (1976). 72. Branan, C., The Process Engineer’s Pocket Handbook, Gulf Publishing Co., (1976). 73. Turbo-Blower Manual, ME – 1650.00, Ingersoll-Rand Co., New York, NY. 74. Golden, Scott, Fulton, Scott A., and Daryl W. Hanson, Understanding Centrifugal Compressor Performance in a Connected Process System, Revamps—Petroleum Technology Quarterly ® Spring (2002). 75. Stephenson, Grant, Integrate Compressor Performance Maps Into Process Simulation, www.aiche.org/cep, CEP, pp 42–47, June (2011). 76. Cole, S.L., “Here’s an Easy Approach To Centrifugal Compressor Selection,” Oil and Gas Jour., V. 58, No. 6, p. 107 (1960) and private communication with Ernest E. Ludwig. 77. Lapina, R. P., “How to Use the Performance Curves to Evaluate Behavior of Centrifugal Compressors,” Chem, Eng., p. 86, Jan. 25, (1982). 78. Lapina, R. P., “Compressors: How Changes in Inlet Conditions Affect Efficiency,” Chem. Eng., V. 97, No. 7, p. 110 (1990). 79. Koch, D. A., and J. C. Schildwachter, “How to Predict Compressors Performance,” V. 41, No. 6, p. 151 (1962). 80. Hancock, R., “Drivers Controls and Accessories,” Chem. Eng., p. 204, Oct. (1956). 81. Peters, K. L., “Applying Multiple Inlet Compressors,” Hydro. Proc., V. 60, No. 5, p. 171 (1981). 82. Davis, H., “Evaluating Multistage Centrifugal Compressors,” Chem. Eng., p. 35, Dec. 26, (1983). 83. Gresh, M. T., “Troubleshooting Compressors Performance,” Hydro. Proc., V. 71, No. 1, p. 57 (1992). 84. “Expansion Turbines for Energy Conversion and Cryogenic Applications,” Atlas Copco, Bul. 2781005601, pub. date not known. 85. Sudduth, L. F., “Shortcut Methods Help Expander-Plant Performance,” Oil and Gas Jour., p. 88, Dec. (1974).

Compression Equipment  835 86. Claude, R. W., Axial Compressors, Chem. Eng., V. 63, No. 6. p. 212 (1956). 87. Adams, H. E., “Thermodynamics Characteristics of Nash Compressors,” presented at the 38th annual meeting of TAPPI, Nash Engineering Co., South Norwalk, CT. 88. Bulletin 11,001-A, Axi-Compressor, Ingersoll-Rand Co., New York, NY. 89. Abraham, R. W., “How to Pick Rotary-Screw Compressors,” Oil and Gas Jour., p. 90, June 12, (1972). 90. Price, B. C., “Know the Range and Limitations of Screw Compressors,” Chem. Eng. Prog., V. 87, No. 2, p. 50 (1991). 91. Abraham, R. W., “How to Pick Rotary Screw Compressors,” Oil and Gas Jour., p. 94, June 12, (1972). 92. Van Ormer, H. P., Jr., “Better Service from Rotary Screw Air Compressors Package,” Hydro. Proc., p. 181, May (1980). 93. Bloch, H. P., and P. W. Noack, “Screw Compressors,” Chem. Eng., V. 99, No. 2, p. 108 (1992). 94. Patton, P. W., and C. F. Joyce, “Lowest Cost Vacuum System,” Chem. Eng., p. 84, Feb. 2, (1976). 95. McCormick, M., Playing It Cool, Hydrocarbon Engineering, pp 66–71, May (2013). 96. Wehrman, J. G., Walder, T. E., and N. J. Haryett., The Use of Integrally Geared Compressors Based on Two Industrial Gas Companies’ Experience, Proc. Of the 32nd Turbomachinery Symposium, pp 209 – 219, (2003). 97. De Maria, R. K., Consider integral-gear compressors in CO2 services, Hydrocarbon Processing, pp 35–36, May (2013). 98. Livingston, E. H., “Build Your Working Knowledge of Process Compressors,” Chem. Eng Prog. V. 89, No. 2, (1993). 99. Renard, D., Rerating rotating equipment optimizes olefins plant performance, Hydrocarbon Processing, pp 43–46, May (2013). 100. Lenz, J.R., and E. A. Cooksey, Application of Computational Fluid Dynamics to Compressor Efficiency Improvement, International Compressor Engineering Conference, Paper 1018, (1994). 101. Nordwall, G., Jumonville, J., and T. Matthews, Desktop Use of Computational Fluid Dynamics To Design and Troubleshoot Compressors and Turboexpanders, Proc. Of the Thirty-Second Turbomachinery Symposium, (2003). 102. Lieberman, Norman P., Process Engineering For A Small Planet, How to Reuse, Re-Purpose, and Retrofti Existing Process Equipment, John Wiley and Sons, Inc. (2012). 103. Roy Sanders, Chemical Process Safety—Learning from Case Histories, 3rd, Elsevier (2005). 104. Lewin, D. R., Seider, W. D., Seader, W. D., Dassau, Eyal., Golbert, Joshua., Goldberg, D., Fucci, Matthew, and Robyn B. Nathanson, Using Process Simulators in Chemical Engineer—A Multimedia Guide For the Core Curriculum, John Wiley & Son (2003). 105. Cronan, C. S., and T. R. Oliver, Eds., “Handling Compressible Fluids,” Reports, Chem. Eng., June (1956). 106. Linde Industrial Gases, Hydrogen: the key refinery enabler, www.digitalrefining.com/article/1000575, Aug. (2012). 107. Coker, A. K., Ludwig’s Applied Process Design for Chemical and Petrochemical Plants, Chapter 20, Vol. 3, 4th ed., Elsevier, 2015. 108. Woodhouse, H. “Efficiencies of Centrifugal Compressors”, The Pet. Eng., p. D11, Oct. 1953 109. Karassik, I.J., “Process Enginieer’s Guide to the Centrifugal Compressor—II”, Chem. Eng., p. 132, Nov. 1947 110. AMCA Special Supplement, Heating, Piping, and Air Conditioning, Air Movement and Control Association, Inc., Feb. (1989), Air Movement and Control Association International, Inc. 111. Tom Baxter, Energy Saviours—Ways for operations and design engineers to boost efficiencies, The Chemical Engineer, p. 43, September, 2018. 112. Ashis Nag, Distillation & Hydrocarbon Processing Practices, Pennwell, 2016. 113. Lieberman, Norman P., Process Engineering For A Small Planet, How to Reuse, Re-Purpose, and Retrofit Exiting Process Equipment, JohnWiley and Sons, Inc. (2012). 114. Engineering Data Book, Gas Processors Suppliers Association (GPSA), 12th. ed., Tulsa, Oklahoma, USA, 2004.

Glossary of Petroleum and Technical Terminology

Abatement: 1. The act or process of reducing the intensity of pollution. 2. The use of some method of abating pollution. 3. Putting an end to an undesirable or unlawful condition affecting the wastewater collection system. Abrasion (Mechanical): Wearing away by friction. Abrasive: Particles propelled at a velocity sufficient to cause cleaning or wearing away of a surface. Absolute Porosity: The percentage of the total bulk volume, which is pore spaces, voids or fractures. Absolute Pressure: 1. The reading of gauge pressure plus the atmospheric pressure. 2. Gauge pressure plus barometric or atmospheric pressure. Absolute pressure can be zero in a perfect vacuum. Units, psia, bara. e.g., psia = psig + 14.7, bara = barg + 1.013. Absolute Temperature: Temperature measurement starting at absolute zero. e.g., °R = °F + 460, K = °C + 273.16 Absolute Viscosity: The measure of a fluid’s ability to resist flow without regard to its density. It is defined as a fluid’s kinematic viscosity multiplied by its density.

Absorbent: The material that can selectively remove a target constituent from another compound by dissolving it. Absorption: A variation of fractionation. In a distillation column, the stream to be separated is introduced in vapor form near the bottom. An absorption liquid called lean oil is introduced at the top. The lean oil properties are such that as the two pass each other, the lean oil will selectively absorb components of the stream to be separated and exit the bottom of the fractionator as rich oil. The rich oil is then easily separated into the extra and lean oil in conventional fractionation. Absorption Gasoline: Gasoline extracted from wet natural gas by putting the gas in contact with oil. Absorption Oil (Facilities): The wash oil used to remove heavier hydrocarbons from the gas stream. Accident: An event or sequence of events or occurrences, natural or man-made that results in undesirable consequences and requires an emergency response to protect life and property.

837

838  Petroleum Refining Design and Application Handbook Volume 2 Accumulator: A vessel that receives and temporarily stores a liquid used in the feedstock or the processing of a feed stream in a gas plant or other processing facility. Acentric Factor: A correlating factor that gives a measure of the deviation in behavior of a substance to that for an idealized simple fluid. It is a constant for each component and has been correlated with the component vapor pressure. Acid Gas: 1. A gas that contains compounds such as CO2, H2S or mercaptans (RSH, where R = CnH2n+1, n=1, 2) that can form an acid in solution with water. 2. Group of gases that are found in raw natural gas and are usually considered pollutants. Amongst these are CO2, H2S and mercaptans. 3. Any produced gas primarily H2S and CO2 that forms an acid when produced in water. Acid Inhibitor: Acid corrosion inhibitor. It slows the acid attack on metal. Acid Number: A measure of the amount of potassium hydroxide (KOH) needed to neutralize all or part of the acidity of a petroleum product. Also referred to as neutralization number (NN) or value (NV) and total acid number (TAN). Acid Soluble Oil (ASO): 1. High boiling polymers produced as an unwanted by-product in the alkylation processes. 2. Polymers produced from side reactions in the alkylation process. Acid Treating/Treatment: A process in which unfinished petroleum products, such as gasoline, naphthas, kerosene, diesel fuel, and lubricating oil stocks, are contacted with sulfuric acid to improve their color, odor, and other properties. Acidity: The capacity of water or wastewater to neutralize bases. Acidity is expressed in milligrams per liter of equivalent calcium carbonate (CaCO3). Acidity is not the same as pH because water does not have to be strongly acidic (low pH) to have a high acidity. Acidity is a measure of how much base must be added to a liquid to raise the pH to 8.2. AC Motor: Most of the pumps are driven by alternating current, three-phase motors. Such motors that drive pumps are usually fixed-speed drivers. DC motors are rarely used in process plants. Activity of Catalyst: Activity generally means how well a catalyst performs with respect to reaction rate, temperature or space velocity.

Actual Tray: A physical tray (contact device) in a distillation column, sometimes called a plate. Adsorbents: Special materials like activated charcoal, alumina or silica gel, used in an adsorption process that selectively cause some compounds, but not others, to attach themselves mechanically as liquids. Adsorption: 1. A process for removing target constituents from a stream by having them condense on an adsorbent, which is then taken off line so the target constituents can be recovered. 2. The process by which gaseous components adhere to solids because of their molecular attraction to the solid surface. Alarms: Process parameters (levels, temperatures, pressures, flows) are automatically controlled within a permissible range. If the parameter moves outside this range, it sometimes activates both an audible and a visual alarm. If the panel board operator fails to take corrective action, a trip may also then be activated. Alcohol: The family name of a group of organic chemical compounds composed of carbon, hydrogen and oxygen. The series of molecules vary in chain length and are composed of a hydrocarbon plus a hydroxyl group, CH3 (CH2) n – OH (e.g., methanol, ethanol, tertiary butyl alcohol). Alkanolamine: An organic nitrogen bearing compound related to ammonia having at least one, two or three of its hydrogen atoms substituted with at least one, two or three linear or branched alkanol groups where only one or two could also be substituted with a linear or branched alkyl group (i.e., methyldiethanolamine MDEA). The number of hydrogen atoms substituted by alkanol or alkyl groups at the amino site determines whether the alkanolamine is primary, secondary or tertiary. Alkylate: 1. The gasoline produced by an alkylation process. It is made by combining the low boiling hydrocarbons catalytically to obtain a mixture of highoctane hydrocarbons boiling in the gasoline range. 2. The product of an alkylation reaction. It usually refers to the high octane product from alkylation units. This alkylate is used in blending high octane gasoline. Alkylate Bottoms: A thick, dark brown oil containing high molecular-weight polymerization products of alkylation reactions. Alkylation: 1. A refining process for chemically combining isobutane (iC4H10) with olefin hydrocarbons [e.g., propylene (C3H6), butylenes (C4H8)] through the

Glossary of Petroleum and Technical Terminology  839 control of temperature and pressure in the presence of an acid catalyst. 2. A refining process in which light olefins primarily a mixture of propylene (C3H6), butylenes (C4H8) and/or amylenes are combined with isobutane (iC4H10) over an acid catalyst to produce a high octane gasoline (highly branched C5 – C12, i-paraffins), called alkylate. The commonly used catalysts are sulfuric acid (H2SO4) and hydrofluoric acid (HF). The major constituents of alkylate are isopentane and isooctane (2,2,4 – trimethyl pentane, TMP), the latter possessing an octane number of 100. The product, alkylate, is an isoparaffin, has high octane value and is blended with motor and aviation gasoline to improve the antiknock value of the fuel. Aluminum Chloride Treating: A quality improvement process for steam cracked naphthas using aluminum chloride (AlCl3) as a catalyst. The process improves the color and odor of the naphtha by the polymerization of undesirable olefins into resins. The process is also used when production of resins is desirable. American Petroleum Institute (API): An association, which among many things sets technical standards for measuring, testing and other types of handling of petroleum. Amine Treating: Contacting of a gas or light hydrocarbon liquid with an aqueous solution of an amine compound to remove the hydrogen sulfide (H2S) and carbon dioxide (CO2). Anaerobic Digestion: Is a collection of processes by which microorganisms break down biodegradable material in the absence of oxygen. The process is used for industrial or domestic purposes to manage waste and/or to produce fuels. Much of the fermentation used industrially to produce food and drink products, as well as home fermentation uses anaerobic digestion. The digestion process begins with bacterial hydrolysis of the input materials. Insoluble organic polymers such as carbohydrates are broken down to soluble derivatives that become available for other bacteria. It is used as part of the process to treat biodegradable waste and sewage sludge. As part of an integrated waste management system, anaerobic digestion reduces the emission of landfill gas into the atmosphere. Anaerobic digestion is widely used as a source of renewable energy. The process produces biogas, consisting of methane, carbon dioxide and traces of other “contaminant” gases. The biogas can

be used directly as fuel in combined heat and power gas engines or upgraded to natural gas-quality biomethane. The nutrient-rich digestate also produced can be used as fertilizer. Aniline Point: The minimum temperature for complete miscibility of equal volumes of aniline and the test sample. The test is considered an indication of the paraffinicity of the sample. The aniline point is used as a classification of the ignition quality of diesel fuels. Antiknock Agent: 1. Is a gasoline additive used to reduce engine knocking and increase the fuel’s octane rating by raising the temperature and pressure at which auto-ignition occurs. The mixture is gasoline or petrol, when used in high compression internal combustion engines, has a tendency to knock (also, referred to as pinging, or pinking) and/or to ignite early before the correctly time spark occurs (pre-ignition, refers to engine knocking). 2. The most wanted and widely used additives in gasoline are the antiknock compounds. They assist to enhance the octane number of gasoline. Lead in the form of tetra ethyl lead (TEL) or tetra methyl lead (TML) is a good antiknock compound. TEL helps to increase the octane number of gasoline without affecting any other properties, including vapor pressure, but when used alone in gasoline gives rise to troublesome deposits. Antiknock Index: The Research Octane Number (RON) test simulates driving under mild conditions while the Motor Octane Number (MON) test simulates driving under severe conditions, i.e., under load and at high speed. The arithmetic average of RON and MON that gives an indication of the performance of the engine under the full range of conditions is referred to as AntiKnock Index (AKI). It is determined by:

Antiknock Index ( AKI) =

RON+MON 2

Antiknock Quality (Octane Number): Knocking is a characteristic property of motor fuels that governs engine performance and is expressed in terms of octane number. It depends on the properties of hydrocarbon type and nature. Octane number is the percentage of iso-octane in the reference fuel, which matches the knocking tendency of the fuel under test. Research octane number (RON) and motor octane number

840  Petroleum Refining Design and Application Handbook Volume 2 (MON) are two methods used and are measured with a standard single cylinder, variable compression ratio engine. For both octane numbers, same engine is used, but operated at different conditions. The distinction between two octane numbers (RON and MON) measurement procedures are engine speed, temperature of admission and spark advance. The motor method captures the gasoline at high engine speeds and loads, and the research octane method at low speed depending on the fuel characteristics. The MON is normally 8–10 points lower than the RON. A high tendency to autoignite, or low octane rating, is undesirable in a gasoline engine, but desirable in a diesel engine. Antiknock index (AKI) = (RON + MON)/2. API Gravity: A method for reporting the density of petroleum streams. It is defined as   141.5 °API =  − 131.5 , where Sp.Gr  Sp.Gr @ 60 / 60 °F  is the specific gravity relative to water. °API gravity is reported at a reference temperature of 60°F (15.9°C). The scale allows representation of the gravity of oils, which on the specific gravity 60/60°F scale varies only over a range of 0.776 by a scale that ranges from less than 0 (heavy residual oil) to 340 (methane). According to the expression, 10°API indicates a specific gravity of 1 (equivalent to water specific gravity). Thus, higher values of API gravity indicate lower specific gravity and therefore lighter crude oils, or refinery products and vice-versa. As far as crude oil is concerned lighter API gravity value is desired as more amount of gas fraction, naphtha and gas oils can be produced from the lighter crude oil than with the heavier crude oil. Therefore, crude oil with high values of API gravity is expensive to produce due to their quality. Classification of crude oils Crude category Light crudes Medium crudes Heavy crudes Very heavy crudes

API gravity °API > 38 38 > °API > 29 29 > °API > 8.5 °API < 8.5 o

The higher the API gravity, the lighter the compound. Light crudes generally exceed 38°API and

heavy crudes are commonly are crudes with an °API of 22 or below. Intermediate crudes fall in the range of 22–38 °API (See Figures 1a and 1b). Aromatics: 1. A group of hydrocarbons characterized by having at least one benzene ring type structure of six carbon atoms with three double and three single bonds connecting them somewhere in the molecule. The general formula is CnH2n-6 where n = 6, 7, 8, etc. The simplest is benzene, plus toluene and the xylenes. Aromatics in gas oils and residues can have many, even scores of rings. 2. The three aromatic compounds – benzene (C6H6), toluene (C7H8), xylene (C8H10). As Low As Reasonably Practicable (ALARP): The principle that no industrial activity is entirely free from risk and that it is never possible to be sure that every eventuality has been covered by safety precautions, but that there would be a gross disproportion between the cost in (money, time or trouble) of additional preventive or protective measures, and the reduction in risk in order to achieve such low risks (See Figure 2). Asphalt: 1. A heavy semi-solid petroleum product that gradually softens when heated and is used for surface cementing. Typically brown or black in color, it is composed of high carbon to hydrogen hydrocarbons. It occurs naturally in crude oil or can be distilled or extracted. 2. The end product used for area surfacing consisting of refinery asphalt mixed with aggregation. 3. Heavy tar-like residue from distillation of some types of crude oil. Asphalt components are high molecular weight derivatives of aromatic compounds. Not all asphalt materials are suitable for use as building agents in road pavement. Asphaltenes: Highly condensed masses of high molecular weight aromatic compounds. They exit in petroleum residuum as the center of colloidal particles or micelles. The asphaltenes are kept in solution by an outer ring of aromatic compounds of lower molecular weight. They can precipitate when the continuous nature of the surrounding ring of aromatics is broken down by cracking processes. Assay Data: Laboratory test data for a petroleum stream, including laboratory distillation, gravity, compositional breakdown and other laboratory tests. Numerous important feed and product characterization properties in refinery engineering include:

Glossary of Petroleum and Technical Terminology  841 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 21. 22. 23.

API gravity Watson Chracterization factor Viscosity Sulfur content, wt % Nitrogen content, wt % Carbon residue, wt% Salt content Metal contents Asphaltene, % Naphthenes, % True boiling point (TBP) curve Pour point Cloud point Freeze point Aniline point Flash and fire point ASTM distillation curve Octane number Conradson carbon Reid vapor pressure Bottom sediment and water (BS &W) Light hydrocarbon yields (C1 – C5)

The crude quality is getting heavier worldwide. Existing refineries that are designed to handle normal crudes are being modified to handle heavy crude. New technology for upgrading is used to obtain clean and light products from lower cost feeds. The crude assay will determine the yields of different cuts and consequently the refinery configuration. Associated Natural Gas: Natural gas that is dissolved in crude in the reservoir and is co-produced with the crude oil. ASTM: American Society of Testing and Materials. Nearly all of the refinery product tests have been standardized by ASTM. ASTM Distillation: A standardized laboratory batch distillation for naphthas and middle distillates carried out at atmospheric pressure without fractionation. ASTM Distillation Range: Several distillation tests are commonly referred to as “ASTM distillations.” These are usually used in product specifications. These

ASTM distillations give results in terms of percentage distilled versus temperature for a sample laboratory distillation with no fractionation. The values do not correspond to those of refinery process distillations, where fractionation is significant. ASTM D86 Distillation: Of an oil fraction takes place at laboratory room temperature and pressure. Note that the D86 distillation will end below an approximate temperature of 650°F (344°C), at which petroleum oils begin to crack at one atmospheric pressure. ASTM D1160 Distillation: Of an oil fraction is applicable to high-boiling oil samples (e.g., heavy heating oil, cracker gas oil feed, residual oil, etc.) for which there is significant cracking at atmospheric pressures. The sample is distilled at a reduced pressure, typically at 10 mm Hg, to inhibit cracking. In fact, at 10 mmHg, we can distill an oil fraction up to temperatures of 950–1000°F (510–538°C), as reported on a 760 mm Hg basis. The reduced pressure used for D1160 distillation produces a separation of components that is more ideal than that for D86 distillation. ASTM D2887 Distillation: Of oil fraction is a popular chromatographic procedure to “simulate” or predict the boiling point curve of an oil fraction. We determine the boiling point distribution by injecting the oil sample into a gas chromatograph that separates the hydrocarbons in a boiling-point order. We then relate the retention time inside the chromatograph to the boiling point through a calibration curve. ASTM End Point of Distillates: End point is an important specification or way of describing gasolines, naphthas, or middle distillates. It’s the approximate relationship between the end point of a fraction and its True Boiling Point (TBP) and other cut points. Atmospheric Distillation: 1. The refining process of separating crude oil components at atmospheric pressure by heating to temperatures of 600–750°F (316–400°C) (depending on the nature of the crude oil and desired products) and subsequent condensing of the fractions by cooling. 2. Distillation/Fractionation of crude oil into various cuts/fractions under atmospheric condition. The more volatile components (i.e., lower boiling points) rise through trays/bubble caps and are condensed at various temperatures and the least volatile components, short and long residues

842  Petroleum Refining Design and Application Handbook Volume 2 API gravity of some hydrocarbon compounds

100 90 80 70 60

°API

50 40 30 20 10 0

(a)

0.6

Specific gravity @60°F/15,5°C

1.10 1.05 1.00

0.7

0.8

0.9 1 Specific gravity

1.1

1.2

1.2

API vs gravity Extra heavy oil Bitumen

Heavy oil

0.95 Medium oil

0.90 0.85

Light oil

0.80

Condensate

0.75 0.70 0.65 0.60

EngineeringToolBox.com 0

10

20

30

LNG/CNG 40

50

60

70

80

90

°API

(b)

Figure 1 (a) A plot of °API vs. specific gravity of hydrocarbons compounds. (b) Specific gravity vs. °API of hydrocarbons (Source: EngineeringToolBox.com) Alarp determination process - overview Yes Can the hazard/threat be eliminated or reduced?

Examples: Modify how the work will be performed, such as reduce or eliminate the need for work at heights, technology improvement such as organic growth control in cooling water instead of Cr, etc.

No

Is there a standard or practice to apply?

1) Eliminate or reduce the hazards.

Yes

2) Apply current company’s standards (e.g. DEP) or industry work practices (the whole threat to consequence line should be covered)

No

Apply risk-based approach 3) Bow-ties or 4) Barrier counting or

Figure 2 ALARP determination process overview. DEP = Design Engineering Practice.

5) Residual risk (LOPA or QRA)

A L A R P

Glossary of Petroleum and Technical Terminology  843 (i.e., higher boiler points ) are removed as bottom products.

Azeotropes cannot be separated with conventional distillation.

Atmospheric Crude Oil Distillation: The refining process of separating crude oil components at atmospheric pressure by heating to temperatures of about 600–750 °F (316–400°C) (depending on the nature of the crude oil and desired products) and subsequent condensing of the fractions by cooling.

Backflow: 1. A flow condition, caused by differential pressure, resulting in the flow of liquid into the potable water supply system from sources other than those intended; or the backing up of liquid, through a conduit or channel, in a direction opposite to normal flow. 2. Return flow from injection of a fluid into a formation.

Atmospheric Gas Oil (AGO): A diesel fuel and No. 2 heating oil blending stock obtained from the crude oil as a side stream from the atmospheric distillation tower. Atmospheric Reduced Crude (ARC): The bottoms stream from the atmospheric distillation tower. Atmospheric Residuum: The heaviest material from the distillation of crude oil in a crude distillation column operating at a positive pressure. Autoignition: The spontaneous ignition and resulting rapid reaction of a portion of or all the fuel-air mixture in the combustion chamber of an internal combustion engine. The flame speed is many times greater than that following normal ignition. Autoignition Temperature (AIT): 1. The lowest temperature at which a gas will ignite after an extended time of exposure. 2. The lowest temperature at which a flammable gas or vapor air mixture will ignite from its own heat source or a contacted heat source without the necessity of a spark or a flame. Aviation Gasoline Blending Components: Naphtha’s which will be used for blending or compounding into finished aviation gasoline (e.g., straight-run gasoline, alkylate, reformate, benzene, toluene, xylenes). Excludes oxygenates (alcohols, ethers), butanes and pentanes. Oxygenates are reported as other hydrocarbons, hydrogen and oxygenates. Aviation Gasoline (Finished): A complex mixture of relatively volatile hydrocarbons with or without small quantities of additives, blended to form a fuel suitable for use in aviation reciprocating engines. Fuel specifications are provided in ASTM Specification D910 and Military Specification MIL-G-5572. Note: Data on blending components are not counted in data on finished aviation gasoline. Azeotrope: A constant boiling point mixture for which the vapor and liquid have identical composition.

Back Pressure: A pressure caused by a restriction or fluid head that exerts an opposing pressure to flow. Barrel: A volumetric measure of refinery feedstocks and products equal to 42 U.S. gal. Barrels Per Calendar Day (BPCD or B/CD): Average flow rates based on operating 365 days per year. The amount of input that a distillation facility can process under usual operating conditions. The amount is expressed in terms of capacity during a 24-hour period and reduces the maximum process capability of all units at the facility under continuous operation to account for the following limitations that may delay, interrupt, or slow down production: The capability of downstream facilities to absorb the output of crude oil processing facilities of a given refinery. No reduction is made when a planned distribution of intermediate streams through other than downstream facilities is part of a refinery’s normal operation; the types and grades of inputs to be processed; the types and grades of products expected to be manufactured; the environmental constraints associated with refinery operations; the reduction of capacity for scheduled downtime due to such conditions as routine inspection, maintenance, repairs and turnaround, and the reduction of capacity for unscheduled downtime due to such conditions. Barrels Per Stream Day (BPSD or B/SD): The maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude and product slate conditions with no allowance for downtime. This notation equals barrels per calendar day divided by the service factor. Basic Process Control System (BPCS): A system which responds to input signals from the process, its associated equipment, other programmable systems and/or an operator and generates output signals causing the process and its associated equipment to operate

844  Petroleum Refining Design and Application Handbook Volume 2

Battery Limits (BL): The periphery of the area surrounding any process unit, which includes the equipment for the particular process. Baume gravity: Specific gravity of liquids expressed as degrees on the Baume scale. For liquids lighter than water,

Sp.Gr @15.6 / 15.6 °C =

140 130 + deg Be

For liquids heavier than water

145 Sp.Gr @15.6 / 15.6 °C = 145 - deg Be Bbl: Abbreviation for a quantity of 42 U.S. gal. Benchmark crude: A reference crude oil with whom the prices of other crudes are compared with. Benzene (C6H6): An aromatic hydrocarbon present in small proportion in some crude oils and made commercially from petroleum by the catalytic reforming of naphthenes in petroleum naphtha. It is also made from coal in the manufacture of coke. Used as a solvent, in manufacturing detergents, synthetic fibers, and petrochemicals and as a component of high-octane gasoline. Bernoulli equation: A theorem in which the sum of the pressure-volume, potential, and kinetic energies of an incompressible and non-viscous fluid flowing in a pipe with steady flow with no work or heat transfer is the same anywhere within a system. When expressed in head form, the total head is the sum of the pressure, velocity and static head. It is applicable only for incompressible and non-viscous fluids as: In SI Units

v2 P1 v12 P + + z1 = 2 + 2 + z2 + h f rg 2 g rg 2 g where hf is the pipe friction from point 1 to point 2 may be referred to as the head loss in metres of fluid. In Imperial Units.

v12

v22

144P1 g g 144 P2 + + z1 = + + z2 + h f gc gc r 2gc r 2gc where hf is the pipe friction from point 1 to point 2 in foot-pounds force per pound of flowing fluid; this is sometimes referred to as the head loss in feed of fluid.

where, P is pressure, ρ is density, gc is conversion factor  lbm ft  , g is acceleration due to gravity (32 ft/ •  32.174  lb f s 2   s2), v is velocity, z is elevation and hf is frictional head loss. It is a statement of the law of the conservation of energy, which was formulated by Daniel Bernoulli in 1738 (See Figure 3). Bitumen: That portion of petroleum, asphalt, and tar products that will dissolve completely in carbon disulfide (CS2). This property permits a complete separation from foreign products not soluble in carbon disulfide. Blast: A transient change in gas density, pressure (either positive or negative), and velocity of the air surrounding an explosion point. Blending: One of the final operations in refining, in which two or more different components are mixed together to obtain the desired range of properties in the final product. Blending Components: Modern gasoline is a blend of various refinery streams produced by distillation, cracking, reforming and polymerization together with additives to achieve the specific fuel performance requirements. Blending Octane Number: When blended into gasoline in relatively small quantities, high-octane materials behave as though they had an octane number higher than shown by laboratory tests on the pure Total head (energy grade line) v12 2g

Head (ft) of fluid

in the desired manner but which does not perform any safety instrumented functions (SIF) with a claimed Safety Instrumented Level, SIL ≥ 1.

hL

Hydraulic gr

ade line

144 × P1 ρ1

v22 2g

144 × P2 ρ2

Pressure head, P Velocity head

1 Z1

2

Flow

Z2

Elevation head

Arbitrary horizontal datum line Z1+

Pipe length (ft)

144 P1 v12 144 P2 v22 + = Z2+ + + hL ρ1 ρ2 2g 2g

Figure 3 Distribution of fluid energy in a pipeline.

Glossary of Petroleum and Technical Terminology  845 material. The effective octane number of the material in the blend is known as the blending octane number. Blending Plant: A facility which has no refining capability but is either capable of producing finished motor gasoline through mechanical blending or blends oxygenates with motor gasoline. Blending Value (hydrocarbon): In octane ratings of a hydrocarbon made on blends of 20 percent hydrocarbon plus 80 percent of a 60 : 40 mixture of isooctane (iC8H18) and n-heptane (nC7H16), the blending octane number is a hypothetical value obtained by extrapolation of a rating of 100% concentration of the hydrocarbon. Blocked operation: A set of operating conditions and procedures that apply to a particular feed stock and/or set of product specifications for a process. Boiler: 1. A closed vessel in which a liquid is heated or heated and evaporated. Boilers are often classified as steam or hot water, low pressure or high pressure, and capable of burning one fuel or a number of fuels. 2. Vessel in which a liquid is heated with or without vaporization; boiling need not occur. Boiler Feed Pump: A pump which returns condensed steam, makeup water or both directly to the boiler. Boiler Feed Water: Water supplied to a boiler by pumping. Boiling Liquid Expanding Vapor Explosion (BLEVE): 1. The nearly instantaneous vaporization and corresponding release of energy of a liquid upon its sudden release from a containment under pressure than atmospheric pressure and at a temperature above its atmospheric boiling point. 2. A type of rapid phase transition in which a liquid contained above its atmospheric boiling point is rapidly depressurized, causing a nearly instantaneous transition from liquid to vapor with a corresponding energy release. A BLEVE is often accompanied by a large fireball if a flammable liquid is involved, since an external fire impinging on the vapor space of a pressure vessel is a common BLEVE scenario. However, it is not necessary for the liquid to be flammable to have a BLEVE to occur. Blowdown: The disposal of voluntary discharges of liquids or condensable vapors from process and vessel drain valves, thermal relief or pressure relief valves. Blowout: An uncontrolled flow of gas, oil or other well fluids from a wellbore at the wellhead or into a

ground formation, caused by the formation pressure exceeding the drilling fluid pressure. It usually occurs during drilling on unknown (exploratory) reservoirs. Boiling Point: 1. Heat a liquid and its vapor pressure increases. When the liquid’s vapor pressure equals the pressure in the vessel, the liquid starts to boil. The temperature at which this boiling starts is the liquid’s boiling temperature. 2. Typically refers to the temperature at which a component or mixture of components starts to vaporize at a given pressure. When used in petroleum refining, it is usually synonymous with the normal boiling point (i.e., boiling point at one atmosphere). 3. The temperature at which the pressure exerted by molecules leaving a liquid equals the pressure exerted by the molecules in the air above it. A free-for-all of molecules leaving the liquid then ensures. In a solution, the boiling point will be increased by a number that depends on the number of particles in solution: delta (T) = Kb x (number of solute molecules per liter) where delta (T) = the rise in the boiling point. Kb = the ebulllioscopic constant and varies from one solvent to another. Boiling Range: 1. The spread of temperatures over which oil starts to boil or distill vapors and proceeds to complete evaporation. Boiling range is determined by ASTM test procedures for specific petroleum products. It is measured in °F or (°C). 2. The lowest through to highest boiling temperatures for a petroleum stream when distilled. Boiling ranges are often reported on a TBP (true boiling point) basis, i.e., as normal boiling points. Boiling Temperature: The temperature at which steam bubbles begin to appear within a liquid. When the fluid is a pure compound, the boiling point is unique for each pressure. Boil Off: A small amount of LNG evaporates from the tank during storage, cooling the tank and keeping the pressure inside the tank constant and the LNG at its boiling point. A rise in temperature is encountered by the LNG being vented from the storage tank. Boil Off Vapor: Usually refers to the gases generated during the storage or volatile liquefied gases such as LNG. Natural gas boils at slightly above -261°F (-163°C) at atmospheric pressure and is loaded, transported and discharged at this temperature, which requires special materials, insulation and handling equipment to deal with the low temperature and the boil-off vapor.

846  Petroleum Refining Design and Application Handbook Volume 2 Boot, Boot Cooler: The section of a distillation column below the trays. For columns with very hot feeds, a portion of the bottom product is cooled and circulated through the boot or lower the temperature of the liquid in the boot and prevent depositing of coke. Many vacuum distillation columns have boot coolers. Bottoms: 1. The heavy fractions or portions, of a crude oil that do not vaporize during fractionation/ distillation. 2. The accumulation of sediments, mud and water in the bottoms of lease tanks. 3. The product coming from the bottom of a fractionating column. In general, the higher-boiling residue that is removed from the bottom of a fractionating tower. 4. The liquid level left in a tank after it has been pumped “empty” and the pump loses suction. Bow-Tie–Analysis (BTA): 1. A qualitative risk analysis that portrays events and consequences on either side of a “bowtie”. Barriers or safeguards are shown in between the two sides. It depicts the risks in ways that are readily understandable to all levels of operations and management. 2. A type of qualitative safety review where cause scenarios are identified and depicted on the pre-event side (left side) of a bow-tie diagram. Credible consequences and scenarios outcomes are depicted on the post-event side (right side) of the diagram, and associated barrier safeguards are included(See Figure 4). Brackish Water: Indefinite term meaning water with small amounts of salt. Saltier than fresh water. Brainstorming: A group problem-solving technique that involves the spontaneous contribution of ideas from all members of the group primarily based on their knowledge and experience. Brent: A large oil field in the U.K sector of the North Sea. Its name is used for a blend of crudes widely used The bow-tie model Objective: reduce liklihood (pro-active/preventative) H A Z A R D

Conse quence

Scenario Top event Threats Controls

Recovery measures

Control (keep within control limits)

Conse quence

Conse quence Prepare for emergencies

Objective: mitigate consequences and reinstate (reactive)

Figure 4 The Bow-Tie – Analysis.

as a price marker or benchmark for the international oil industry. Brent crude currently has an average quality of 38°API. Brent Blend: A light sweet crude oil produced in the North Sea; a benchmark for pricing of many foreign crude oils. Bright Stock: Heavy lube oils (frequently the vacuum still bottoms) from which asphaltic compounds, aromatics, and waxy paraffins have been removed. Bright stock is one of the feeds to a lube oil blending plant. British thermal unit (Btu): A standard measure of energy; the quantity of heat required to raise the temperature of 1 pound of water by 1°F. Bromine Index: Measure of the amount of bromine reactive material in a sample; ASTM D-2710. Bromine Number: A test that indicates the degree of unsaturation in the sample (olefins and diolefins); ASTM D-1159. BTX: The acronyms for the commercial petroleum aromatics benzene, toluene and xylene. Bubble Cap: 1. It is an inverted cup with a notched or slotted periphery to disperse the vapor in small bubbles beneath the surface of the liquid on the bubble plate in a distillation column. The bubble caps cause the vapor coming from the bottom to come in intimate contact with the liquid sitting on the tray. 2. A bubble cap tray has riser or chimney fitted over each hole, and a cap that covers the riser. The cap is mounted so that there is a space between riser and cap to allow the passage of vapor. Vapor rises through the chimney and is directed downward by the cap, finally discharging through slots in the cap, and finally bubbling through the liquid on the tray (See Figure 5). Bubble Point: 1. This is the same as the boiling point. When a liquid is at its bubble point, it is said to be saturated liquid at the temperature and pressure. If we raise the pressure, the liquid’s bubble point temperature goes up. 2. The temperature and pressure at which a liquid first begins to vaporize into gas. 3. The temperature at which the first bubbles appear when a liquid mixture is heated. 4. The temperature at which a component or mixture of components begins to vaporize at a given pressure. It corresponds to the point of zero percent vaporization or 100 percent condensation. The pressure should be specified, if not one atmosphere. 5. The pressure at which gas begins to break out

Glossary of Petroleum and Technical Terminology  847

Cap Liquid

Slot

Riser Liquid

Vapour

Tray Vapour Vapour

Liquid Vapour

Figure 5 A Bubble cap tray.

of under-saturated oil and form a free gas phase in the matrix or a gas cap.

Bunker Fuel Oil: A heavy residual fuel oil used by ships, industry and large-scale heating installations.

Bubble Tower or Column: A fractionating tower constructed in such a way that the vapors rising up pass through different layers of condensate on a series of plates. The less volatile portions of vapor condense in bubbling through the liquid on the plate, overflow to the next lower plate and finally back to the boiler.

Butadiene (C4H6): A diolefin with two double bonds and two isomers. A colorless gas resulting from cracking processes. Traces result from cat. cracking from catalytic dehydrogenation of butane (C4H10) or butylenes (C4H8) and in ethylene plants using butane, naphtha or gas oil as feeds. Butadiene is principally used to make polymers like synthetic rubber and acrylonitrile butadiene styrene (ABS) plastics.

Bubble Tray: A horizontal tray fitted in the interior of a fractionating tower; meant to give intimate contact between rising vapors and falling liquid in the tower. Bulk Properties: Provide a quick understanding of the type of the oil sample such as sweet or sour, light and heavy, etc. However, refineries require fractional properties of the oil sample that reflects the property and composition for specific boiling-point range to properly refine it into different end products such as gasoline, diesel, and raw materials for chemical process. Fractional properties usually contain paraffins, naphthenes and aromatics (PNA) contents, sulfur content, nitrogen content for each boiling-point range, octane number of gasoline, freezing point, cetane index and smoke point for kerosene and diesel fuels. Bulk Station: A facility used primarily for the storage and/or marketing of petroleum products which has a total bulk storage capacity of less than 50,000 barrels and receives its petroleum products by tank car or truck. Bulk Terminal: A facility used primarily for the storage and/or marketing of petroleum products which has a total bulk storage capacity of 50,000 barrels or more and/or receives petroleum products by tanker, barge or pipeline.

Butane (C4H10): A normally gaseous four-carbon straight chain or branched-chain hydrocarbon extracted from natural gas or refinery gas streams. It includes normal butanes and refinery grade butanes and is designated in ASTM Specification D1835 and Gas Processors Association Specifications for commercial butane. Commercial butane is typically a mixture of normal and isobutene, predominantly normal. Hydrocarbons in the paraffin series with a general formula CnH2n+2, where n = 1, 2, 3, 4, 5, etc. To keep than liquid and economically stored, butane must be maintained under pressure or at low temperatures. Butylene/Butene (C4H8): Hydrocarbons with several different isomers in the olefin series with a general formula CnH2n. Used in refining in an alkylation plant or in petrochemicals to make solvents and some polymers. Carbon Hydrogen Ratio: The carbon hydrogen ratio is determined by the following:

C 74 + 15d = H 26 − 15d where d is the specific gravity at 15°C

848  Petroleum Refining Design and Application Handbook Volume 2 The carbon hydrogen ratios of different products are: LPG (d= 0.56)

= 4.68

Naphtha (d = 0.72)

= 5.57

Gasoline (d = 0.73)

= 5.64

ATF (d = 0.79)

= 6.067

SK (d = 0.795)

= 6.10

JP5 (d = 0.80)

= 6.14

HSD (d = 0.845)

= 6.50

LDO (d = 0.87)

= 6.72

LSHS (d = 0.98)

= 7.85

FO (d = 0.99)

=7.97

Calorific Value: 1. A measure of the amount of energy released as heat when a fuel is burned. 2. The quantity of heat produced by the complete combustion of a fuel. This can be measured dry or saturated with water vapor, net or gross. It is a measure of the heat producing capacity of the fuel. It is determined by:

Qv = 12400 − 2100d 2 where Qv = calorific value, gross cals/g d = density at 15°C Note: 1 cal = 4.184 Joules Calorific value (average) of different fuels Fuel

Calorific value, kcal/kg

Naphtha

11330

Kerosene

11070

HSD

10860

Fuel Oil

10219

Charcoal

6900

Hard coal

5000

Fire wood

4750

Lignite-Brown coal

2310

Carbon Number: The number of carbon atoms in one molecule of a given hydrocarbon. Carbon Residue: Carbon residue is a measure of the coke-forming tendencies of oil. It is determined by destructive distillation in the absence of air of the sample to a coke residue. The coke residue is expressed as the weight percentage of the original sample. There are two standard ASTM tests, Conradson carbon residue (CCR) and Ramsbottom carbon residue (RCR).

Catalyst: A substance present in a chemical reaction that will promote, accelerate or selectively direct a reaction, but does not take part in it by changing chemically itself. Sometimes a catalyst is used to lower the temperature or pressure at which the reaction takes place. Catalyst/Oil Ratio (C/O): The weight of circulating catalyst fed to the reactor of a fluid-bed catalytic cracking unit divided by the weight of hydrocarbons charged during the same interval. Catalytic Cracking: 1. The refining process of breaking down the larger, heavier, and more complex hydrocarbon molecules into simpler and lighter molecules. Catalytic cracking is accomplished by the use of a catalyst and is an effective process for increasing the yield of gasoline from crude oil. Catalytic cracking processes fresh feeds and recycled feeds. 2. A central process in reforming in which heavy gas oil range feeds are subjected to heat in the presence of a catalyst and large molecules crack into smaller molecules in the gasoline, diesel and surrounding ranges. 3. A petroleum refining process in which heavy hydrocarbon molecules are broken down (cracked) into lighter molecules by passing them over a suitable catalyst (generally heated). 4. A method of cracking that uses a catalyst to convert hydrocarbons to positively charged carbonations, which then break down into smaller molecules. This can be carried out at much lower temperatures than thermal cracking – still hot 932–1112°F (500–600°C) as compared to around 1292°F (700°C). But that difference adds up to a lot of dollars. Catalytically Cracked Distillates: These are obtained when high-boiling non-gasoline hydrocarbons are heated under pressure in the presence of a catalyst to obtain lower-boiling gasoline components. Catalytically cracked distillates usually have high octane numbers than straight-run gasoline. Catalytic Cycle Stock: That portion of a catalytic cracker reactor effluent that is not converted to naphtha and lighter products. This material, generally 340°F (170°C), either may be completely or partially recycled. In the latter case, the remainder will be blended to products or processed further. Catalytic Hydrocracking: A refining process that uses hydrogen and catalysts with relatively low temperatures and high pressures for converting middle boiling or residual material to high -octane gasoline, reformer charge stock, jet fuel, and/or high-grade fuel

Glossary of Petroleum and Technical Terminology  849 oil. The process uses one or more catalyst, depending upon product output, and can handle high-sulfur feedstocks without prior desulfurization. Catalytic Hydrotreating: A refining process for treating petroleum fractions from atmospheric or vacuum distillation units (e.g., naphthas, middle distillates, reformer feeds, residual fuel oils, and heavy gas oil) and other petroleum (e.g., cat cracked naphtha, coker naphtha, gas oil, etc.) in the presence of catalysts and substantial quantities of hydrogen. Hydrotreating includes desulfurization, removal of substances (e.g., nitrogen compounds) that deactivate catalysts, conversion of olefins to paraffins to reduce gum formation in gasoline, and other processes to upgrade the quantity of the fractions. Catalytic Polymerization (cat. poly): A process in which propylene and/or butylenes components are chemically joined to produce gasoline. A phosphoric acid (HPO3) catalyst is usually employed in the process. Catalyst Promoter: A substance added to a catalyst to increase the fraction of the total catalyst area which is useful for a reaction. Catalytic Reforming: 1. A refining process using controlled heat and pressure with catalysts to rearrange certain hydrocarbon molecules, thereby converting paraffinic and naphthenic hydrocarbons (e.g., lowoctane gasoline boiling range fractions) into petrochemical feedstocks and higher octane stocks suitable for blending into finished gasoline. 2. A process where low octane straight-run naphthas are chemically changed into high-octane gasoline, called reformate and to produce aromatics (BTX: benzene, toluene and xylene) for petrochemical plants over a platinum (Pt) catalyst. The reformate has higher aromatic and cyclic hydrocarbon contents. Catalytic reforming is reported into two categories, namely: Low Pressure. A processing unit operating at less than 225 psig measured at the outlet separator. High Pressure: A processing unit operating at either equal to or greater than 225 psig measured at the outlet separator.

Catastrophic Incident: An incident involving a major uncontrolled emission, fire or explosion with an outcome effect zone that extends offsite into the surrounding community. Cause: The reasons why deviations might occur. Caustic Soda: Name used for sodium hydroxide (NaOH); used in refineries to treat acidic hydrocarbon streams to neutralize them. Cavitation: 1. The creating of high-speed, very low pressure vapor bubbles that quickly and violently collapse. It is very detrimental to surfaces in the near proximity, and often seen in severe turbulent flow. 2. Occurs during vaporization of a pumped fluid resulting in vibration, noise, and destruction of equipment. This is when the absolute pressure of the system equals the vapor pressure of the pumped fluid. In a centrifugal pump, it results in the damage of the impeller. 3. When the pressure of liquid flowing into a centrifugal pump gets too low, liquid boils inside the pump case and generates bubbles. The discharge pressure and flow become erratically low. Centipoise (cP): A measure of viscosity related to centistrokes by adjusting for density. 1. Viscosity measurement, 1/1000th of a poise. 2. A centripoise (cP) is 1/1000th of a poise (P), which is the fundamental unit of dynamic viscosity in the CGS system of units. In the SI system of units, the fundamental unit of dynamic viscosity is the Pascal second (Pa.s) is equivalent of 10P. Centistoke (cSt): Is 1/100th of a Stoke (St), which is the fundamental unit of kinematic viscosity in the CSG system of units. In the SI system of units, the fundamental unit of kinematic viscosity is the millimeter squared per second (mm2/s), which is equivalent to the centistokes.

Catalyst Selectivity: The relative activity of a catalyst with respect to a particular component or compound in a mixture.

Cetane (Hexadecane, C16H34): An alkane hydrocarbon with a chemical formula C16H34 used as a solvent and in cetane number determinations. 1. A pure paraffin hydrocarbon used as standard reference fuel in determining the ignition qualities of diesel fuels. 2. A number calculated from the API gravity and the D86 50% distilled for a petroleum stock. It is used to rate the performance of a fuel in diesel engines. It is arbitrarily given a cetane number of 100.

Catalyst Stripping: The introduction of steam at a point where spent catalyst leaves the reactor, in order to remove or strip the hydrocarbons retained on the catalyst.

Cetane Index: 1. A number calculated from the average boiling point and gravity of a petroleum fraction in the diesel fuel boiling range, which estimates the cetane number of the fraction according to ASTM

850  Petroleum Refining Design and Application Handbook Volume 2 D976. An indication of carbon – hydrogen ratio. 2. An empirical method for determining the cetane number of a diesel fuel by a formula based on API gravity and the mid-boiling point (ASTM D975). (See for example, http://www.epa.gov/nvfel/testproc/121.pdf.) Cetane Number: 1. The percentage of pure cetane in a blend of cetane and alpha-methyl-naphthalene that matches the ignition quality of a diesel fuel sample. This quality, specified for middle distillate fuel, is the opposite of the octane number of gasoline. It is an indication of ease of self-ignition. 2. A term for expressing the ignition quality of a diesel fuel. 3. A measure of the ignition quality of a diesel fuel, expressed as a percentage of cetane that must be mixed with methyl naphthalene to produce the same ignition performance as the diesel fuel being rated. The higher the number, the more easily the fuel is ignited under compression. It is an important factor in determining the quality of diesel fuel. In short, the higher the cetane number, the more easily the fuel combusts in a compression setting (such as a diesel engine). The characteristic diesel “knock” occurs when fuel that has been injected into the cylinder ignites after a delay causing a late shock wave. Minimizing this delay results in less unburned fuel in the cylinder and less intense knock. Therefore higher-cetane fuel usually causes an engine to run more smoothly and quietly. This does not necessarily translate into greater efficiency, although it may in certain engines. The cetane number is determined in a single cylinder Cooperative Fuel Research (CFR) engine by comparing its ignition quality with that of reference blends of known cetane number. Cetane number = 0.72 diesel index (10)

Charge Capacity: The input (feed) capacity of the refinery processing facilities. Characterization Factor (CF): 1. An index of feed quality, also useful for correlating data on physical properties. The Watson or Universal Oil Property (UOP) characterization factor, KW is defined as the cube root of the mean average boiling point in °R divided by the specific gravity. An indication of carbon to hydrogen ratio. Kw is expressed by

Kw =

TB1/3 Sp.Gr

where = mean average boiling point, °R [°F +460] TB Sp.Gr = Specific gravity at 60°F TB is the average boiling point in °R taken from five temperatures corresponding to 10, 30, 50, 70 and 90% volume vaporized. 2. A calculated factor used to correlate properties for petroleum streams. It is a measure of the paraffinicity of the stream and is defined as CF = MABP1/3 / Sp.Gr  , where MABP = mean average boiling point temperature, °R and Sp.Gr. = specific gravity at 60°F (15.9°C) relative to water. Typically Watson characterization factor varies between 10.5 and 13 for various crude streams. Highly paraffinic crude typically possesses a Kw of 13. On the other hand, highly naphthenic crude possesses a Kw factor of 10.5. Therefore, Watson characterization factor can be used to judge the quality of the crude oil in terms of the dominance of the paraffinic or naphthenic compounds.

Calculated Cetane Index (CCI) is determined by four variables:

Checklist: A detailed list of desired system attributes for a facility. It is used to assess the acceptability of a facility compared to accepted norms.

CCI = 45.2 + (0.0892) (T10 N) + [0.131 + 0.901(B)] [T50 N] + [0.0523 – (0.420)B] [T90 N] + [0.00049] [(T10 N)2 – (T90 N)2] + 107B + 60B2

Clarified Oil: The heaviest stream from a catalytic cracking process after settling to remove suspended catalyst particles.

where T10 T50 T90 B D DN

= = = = = =

10 % distillation temperature, °C 50 % distillation temperature, °C 90% distillation temperature, °C e-3.5DN – 1 Density @ 15 °C D – 0.85

CFR: Combined feed ratio. The ratio of total feed (including recycle) to fresh feed. CGO: Coker gas oil.

Clear Treating: An elevated temperature and pressure process usually applied to thermally cracked naphthas to improve stability and color. The stability is increased by the adsorption and polymerization of reactive diolefins in the cracked naphtha. Clay treating is used for treating jet fuel to remove surface agents that adversely affect the water separator index specifications. Clear: Without lead. Federal regulations require that fuels containing lead must be dyed.

Glossary of Petroleum and Technical Terminology  851 Cloud Point: 1. The temperature at which solidifiable compounds (wax) present in the sample begin to crystallize or separate from the solution under a method of prescribed chilling. 2. The temperature at which a noticeable cloud of crystals or other solid materials appear when a sample is cooled under prescribed conditions. Cloud point is a typical specifications of middle distillate fuels; ASTM D-2500. Cold Filter Plugging: Is defined as that temperature at which a fuel suspension fails to flow through a standard filter when cooled as prescribed by the test method. Coke drum: A large upright drum used as a receptacle for coke formed in the delayed coking process. Coke: 1. A product of the coking process in the form of mostly solid, densely packed carbon atoms. 2. Deposits of carbon that settle on catalysts in cat. crackers, cat. reformers, hydrocrackers and hydrotreaters and degrade their effectiveness. 3. A carbonaceous deposit formed by the thermal decomposition of petroleum. Coker: A refinery process in which heavy feed such as flasher bottoms, cycle oil from a catalytic cracker, or thermal cracked gas oil is cooked at high temperatures. Cracking creates light oils; coke forms in the reactors and needs to be removed after they fill up. Coking: A refining process in which petroleum oil is heated destructively such that the heaviest materials are converted to coke. There are two processes: delayed coking and fluid coking, with delayed coking being the most widely used. Coil: A series of pipes in a furnace through which an oil flows and is heated. Color: It is an indication of the thoroughness of the refining process. This is determined by Saybolt Chromometer or by Lovibond Tintometer. Saybolt color of petroleum products test is used for quality control and product identification purposes on refined products having as ASTM color of 0.5 or less. ASTM color of petroleum products applies to products having ASTM color of 0.5 or darker, including lubricating oils, heating oils, and diesel fuel oils. Pale

= 4.5 ASTM color or lighter

Red

= Darker than 4.5 ASTM

Dark

= Darker than 8.0 ASTM

Compressed Natural Gas: 1. Natural gas that has been compressed under high pressures (typically between 3000 and 3600 psi and held in a container;

expands when released for use as a fuel. 2. Natural gas compressed to a volume and density that is practical as a portable fuel supply (even when compressed, natural gas is not a liquid). 3. Natural gas in its gaseous state that has been compressed. 4. Natural gas that is under pressure. The pressure reduces the volume occupied for the gas so it can be contained in a smaller vessel. Compressibility: The volume change of a material when pressure is applied. Compressibility Factor (Z): 1. The fractional reduction in the volume of a substance with applied pressure. The compressibility factor is a measure of the compressibility of a gas, Z and used as a multiplier to adapt the ideal gas law for non-ideal gases. 2. The ratio of the actual volume of a gas divided by the volume that would be predicted by the ideal gas law, usually referred to as the “Z” factor.

Z

pV RT

where p is the pressure, V is the volume, R is the universal gas constant, and T is the absolute temperature. Compressible fluid: A fluid in which the density changes with applied pressure. The compressibility of liquids is negligible in comparison with gases and vapors. The isothermal compressibility of a gas is the change in volume per unit volume or density for a unit change in applied pressure given as:

c=

−1  ∂V  −1  ∂r  =     r  ∂p  T V  ∂p  T

Isothermal compressibility coefficients are frequently used in oil and gas engineering, transient fluid flow calculation, and in the determination of the physical properties of substances. Compression Ratio: Is a measure of the amount of compression that takes place in an engine’s cylinder. The ratio of volumes in an internal combustion cylinder when the piston is at the bottom of the stroke to that when the piston is at the top of the stroke, giving a measure of how much the air or air/fuel mixture is compressed in the compression stroke. CP =

V1 Volume when pistonis @ bottom of stroke = n is @ top of stroke V2 Volume when piston

Compressor: 1. A device that increases the pressure of gas. Commonly used as a production rate increaser by increasing the gas pressure delivered from low-pressure

852  Petroleum Refining Design and Application Handbook Volume 2 gas wells to enter the pipeline. The intake into the compressor lowers the wellhead pressure, creating a larger drawdown. 2. An engine used to increase the pressure of natural gas so that it will flow more easily through a pipeline. 3. Thermodynamic machine that increases the pressure of a gas flow using mechanical energy. 4. A mechanical device used to raise the pressure of a gas. Compressors can be of three types: axial, centrifugal or reciprocating. The usual means of providing the required power are electrical motors, steam turbines or gas turbines. Compressor Station: 1. A booster station associated with a gas pipeline that uses compressors to increase the gas pressure. When gas turbines are used to provide compressor power, stations can use some of the gas moving through the line as fuel. 2. Stations located along natural gas pipelines that recompress gas to ensure an even flow. Condensation: Reaction in which aromatic ring structures combine to form ring structures larger than the reactants. Condensate: 1. The relatively small amount of liquid hydrocarbon typically C4,s through naphtha or gas oil that gets produced in the oil patch with unassociated gas. 2. The liquid formed when a vapor cools. Conradson Carbon: A test used to determine the amount of carbon residue left after the evaporation and pyrolysis of an oil under specified conditions. Expressed as weight percentage; ASTM D-189. Conradson Carbon Residue (CCR): Results from ASTM test D189. It measures the coke-forming tendencies of oil. It is determined by destructive distillation of a sample to elemental carbon (coke residue), in the absence of air, expressed as the weight percentage of the original sample. A related measure of the carbon residue is called Ramsbottom carbon residue. A crude oil with a high CCR has a low value as refinery feedstock. Conradson Carbon Residue (ASTM D 1289): ASTM D 4530 microcarbon residue: This procedure determines the carbon residue left after evaporation and pyrolysis of an oil sample under prescribed conditions and is a rough indicator of oil’s relative coke-forming tendency or contamination of a lighter distillate fraction with a heavier distillate fraction or residue. Carbon residue and atomic H – to – C ratio is correlated by: H/C = 171–0.015CR (conradson)

Consequence: 1. Is the ultimate harm that may occur due to a credible hazard release scenario. 2. The direct undesirable result of an accident sequence usually involving a fire, explosion, or release of toxic material. Consequence description may include estimates of the effects of an accident in terms of factors such as health impacts, physical destruction, environmental damage, business interruption, and public reaction of company prestige (See Figure 6). Continuous Catalytic Reforming (CCR) process: Continuous catalytic reforming process occurs where the catalyst is circulated through the reactors and a regeneration step, analogous to catalytic cracking processes. Continuous stirred tank reactor (CSTR): 1. A type of idealized chemical reactor used to contain a chemical reaction in which liquid reactants continuously flow into the reactor and products continuously removed such that there is no accumulation within the reactor. By assuming perfect mixing of the reactants within the reactor, by using a stirrer/mixer, the composition of the material is therefore assumed to be the same as the composition at all points within the reactor. 2. Reactors that are characterized by a continuous flow of reactants into and a continuous flow of products from the reaction system. Examples are the plug flow reactor and the continuous stirred flow reactor. Control of Major Accident Hazards (COMAH): The legislation requires that businesses holding more than threshold quantities of named dangerous substances “Take all necessary measures to prevent major accidents involving dangerous substances. Limit the consequences to people and the environment of any major accidents which do occur.” Plant designers need to consider whether their proposed plant will be covered by this legislation at the earliest stages. Control of Substances Hazardous to Health (COSHH): The legislation that requires risk assessment

Emissions

Crude oil Hazard

Pollution

Reputation Resulting event or chain of events

Figure 6 A consequence.

Glossary of Petroleum and Technical Terminology  853 and control of hazards associated with all chemicals and used in a business which has potentially hazardous properties. Consideration of the properties of chemicals used as feedstock, intermediates, and products, is a basic part of plant design. Inherently safe design requires us to consider these issues at the earliest stage.

Adding acid or oxygen is a good way for this to occur. The main way of slowing corrosion down (inhibition) is by providing an impermeable coating to stop the chemical reaction from occurring in the first place or by providing a more easily attacked metal that will be consumed first (a “sacrificial anode”).

Conversion: 1. A measure of the completeness of a chemical reaction. It is often presented as the fraction of a particular reactant consumed by the chemical reaction. The conversion per pass is a measure of the limiting reactant that is converted in a chemical reactor and recycled for combination with fresh reactant feed. Not all reactions are complete within the reactor, and in many cases, unreacted reactants are separated from products and recycled for further reaction. 2. Typically, the fraction of a feedstock converted to gasoline and lighter components.

Corrosion Inhibitor: 1. A chemical substance or combination of substances that when present in the environment, prevents or reduces corrosion. 2. Substance that slows the rate of corrosion.

Correlation Index (CI): The U.S. Bureau of Mines factor for evaluating individual fractions from crude oil. The CI scale is based upon straight chain hydrocarbons having a CI value of 0 and benzene having a value of 100. The lower the CI value, the greater the concentrations of paraffin hydrocarbons in the fraction, and the higher the CI value, the greater the concentrations of naphthenes and aromatics. CI is an indication of the hydrocarbon to carbon ratio and the aromaticity of the sample. CI is expressed by:

K d where TB Sp.Gr

CI =

87, 552 + 473.7Sp.Gr − 456.8 TB

CI =

48640 + 473.7d − 456.8 K

= average boiling point (K = °C + 273.15) = specific gravity at 15 °C/15 °C = mean average boiling point, °R = specific gravity at 60°F

Corrosion: 1. The deteriorating chemical reaction of a metal with the fluids with which it is in contact. 2. The gradual decomposition or destruction of a material by chemical action, often due to an electrochemical reaction. Corrosion may be caused by (a) stray current electrolysis; (b) galvanic corrosion caused by dissimilar metals, (c) differential-concentration cells. Corrosion starts at the surface of a material and proceeds inward. Corrosion Inhibition: Corrosion can be defined as the unwanted production of a salt from a metal.

Corrosive Gas: 1. A gas that attacks metal or other specified targets. Most commonly CO2 and H2S. Usually in association with water or water vapor. Oxygen can be described as a corrosive gas in some cases. 2. In water, dissolved, oxygen reacts readily with metals at the anode of a corrosion cell, accelerating the rate of corrosion until a film of oxidation products such as rust forms. At the cathode where hydrogen gas may form a coating on it and therefore, slows the corrosion rate, oxygen reacts rapidly with hydrogen gas forming water and again increases the rate of corrosion. Cracking: The breaking down of higher molecular weight hydrocarbons to lighter components by the application of heat. Cracking in the presence of a suitable catalyst produces an improvement in yield and quality over simple thermal cracking. Cracking Correction: Correction to a laboratory distillation to account for the lowering of the recorded temperatures because of thermal cracking of the sample in the distillation flask. Cracking occurs for most petroleum stocks at temperatures greater than about 650°F (344°C) at atmospheric pressure. Cracked Stock: A petroleum stock that has been produced in a cracking operation, either catalytic or thermal. Cracked stocks contain hydrogen deficient compounds such as olefins (CnH2n) and aromatics (CnH2n-6). Critical Point: The temperature and pressure at which a component or mixture of components enter a dense phase, being neither liquid nor vapor. Critical Pressure: The vapor pressure at the critical temperature. Critical Temperature: The temperature above which a component cannot be liquefied. For mixtures, the temperature above which all of the mixture cannot be liquefied.

854  Petroleum Refining Design and Application Handbook Volume 2 Crude Assay Distillation: See Fifteen-five (15/5) distillation. Crude Chemistry: Fundamentally, crude oil consists of 84–87 wt % carbon, 11–14% hydrogen, 0–3 wt % sulfur, 0–2 wt % oxygen, 0–0.6 wt % nitrogen and metals ranging from 0–100 ppm. Understanding thoroughly the fundamentals of crude chemistry is very important in various refining processes. The existence of compounds with various functional groups and their dominance or reduction in various refinery products is what is essentially targeted in various chemical and physical processes in the refinery. Based on chemical analysis and existence of various functional groups, refinery crude can be broadly categorized into about nine categories: 1. Paraffins, CnH2n+2, CH4, C2H6, C3H8

4. Aromatics, 7. Oxygen containing CnH2n-6, C6H6, compounds, C7H8, C8H10 R-OH, CH3OH, C6H5OH

5. Naphthalene 2. Olefins, CnH2n. C2H4, C3H6

8. Resins

3. Naphthenes, 6. Organic sulfur CnH2n, C6H12, compounds, RSH, CH3SH,

9. Asphaltenes

R − S − R′

Crude and Crude Oil: 1. A range of principally carbon-hydrogen chain compounds with generally straight carbon chain lengths of C1 (methane) to C60+, compounds boiling higher than 2000°F (1094°C). The straight-chain materials are alkanes. 2. Oil as it comes from the well; unrefined petroleum. 3. The petroleum liquids as they come from the ground; formed from animal and vegetable material that is collected at the bottom of ancient seas. 4. Tarry group consisting of mixed carbon compounds with a highly variable composition. 5. A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface-separating facilities. Depending upon the characteristics of the crude stream, it may also include the following: • Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being removed from oil well (casing head) gas

in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included. • Small amounts of non-hydrocarbons produced from oil, such as sulfur and various metals. • Drip gases and liquid hydrocarbons produced from tar sands, gilsonite and oil shale. • Liquid produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide range of petroleum products, including heating oils; gasoline, diesel, and jet fuels, lubricants, asphalt; ethane, propane and butane and many other products used for their energy or chemical content. The basic types of crudes are asphalt, naphthenic, or paraffinic depending on the relative proportion of these types of hydrocarbons present. Crude Oil Assay: Is a precise and detailed analysis on carefully selected samples of crude thoroughly representative of average production quality. It helps to assess the potential sales value of a new crude oil and to plan for its most effective utilization. Numerous important feed and product characterization properties in refinery engineering include: 1. API gravity 2. Watson Chracterization factor 3. Viscosity 4. Sulfur content 5. True boiling point (TBP) curve 6. Pour point 7. Flash and fire point 8. ASTM distillation curve 9. Octane number Crude Oil Losses: This represents the volume of crude oil reported by petroleum refineries as being lost in their operations. These losses are due to spills, contamination, fires, etc., as opposed to refinery processing losses. Crude Oil Production: The volume of crude oil produced from oil reservoirs during given periods of time. The amount of such production for a given period is measured as volumes delivered from lease storage tanks (i.e., the point of custody transfer) to pipelines, trucks, or other media for transport to refineries

Glossary of Petroleum and Technical Terminology  855 or terminals with adjustments for (1) net differences between opening and closing lease inventories, and (2) basic sediment and water (BS & W). Crude Oil Qualities: This refers to two properties of crude oil, the sulfur content and API gravity, which affect processing complexity and product characteristics. Cryogenics: The production and application of lowtemperature phenomena. The cryogenic temperature range is usually from -238°F (-150°C) to absolute zero -460°F (-273°C), the temperature at which molecular motion essentially stops. The most important commercial application or cryogenic gas liquefaction technique is the storage, transportation and regasification of LNG. Cryogenic Liquid or Cryogenics: Cryogenic liquids are liquefied gases that are kept in their liquid state at very low temperatures and have a normal boiling point below -238°F (-150°C). All cryogenic liquids are gases at normal temperatures and pressures. These liquids include methane (CH4), oxygen (O2), nitrogen (N2), helium (He) and hydrogen (H2). Cryogens normally are stored at low pressures. Cryogenic Recovery: Cryogenic recovery processes are carried out at temperatures lower than -150°F (-101°C). The low temperatures allow the plant to recover over 90% of the ethane in the natural gas. Most new gas processing plants use cryogenic recovery technology. CSB: An acronym for Chemical Safety and Hazard Investigation Board. An agency of the U.S. government charted to investigate chemical industry incidents, determine their root cause, and publish their findings to prevent similar incidents occurring. Cut: That portion of crude oil boiling within certain temperature limits. Usually, the limits are on a crude assay true boiling point (TBP) basis. Cut Point Temperature, Cut Points: A temperature limit of a cut, usually on a true boiling point basis, although ASTM distillation cut point is not uncommon. The boiling point curve most commonly used to define cut points is the true boiling point (TBP) at one atmosphere of pressure. Cut Point Ranges: A series of cut point temperatures are defined for a petroleum stock. The cut point ranges are the temperature differences between adjacent cut point temperatures. When developing petroleum pseudo-components for a petroleum stock, cut

point ranges must be defined that include the total boiling point range of the stock. Cutter Stock: Diluent added to residue to meet residual fuel specifications for viscosity and perhaps sulfur content. Typically cracked gas oil. Cycloparaffin: A paraffin molecule with a ring structure. Cycle Oil, Cycle Stock: An oil stock, containing a hydrogen deficient compound that was produced in a thermal or catalytic cracking operation. Cyclization: Chemical reaction in which non-ring structure paraffin or olefins are converted into ring structures. Cyclo-olefins: Unsaturated ring structure with one or two double bonds in the ring. Darcy-Weisbach equation: An equation used in fluid mechanics to determine the pressure or head loss due to friction within a straight length of pipe for a flowing fluid. The frictional pressure drop, Δpf (psi) is expressed by

 L  rv 2 ∆p f = f D    d 2 where

   tw  fD =  2   rv   2 

In the form of frictional head loss, hf (ft) is:

 L  v2 h f = fD    d  2g where, τw is the shear stress, fD is the Darcy friction factor, dimensionless (fD = 4fF), fF is the fanning friction factor, L and d and the pipe length (ft) and inside diameter (ft), v is the average velocity of the fluid (ft), ρ is the fluid density (lbm/ft3) and g is the acceleration due to gravity (ft/s2). It is known as the Darcy-Weisbach or Moody friction factor, whose value depends on the nature of the flow and surface roughness of the pipe. This Darcy friction factor is four times the Fanning friction factor (i.e., fD = 4fF). The value of the friction factor can be determined from various empirical equations and published charts such as the Moody diagram (See Figure 7).

856  Petroleum Refining Design and Application Handbook Volume 2 0.10 0.09 Critical zone

Transition zone

Complete turbulence rough pipes

0.05 0.04

0.06

0.03

0.05

ν2 ) 2g

0.015 0.01 0.008 0.006

0.03

Recr

Friction factor f = hL/(L/D) (

w flow inar Lam = 64 f Re

0.04

0.02

0.004 0.003 0.002 0.0015

0.02

Sm

0.015

oo

th

0.001 0.0008 0.0006 0.0004 0.0003 0.0002 0.00015 0.0001

pip

es

0.01 0.009 0.008

ε D

0.07

Laminar flow

103

2

3 4 5 6 8 104

2

3 4 5 6 8 105

2

3 4 5 6 8 106

2

3 4 5 6 8 107

2

Relative roughness

0.08

0.00006 0.00004 0.00003 0.00002 0.000015 0.00001

3 4 5 6 8 108

Dρν νD Reynolds number, Re = 1 (ν in ft/s, D in ft., ν1 in ft2/s) = ν µe

Figure 7 Moody diagram.

An empirical equation known as the ColebrookWhite equation has been proposed for calculating the friction factor in the turbulent flow:

 e 1 2.51  = −2 log10  +  fD  3.7 D Re f D  where D = pipe inside diameter, in e = absolute pipe roughness, in Re = Reynolds number, dimensionless The term fD (L/d) may be substituted with a head loss coefficient K (also known as the resistance coefficient) and then becomes

hf = K

v2 2g

The head loss in a straight piece of pipe is represented as a multiple of the velocity head v2/2g. Following a similar analysis, we can state that the pressure drop through a valve or fitting can be represented by K(v2/2g), where the coefficient K is specific to the valve and fitting. Note that this method is only applicable to turbulent flow through pipe fittings and valves. Recently K is presented by Hooper’s 2-K method and Darby’s 3 K- method.

DAO - Deasphalted oil: The raffinate product from the propane deasphalting unit. D1160: ASTM laboratory distillation method for high-boiling streams. The D1160 is performed under vacuum conditions with 10 mm Hg being the most common pressure used for the test. D1160 data are normally reported at a 760 mm Hg basis. D2887: ASTM simulated distillation method for high-boiling streams. The D2887 has an upper limit of 1000°F (538°C) and the temperatures are reported versus weight percent distilled. A normal paraffin standard is used to convert the chromatographic results to a boiling point curve. D3710: ASTM simulated distillation method for gasoline and light naphthas. D3710 data are reported on a volume basis. D86: ASTM laboratory distillation method conducted at atmospheric pressure for streams boiling below approximately 700°F (371°C). The D86 is the most commonly used laboratory distillation for petroleum stocks. Deasphalting: Process for removing asphalt from petroleum fractions, such as reduced crude.

Glossary of Petroleum and Technical Terminology  857 Debottlenecking: 1. Increasing production capacity of existing facilities through the modification of existing equipment to remove throughput restrictions. Debottlenecking generally increases capacity for a fraction of the cost of building new facilities. 2. The process of increasing the production capacity of existing facilities through the modification of existing equipment to remove throughput restrictions. 3. A program, typically in surface facilities and lines to remove pressure drop causing flow restrictions. Debutanizer: A column that removes n-butanes (nC4H10) and lighter in the top product. Decant Oil: The bottom stream from the FCC unit distillation tower after catalyst has been separated from it. Decanted Water: Insoluble water that is drawn from a drum containing condensed hydrocarbons and water. Decoking: The process of removing coke from catalysts in a catalytic cracker, catalytic reformer, hydrocracker or hydrotreaters. Usually heated air will oxidize the coke to carbon monoxide or carbon dioxide. Deethanizer: A column that removes ethane (C2H6) and lighter in the top product. Deflagration (i.e., “to burn down”): Is a term describing subsonic combustion propagation through heat transfer, hot burning material heats the next layer of cold material and ignites it. Most “fire” found in daily life, from flames to explosions, is deflagration. Deflagration is different from detonation, which propagates supersonically through shock waves. Delayed Coker: A process unit in which residue is cooked until it cracks to coke and light products. Delayed Coking: 1. A semi-continuous thermal process for the conversion of heavy stock to lighter material. The method involves pre-heating the feedstock in a pipe still, discharging into large insulated coke drums and retaining there for a particular length of time for cracking to occur. Gas, gasoline and gas oil are recovered as overhead products and finally coke is removed. 2. A process by which heavier crude oil fractions can be thermally decomposed under conditions of elevated temperatures and low pressure to produce a mixture of lighter oils and petroleum coke. The light oils can be processed further in other refinery units to meet product specifications. The coke can be used either as a fuel

or in other applications such as the manufacturing of steel or aluminum. Dehydrogenation: A chemical reaction in which a compound loses bonded hydrogen. Deisobutanizer: A column that removes isobutane (iC4H10) and lighter in the top product. Demethanizer: A column that removes methane (CH4) and lighter in the top product. Density: The density of crude oil and petroleum fractions is usually specified in °API, specific gravity or kilograms per cubic meter (kg/m3). The numerical values of specific gravity and kg/m3 are equal; that is a fraction with a specific gravity of 0.873 has a density of 0.873 kg/m3. The API scale runs opposite to that of specific gravity, with larger values for less dense materials and smaller values for more dense fractions (water = 10°API). By definition, °API is always 60°F (15.6°C) for a liquid. Depentanizer: A column that removes n-pentane (nC5H12) and lighter in the top product. Depropanizer: A column that removes propane (C3H8) and lighter in the top product. Desalting: A process that removes chlorides and other inorganic salts from crude oil by injecting water and applying an electrostatic field to force the salt into the aqueous phase. Desiccant: Absorbent or adsorbent, liquid or solid that removes water or water vapor from an air stream. Desiccant Drying: The use of drying agent to remove moisture from a stream of oil or gas. In certain product pipelines, great effort is made to remove all the water vapor before putting the line into service. To accomplish this desiccant dried air or an inert gas is pumped through the line to absorb the moisture that may be present even in the ambient air in the line. Desiccation: The process of drying and removing the moisture within a material. It involves the use of a drying agent known as a desiccant. Desiccants that function by adsorption of moisture include silica gel and activated alumina, while chemical desiccants that function by the reaction with water to form hydrates include calcium chloride and solid sodium hydroxide. A desiccator is a container used for drying substances or for keeping them dry free of moisture. Laboratory desiccators are made of glass and contain a drying agent such as silica gel.

858  Petroleum Refining Design and Application Handbook Volume 2 Design Codes (design standards): Published standards required for equipment and working practices within the chemical and process industries that represent good practice and define the level of standard of design. Developed and evolved over many years and based on tried and tested practices. There are a number of national standards organizations and institutions that provide published standards for design, materials, fabrication, testing of processes and equipment. These include the American Petroleum Institute (API), the American National Standards Institute (ANSI), the American Society of Mechanical Engineers (ASME), the American Society for Testing and Materials (ASTM), the American Iron and Steel Institute (AISI) and the British Standards Institute (BSI). Desorption: The release of materials that have been absorbed or adsorbed in or onto a formation. Desulfurization: The removal of sulfur, from molten metals, petroleum oil or flue gases. Petroleum desulfurization is a process that removes sulfur and its compounds from various streams during the refining process. Desulfurization processes include catalytic hydrotreating and other chemical/physical processes such as adsorption. Desulfurization processes vary based on the type of stream treated (e.g., naphtha, distillate, heavy gas oil, etc.) and the amount of sulfur removed (e.g., sulfur reduction to 10 ppm). See also Catalytic Hydrotreating. Desuperheating zone: A section of a distillation/ fractionating column where a superheated vapor is cooled and some liquid is condensed. FCC main fractionators have a desuperheating zone. Detonation (“to thunder down”): Is a type of combustion involving a supersonic exothermic front accelerating through a medium that eventually drives a shock front propagating directly in front of it. Detonations occur in both conventional solid and liquid explosives, as well as in reactive gases. The velocity of detonation in solid and liquid explosives is much higher than that in gaseous ones, which allows the wave system to be observed with greater detail. An extraordinary variety of fuels may occur as gases, droplet fogs, or dust suspensions. Oxidants include halogens, ozone, hydrogen peroxide and oxides of nitrogen. Gaseous detonations are often associated with a mixture of fuel and oxidant in a composition somewhat below conventional flammability ratios. They happen most often in confined systems, but they sometimes occur in large vapor clouds. Other materials, such as

acetylene, ozone and hydrogen peroxide are detonable in the absence of oxygen. See also Knocking. Dewaxing: The removal of wax from lubricating oils, either by chilling and filtering solvent extraction, or selective hydrocracking. Dew Point: 1. A vapor at its dew point temperature is on the verge of starting to condense to a liquid. Cool the vapor by 1°F, or raise its pressure by 1 psi and it will form drops of liquid. Air at 100% relative humidity is at its dew point temperature. Cool it by 1°F and it starts to rain. 2. The temperature and pressure at which the first drop of liquid will condense for a component or mixture of components. 3. The temperature at a given pressure at which a vapor will form a first drop of liquid on the subtraction of heat. Further cooling of the liquid at its dew point results in condensation of part or all the vapors as a liquid. 4. The temperature at which vaporized materials start to condense into liquid form. 5. The temperature at which liquids begin to condense from the vapor phase in a gas stream. See also Bubble point. Diene: Same as diolefin. Diesel: 1. An internal combustion engine in which ignition occurs by injecting fuel in a cylinder where air has been compressed and is at very high temperature, causing self-ignition. 2. Distillate fuel used in a diesel engine. See the Diesel engine. Diesel Fuel: A fuel produced for diesel engines with typical ASTM 86 boiling point range of 450–675 °F (233–358°C). Diesel Index (DI): A measure of the ignition quality of a diesel fuel. Diesel index is defined as

DI =

(°API)( AnilinePoint ) 100

The higher the diesel index, the more satisfactory the ignition quality of the fuel. By means of correlations unique to each crude and manufacturing process, this quality can be used to predict the cetane number (if no standardized test for the latter is available). Diolefin: CnH2n: Paraffin-type molecule except that it is missing hydrogen atoms causing it to have two double bonds somewhere along the chains. DIPE: Di-isopropyl ether. An oxygenate used in motor fuels. Disposition: the components of petroleum disposition are stock change, crude oil losses, refinery

Glossary of Petroleum and Technical Terminology  859 inputs, exports and products supplied for domestic consumption. Distillate Fuel Oil: A general classification for one of the petroleum fractions produced in conventional distillation operations. It includes diesel fuels and fuel oils. Products known as No. 1, No. 2, and No. 4 diesel fuel are used on highway diesel engines, such as those in trucks and automobiles, as well as off-highway engines, such as those in railroad locomotives and agricultural machinery. Products known as No.1, No. 2, and No. 4 fuel oils are used primarily for space heating and electric power generation. No. 1 Distillate. A light petroleum distillate that can be used as either a diesel fuel or a fuel oil. No. 1 Diesel Fuel. A light distillate fuel oil that has distillation temperatures of 550°F (288°C) at the 90% point and meets the specifications defined in ASTM Specification D 975. It is used in high-speed diesel engines generally operated under frequent speed and load changes, such as those in city buses and similar vehicles. No. 1 Fuel Oil. A light distillate fuel oil that has distillation temperatures of 400°F (204°C) at the 10 percent recovery point and 550°F (288°C) at the 90% point and meets the specifications defined in ASTM Specifications D 396. It is used primarily as fuel for portable outdoor stoves and portable outdoor heaters. No. 2 Distillate: A petroleum distillate that can be used as either a diesel fuel or a fuel oil. No. 2 Diesel Fuel: A fuel that has distillation temperature of 500°F (260°C) at the 10% recovery point and 640°F (338°C) at the 90% recovery point and meets the specifications defined in ASTM Specification D 975. It is used in high-speed diesel engines that are generally operated under uniform speed and load conditions, such as those in railroad locomotives, trucks and automobiles. Low Sulfur No. 2 Diesel Fuel. No. 2 diesel fuel that has a sulfur level no higher than 0.05% by weight. It is used primarily in motor vehicle diesel engines for onhighway use. High Sulfur No. 2. Diesel Fuel. No. 2 diesel fuel that has sulfur level above 0.05% by weight. No. 2 Fuel Oil (Heating Oil): A distillate fuel oil that has distillation temperatures of 400°F (204°C) at the 10% recovery point and 640°F (338°C) at the 90% recovery point and meets the specifications defined in ASTM Specification D 396. It is used in atomizing type burners for domestic heating or for moderate capacity commercial/industrial burner units.

No. 4 Fuel. A distillate fuel oil made by blending distillate fuel oil and residual fuel oil stocks. It conforms with ASTM Specification D 396 or Federal Specification VV – F- 815C and is used extensively in industrial plants and in commercial burner installations that are not equipped with preheating facilities. It also includes No. 4 diesel fuel used for low- and medium-speed diesel engines and conforms to ASTM Specification D975. No. 4 Diesel Fuel. See No. 4 Fuel. No. 4 Fuel Oil. See No. 4 Fuel. Distillate: 1. The liquid obtained by condensing the vapor given off by a boiling liquid. 2. Any stream except the bottoms coming from a fractionator. 3. The products or streams in the light gas oil range such as straight run light gas oil, cat. cracked light gas oil, heating oil or diesel. Distillation: Same as fractionation. A separation process that results in separated products with different boiling ranges. Distillation is carried out in a way that the materials being separated are not subjected to conditions that would cause them to crack or otherwise decompose or chemically change. It is a physical process. Distillation Column: A tall vertical cylindrical vessel used for the process of distillation. Hot vapor rises up the column, which is brought into intimate contact with cooled liquid descending on stages or trays for a sufficient period of time so as to reach equilibrium between the vapor and the liquid. The vapor rises up from the tray below through perforations in the tray, and the liquid on the tray flows over a weir to the tray below. In this way, the more volatile component increases in concentration progressively up the column. In continuous distillation, fresh feed is admitted at the tray corresponding to the same composition. Below the feed point, the section of column is known as the stripping section, while above is referred to as the rectifying section. A reboiler heat exchanger is used to boil the bottom product and produce vapor for the column. A condenser is used to condense some or all of the vapor from the top of the column. A small portion of liquid is returned to the column as reflux. The height of the column is an indication of the ease or difficulty of separation. For example, an ethylene splitter in a refinery used to separate ethylene from ethane, which have close boiling points, requires many trays and the column is very tall. The width of the column is an indication of the internal vapor and liquid rates.

860  Petroleum Refining Design and Application Handbook Volume 2 Distillation Curves: In addition to True Boiling Point (TBP) or good fractionation distillations, there are at least three other major types of distillation curves or ways of relating vapor temperature and percentage vaporized: (a) equilibrium flash vaporization, (b) ASTM or non-fractionating distillations, and (c) Hempel or semi-fractionating distillations. Distillation Range: See boiling range. Distillation Train: A sequence of distillation columns used to separate components from a multicomponent feed. Each column is required to perform a particular separation of either a pure component or a cut between two components. For example, in the separation of four components ABCD in a mixture in which A is the most volatile and D is the least, then the five possible separation sequences requiring three columns are: Separation

Column 1

Column 2

Column 3

1

A:BCD

B:CD

C:D

2

A:BCD

BC:D

B:C

3

AB:CD

A:B

C:D

4

ABC:D

A:BC

B:C

5

ABC:D

AB:C

A:B

(2n − 2)!

n !(n − 1)!

Where N is the number of sequences and n is the number of components: Components (n)

4

5

6

7

Sequences (N)

5

14 42 132

A system of dividing plant or process control into several areas of responsibility, each managed by its own Central Processing Unit, in which the whole is interconnected to form a single entity usually by communication buses of various kinds. Distributor: A device in a vessel that disperses either liquid or vapor to promote better circulation. Doctor Test: A method for determining the presence of mercaptan sulfur petroleum products. This test is used for products in which a “sweet” odor is desirable for commercial reasons, especially naphtha; ASTM D-484. Dow Fire and Explosion Index (F & EI): A method (developed by Dow Chemical Company) for ranking the relative fire and explosion risk associated with a process. Analysts calculate various hazard and explosion indexes using material characteristics and process data.

Where it is required to separate a larger number of components, the number of possible separation sequences becomes much larger according to the relationship

N=

Distributed control systems consist of subsystems that are functionally integrated but may be physically separated and remotely located from one another. Distributed control systems generally have at least one shared function within the system. This may be the controller, the communication link or the display device. All three of these functions may be shared.

8

9

10

429

1430 4862

Distributed Component: A component that appears in both the top and bottom products from a distillation/fractionating column separating zone. Distributed Control System: A system which divides process control functions into specific areas interconnected by communications (normally data highways) to form a single entity. It is characterized by digital controllers and typically by central operation interfaces.

Downcomer: A device to direct the liquid from a distillation column tray to the next lower distillation tray. Draw, Side Draw: A product stream withdrawn from a distillation column at a location above the bottom tray and below the top tray. Draws may be vapor or liquid phase. Dropping Point of Lubricating Greases: Dropping points are used for identification and quality control purposes, and can be an identification of the highest temperature of utility for some applications. This is the temperature at which grease passes from a semisolid to a liquid state under prescribed conditions. Dry Gas: All C1 to C3 material whether associated with a crude or produced as a by-product of refinery processing. Convention often includes hydrogen in dry gas yields. Effective Cut Points: Cut points that can be considered a clean cut, ignoring any tail ends. Emergency: A condition of danger that requires immediate action.

Glossary of Petroleum and Technical Terminology  861 Emergency Isolation Valve (EIV): A valve that, in event of fire, rupture, or loss of containment, is used to stop the release of flammable or combustible liquids, combustible gas, or potentially toxic material. An EIV can be either hand-operated or power-operated (air, hydraulic, or electrical actuation). Emergency Shutdown (ESD): A method to rapidly cease the operation of a process and isolate it from incoming and outgoing connections or flows to reduce the likelihood of an unwanted event from continuing or occurring. Critical valves shut to isolate sections of the process. Other valves may be opened to depressurize vessels or rapidly discharge contents of reactors to quench tanks. Emergency shutdowns may occur due to changes in process conditions causing unstable or unsafe operating conditions, a failure in the control system, operator intervention causing unsafe conditions, plant and pipe failure or some other external event such as an electrical storm or natural catastrophes like earthquakes or coastal flooding. Emulsion: A colloidal suspension of one liquid dispersed within another. The dispersed phase has droplet sizes usually less than 1 mm. Surfactants or emulsifiers are surface-active agents and used to stabilize emulsions. In the offshore oil industry, emulsions form at the interface of water and oil in crude oil gravity separators. Sufficient hold-up time is used to separate the emulsion, or alternatively surfaceactive agents are used to encourage separation. Endothermic reaction: 1. A chemical reaction that absorbs heat from its surroundings in order for the reaction to proceed. Such reactions have a positive enthalpy change and therefore do not occur spontaneously. 2. A reaction in which heat must be added to maintain reactants and products at a constant temperature. E85: Fuel containing a blend of 70 to 85% ethanol. End Point (final boiling point): 1. The highest boiling point recorded for a laboratory distillation. Usually, there is some residual material in the laboratory still, and the end point is not the highest boiling point material in the mixture being distilled. 2. The lowest temperature at which virtually 100% of petroleum product will boil off to vapor form. Energy: The capacity or ability of a system to do work. It may be identified by type as being kinetic, potential, internal, and flow or by source such as electric, chemical, mechanical, nuclear, biological, solar, etc. Energy

can be neither created nor destroyed, but converted from one form to another. It can be stored as potential energy, nuclear, and chemical energy, whereas kinetic energy is the energy in motion of a body defined as the work that is done in bringing the body to rest. The internal energy is the sum of the potential energy and kinetic energy of the atoms and molecules in the body. Energy as the units, Btu, cal, Joules. Energy Balance: 1. An accounting of the energy inputs and outputs to a process or part of a process, which is separated from the surroundings by an imaginary boundary. All energy forms are included in which the energy input across the boundary must equal the energy output plus any accumulation within the defined boundary. When the conditions are steady and unchanging with time, the energy input is equal to the energy output. The most important energy forms in most processes are kinetic energy, potential energy, enthalpy, heat and work. Electrical energy is included in electrochemical processes and chemical energy is in processes involving chemical reactions that occur in various reactor types (e.g., batch, continuous stirred tank, plug flow, fixed and catalytic reactors). 2. Summation of the energy entering a process and the summation of the energy leaving a process. They must equal for a steady-state process. Energy Management: Is the planning and operation of energy production and energy consumption units. Objectives are resource conservation, climate protection and cost savings, while the users have permanent access to the energy they need. Energy management is the proactive, organized and systematic coordination of procurement, conversion, distribution and use of energy to meet the requirements, taking into account the environmental and economic objectives. It is also the solution for electric power producers to reduce emissions and improve efficiency and availability. Energy management requires reducing NOx and greenhouse gas emissions, improving fuel efficiency and reducing SCR operating costs, and streamlining the detection, diagnosis and remediation of plant reliability, capacity and efficiency problems. Energy management programs incorporate energy policies, benchmarking, local and corporate goals, types of energy audits and assessments, reporting systems and integration of energy efficiency elements into engineering procedures and purchasing protocols. Pinch analysis is a tool that is employed in energy management of chemical facilities and is a methodology

862  Petroleum Refining Design and Application Handbook Volume 2 for minimizing energy consumption of chemical processes by calculating thermodynamically feasible energy targets (or minimum energy consumption) and achieving them by optimizing heat recovery systems, energy supply methods and processing operating conditions. It is also known as process integration, heat integration, energy integration or pinch technology (See Process Integration). Engler Distillation: A standard test for determining the volatility characteristics by measuring the percent distilled at various specified temperature (see ASTM D86). Engine knocking (knock, detonation, spark knocking, pinging, or pinking): Spark ignition in internal combustion engines occur when combustion of the air/fuel mixture in the cylinder does not start off correctly in response to ignition by the spark plug, but one or more pockets of air/fuel mixture explode outside the envelope of the normal combustion front. The fuel-air charge is meant to be ignited by the spark plug only, and at a precise point in the piston’s stroke. Knock occurs when the peak of the combustion process no longer occurs at the optimum moment for the four-stroke cycle. The shock wave creates the characteristic metallic “pinging” sound, and cylinder pressure increases dramatically. Effects of engine knocking range from inconsequential to completely destructive. See also Knocking.

will be conducted. Greenfield LNG project development involves a wide range of design, engineering, fabrication and construction work far beyond the capabilities of a single contractor. Therefore, an LNG project developer divides the work into a number of segments, each one being the subject of an engineering, procurement and construction (EPC) contract. 3. Contract between the owner of a liquefaction plant and an engineering company for the project development and erection. See Front-End Engineering and Design Contract. Enthalpy (H): The thermal energy of a substance or system with respect to an arbitrary reference point. The enthalpy of a substance is the sum of the internal energy and flow of energy, which is the product of the pressure and specific volume. H= U + pV The reference point for gases is 273K and for chemical reactions is 298K. Enthalpy balance: A form of energy accounting for a process in which the stream energies to and from the process are expressed as enthalpies. At steady state, the total enthalpy into a process is equal to the total enthalpy out. Where there is an inequality, there is either a loss or an accumulation of material with an associated loss increase in enthalpy. An enthalpy balance is used to determine the amount of heat that will be generated in the process or that needs to be removed to ensure that the process operates safely and to specification.

Engineering line diagram (ELD): A diagrammatic representation of a process. Also referred to as engineering flow diagram. It features all process equipment and piping that is required for start-up and shutdown, emergency and normal operation of the plant. It also includes insulation requirements, direction of flows, identification of the main process and start-up lines, all instrumentation, control, and interlock facilities, key dimensions and duties of all equipment, operating and design pressure and temperature for vessels, equipment elevations, set pressures for relief valves, and drainage requirements.

Entrainment: A non-equilibrium process by which liquids are mechanically carried into a vapor leaving a process vessel or contacting device.

Engineering, Procurement, and Construction Contract: 1. A legal agreement setting out the terms for all activities required to build a facility to the point that it is ready to undergo preparations for operations as designed. 2. The final contracting phase in the development of the export portion of the LNG chain that defines the terms under which the detailed design, procurement, construction, and commissioning of the facilities

Where v is the velocity in the smaller pipe, a is the cross-sectional area of the smaller pipe, A is the crosssectional area of the larger pipe. For a considerable enlargement the head loss tends to

Entrance and exit losses: The irreversible energy loss caused when a fluid enters or leaves an opening, such as into or out of a pipe into a vessel. Where there is a sudden enlargement, such as when a pipe enters a larger pipe or vessel, eddies form and there is a permanent energy loss expressible as a head loss as:

H exit

v2  a 1−  =  2g  A

H exit =

v2 2g

2

Glossary of Petroleum and Technical Terminology  863 With a rapid contraction, it has been found experimentally that the permanent head loss can be given by:

H exit

v2 =K 2g

tertiary butyl ether). 2. Any carbon compound containing the functional group (C – O – C). Commonly used ether is diethyl ether, which is used as an anesthetic.

H

where for very large contraction, K= 0.5 Entropy (dS): The extent to which energy in a closed system is unavailable to do useful work. An increase in entropy occurs when the free energy decreases or when the disorder of molecules increases. For a reversible process, entropy remains constant such as in a friction free adiabatic expansion or compression. The change in entropy is defined as:

dS =

dQ T

where Q is the heat transferred to or from a system, and T is the absolute temperature. However, all real processes are irreversible, which means that in a closed system there is a small increase in entropy. Environmental Protection Agency (EPA), United States: 1. Governmental agency, established in 1970. Its responsibilities include the regulation of fuel and fuel additives. 2. The U.S. federal agency that administers federal environmental policies, enforces environmental laws and regulations, performs research, and provides information on environmental subjects. The agency also acts as chief advisor to the president on American environmental policy and issues. 3. A federal agency created in 1970 to permit coordinated and effective government action, for protection of the environment by the systematic abatement and control of pollution, through integration of research monitoring, standard setting, and enforcement activities. 4. U.S. pollution control enforcer. 5. A regulatory agency established by the U.S. Congress to administer that nation’s environmental laws. Also called the US EPA. Error: Discrepancy between a computed, observed or measured value or condition and the true specified or theoretically correct value or condition. Ethane (C2H6): A colorless gas; a minor constituent of natural gas and a component in refinery gas that, along with methane is typically used as refinery fuel. An important feedstock for making ethylene. Ether (C2H5OC2H5): 1. A generic term applied to a group of organic chemical compounds composed of carbon, hydrogen and oxygen, characterized by an oxygen atom attached to two carbon atoms (e.g., methyl

H

H

C

C

H

H

O

H

H

C

C

H

H

H

Ethylene (C2H4): A colorless gas created by cracking processes. In refineries, it is typically burned with the methane and ethane. In chemical plants, it is purposefully made in ethylene plants and it is basic building block for a wide range of products including polyethylene and ethyl alcohol. ETBE: Ethyl Tertiary Butyl Ether (CH3)3 COC2H5: 1. A colorless, flammable, oxygenated hydrocarbon blend stock. It is produced by the catalytic etherification of ethanol with isobutylene. 2. An oxygenated gasoline blending compound to improve octane and reduce carbon monoxide emissions. It is commonly used as an oxygenate gasoline additive in the production of gasoline from crude oil. HC 3

HC 3

CH

HO C H /H 2

2

HC 3

5

HC

CH O CH 3

2

5

3

Equation of state: A relationship that links the pressure, volume and temperature of an amount of a substance. It is used to determine thermodynamic properties such as liquid and vapor densities, vapor pressures, fugacities and deviations from ideality and enthalpies. Various equations of state have been developed to predict the properties of real substances. Commonly used equations of state include the ideal gas law, virial equation, van der Waals’ equation, PengRobinson, Soave-Redlich Kwong and Lee-Kesler equations. Cubic equations are relatively easy to use and are fitted to experimental data. The van der Waals equation is comparatively poor at predicting state properties. The Lee-Kesler model, which is based on the theory of corresponding states, uses reduced temperature and pressure and covers a wide range of temperatures and pressures. Equilibrium: A condition or state in which a balance exists within a system, which may be physical or chemical. A system is in equilibrium if it shows no tendency to change its properties with time. Static equilibrium occurs if there is no transfer of energy across the system boundary, whereas dynamic equilibrium is when transfer occurs, but the net effect of the energy is

864  Petroleum Refining Design and Application Handbook Volume 2 zero. Thermodynamic equilibrium occurs when there is no heat or work exchange between a body and its surroundings. Chemical equilibrium occurs when a chemical reaction takes place in the forward direction, when reactants form products at exactly the same rate as the reverse reaction of products revert to their original reactant form. Equilibrium constant (Kc): A reversible process, chemical or physical in a closed system will eventually reach a state of equilibrium. The equilibrium is dynamic and may be considered as a state at which the rate of the process in one direction exactly balances the rate in the opposite direction. For a chemical reaction, the equilibrium concentrations of the reactants and products will remain constant providing the conditions remain unchanged for the homogeneous system:

wA + xB ↔ yC + zD The ratio of the molar concentrations of products to reactants remain constant at a fixed temperature, the equilibrium constant, Kc is: y z C ] [D ] [ Kc = [ A]w [ B ]x

For the Haber process for the synthesis of ammonia, nitrogen is reacted with hydrogen as:

N 2 ( g ) + 3H 2 ( g ) ↔ 2NH 3 ( g ) The equilibrium constant is expressed as partial pressure as: Kc

NH 3 N2

2

H2

3

2 pNH 3

pN 2 pH 3 2

Equilibrium K – value (K-value): the ratio of the mole fraction in the vapor divided by the mole fraction in the liquid for a component in the equilibrium state. Each K value corresponds to a given temperature, pressure and mixture composition. Equilibrium ratio (K): the ratio of the mole fraction in the vapor phase y of a component in a mixture, to the mole fraction in the liquid phase x, at equilibrium.

KA =

yA xA

It is a function of both temperature and pressure. The relative volatility , is less dependent on temperature

and pressure than the equilibrium constant where for an ideal mixture of two components, A and B:

aAB =

KA KB

Equilibrium-Flash Vaporizer: When a mixture is heated without allowing the vapor to separate from the remaining liquid, the vapor assists in causing the highboiling parts of the mixture to vaporize. Thus continuous-flash vaporization is used in almost all plant operations. The equipment is used to determine a flash vaporization curve, where a series of runs at different temperatures are conducted, and each run constitutes one point (of temperature and percentage vaporized) on the flash curve. Equipment Reliability: The probability that, when operating under stated environment conditions, process equipment will perform its intended function adequately for a specified exposure period. Equivalent length: A method used to determine the pressure drop across pipe fittings such as valves, bends, elbows and T-pieces. The equivalent length of a fitting is that length of pipe that would give the same pressure drop as the fitting. Since each size of pipe or fitting requires a different equivalent length for any particular type of fitting, it is usual to express equivalent length as so many pipe diameters and this number is independent of pipe. For example, if a valve in a pipe of diameter d, is said to have an equivalent length, n, pipe diameters, then the pressure drop due to the valve is the same as that offered by a length, and of the pipe. Ergun equation: Sabri Ergun developed an equation in 1952 to determine the pressure drop per unit length of a fixed bed of particles such as catalyst at incipient gas velocity, v: 2 −∆p 150 (1 − e ) mv 1.75 (1 − e ) rv + = L fe 3d 2 fe 3d 2

Where –∆p/L is the pressure drop over the depth of bed, e is the bed voidage, d is the mean particle diameter, is the fluid density, is the fluid viscosity, and is the sphericity. The incipient point of fluidization corresponds with the highest pressure drop at the minimum fluidization velocity. Erosion: The physical removal of material from a surface by mechanisms that exclude chemical attack. The usual phenomenon that causes erosion is

Glossary of Petroleum and Technical Terminology  865 impingement by either liquid droplets or entrained solid particles. If there are no corrosive substances present, then in many cases, the most common mechanism for material damage due to erosion is impingement by solid particles. Exothermic reaction: 1. A chemical reaction that gives out/liberates heat. No energy input is required for the reaction to proceed. It has a negative enthalpy change and therefore under the appropriate conditions the reaction will occur spontaneously. Chemical reactors used to contain exothermic reactions therefore require cooling facilities to remove the excess heat that is generated and to maintain a constant temperature. 2. A reaction in which heat is evolved. Alkylation, polymerization, and hydrogenation reactions are exothermic reactions. Expansion Loop: Piping thermally expands as it gets hot. Allowance must be made for the growth in pipe length, otherwise the pipe will break by cracking at its welds. A fractionator at the Good Hope Refinery in the U.S. was burned down because of such an omission. Explosion: 1. The sudden conversion of potential energy (chemical or mechanical) to kinetic energy with the production and release of gases under pressure, or the release of a gas under pressure. 2. A release of energy that causes a pressure discontinuity or blast wave. Exports: Shipments of crude oil and petroleum products from countries, e.g., in the United States. shipments from the 50 states and the District of Columbia to foreign countries, Puerto Rico, the Virgin Islands, and other U.S. possessions and territories. Failure: 1. Termination of the ability of a functional unit to perform a required function. 2. An unacceptable difference between expected and observed performance. Fail Safe: A system design or condition such that the failure of a component, subsystem or system or input to it, will automatically revert to predetermined safe static condition or state of least critical consequence for the component, subsystem or system. Fail Steady: A condition wherein the component stays in its last position when the actuating energy source fails. May also be called Fail in Place. Failure Mode: The action of a device or system to revert to a specified state upon failure of the utility power source that normally activates or controls the

device or system. Failure modes are normally specified as fail open (FO), fail close (FC) or fail steady (FS) which will result in a fail safe or fail to danger arrangement. Failure Mode and Effects Analysis (FMEA): A systematic, tabular method for evaluating and documenting the causes and effects of known types of component failures. Fault: Abnormal condition that may cause a reduction in, or loss of, the capability of a functional unit to perform a required function. Fault Tree: A logic method that graphically portrays the combinations of failures that can lead to a specific main failure or accident of interest. Field Production: Represents crude oil production on leases, natural gas liquids production at natural gas processing plants, new supply of other hydrocarbons/ oxygenates and motor gasoline blending components and fuel ethanol blended into finished motor gasoline. Final Boiling Point (FBP): The final boiling point of a cut, usually on an ASTM distillation basis. Fifteen-five (15/5) distillation: A laboratory batch distillation performed in a 15-theoretical plate fractionating column with a 5:1 reflux ratio. A good fractionation results in accurate boiling temperatures. For this reason, this distillation is referred to as the true boiling point distillation. This distillation corresponds very closely to the type of fractionation obtained in a refinery. Fire:1. A combustible vapor or gas combining with an oxidizer in a combustion process manifested by the evolution of light, heat and flame. 2. The rapid thermal oxidation (combustion) of a fuel source resulting in heat and light emission. There are various types of fire, classified by the type of fuel and associated hazards. In the U.S., the National Fire Protection Association (NFPA) classifies fires and hazards by types of fuels or combustible in order to facilitate the control and extinguishing of fires: Class A Class B Class C Class D

Ordinary combustibles such as wood, cloth, paper, rubber and certain plastics. Flammable or combustible liquids, flammable gases, greases and similar materials. Energized electrical equipment. Combustible metals, such as magnesium, titanium, zirconium, sodium, and potassium.

866  Petroleum Refining Design and Application Handbook Volume 2 Fireball: The atmospheric burning of a fuel-air cloud in which the energy is mostly emitted in the form of radiant heat. The inner core of the fuel release consists of almost pure fuel whereas the outer layer in which ignition first occurs is a flammable fuel-air mixture. As buoyancy forces of the hot gases begin to dominate, the burning cloud rises and becomes more spherical in shape. Fire Point: Is the temperature well above the flash point where the product could catch a fire. The fire point and flash point are always taken care of in the day to day operation of a refinery. (See also Flash point). Fireproof: Resistant to a specific fire exposure. Essentially nothing is absolutely fireproof, but some materials or building assemblies are resistant to damage or fire penetration at certain levels of fire exposures that may develop in the petroleum, chemical or related industries. Fireproofing: A common industry term used to denote materials or methods of construction used to provide fire resistance for a defined fire exposure and specified time. Essentially nothing is fireproof if it is exposed to high temperatures for extended period of time. Fire suppression system: A method, device or system used to detect a fire or ignition source, and to extinguish the fire in sufficient time so as to prevent structural damage and/or debilitation of personnel. Fire triangle: A way of illustrating the three factors necessary for the process of combustion which are fuel, oxygen and heat. All three are required for combustion to occur. A fire can therefore be prevented or extinguished by removing one of the factors. A fire is not able to occur without sufficient amounts of all three (See Figure 8). The fire triangle/fire tetrahedron

at

Ox yg

He

en

The fire tetrahedron

Fuel Fire safety, at its most basic, is based upon the principle of keeping fuel sources and ignition source separate.

Figure 8 Diagram of a fire triangle.

First law of thermodynamics: A law that is applied to the conservation of energy in which the change in internal energy, ΔU of a system is equal to the difference in the heat added, Q to the system and the work done by the system:

∆U = Q − W When considering chemical reactions and processes, it is more usual to consider situations where work is done on the system rather than by it. Fittings: Connections and couplings used in pipework and tubing. The type of fittings used depends largely on the wall thickness as well as in part on the properties of the pipes and tubes including welds, flanges and screw fittings. Fittings include elbow, bends, tees, reducers and branches. Fixed Bed: A place in a vessel for catalyst through or by which feed can be passed for reactions, as opposed to a fluidized bed, where the catalyst moves with the feed. Fixed-Bed Reactor: A reactor in which the catalyst is loaded into an immovable bed. The reactants enter the top of the bed, and the products exit from the bottom of the bed. The process must be taken off line, and hot gases circulated through the catalyst bed to burn off coke deposits and restore the catalyst activity. Flame: The glowing gaseous part of a fire. Flammable: 1. A substance or material that has the ability to support combustion and be capable of burning with a flame. It is easily ignited or highly combustible. The term is more widely used than inflammable as this is often confused with incombustible, which means an inability or lack of ability to combust. A flammable liquid is a liquid that has the capability of catching fire. In the U.S., the National Fire Protection Association defines a flammable liquid as a liquid that has a flash point below 100°F (37.8°C) and a vapor pressure not exceeding 40 psia (2.72 bar) at that temperature. 2. In general sense refers to any material that is easily ignited and burns rapidly. It is synonymous with the term inflammable that is generally considered obsolete; due to its prefix which may be incorrectly misunderstood as not flammable (e.g., incomplete is not complete). Flammable Liquid: 1. As defined by NFPA 30, a liquid having a flash point below 100°F (37.8°C) and having a vapor pressure not exceeding 2068 mm Hg (40 psia) at 100°F (37.8°C) as determined under specific conditions. 2. Any liquid having a flash point below

Glossary of Petroleum and Technical Terminology  867 100°F (37.8°C), except any liquid mixture having one or more components with a flash point at or above the upper limit that makes up 99% or more of the total volume of the mixture, 3. Liquid with a flash point below 100°F (37.8°C). At that temperature, vapors from the substance can be ignited by a flame, spark or other sources of ignition. Flammability Limit: 1. The flammability limit of a fuel is the concentration of fuel (by volume) that must be present in air for an ignition to occur when an ignition source is present. 2. The range of gas or vapor amounts in air that will burn or explode if a flame or other ignition source is present. Importance: The range represents an unsafe gas or vapor mixture with air that may ignite or explode. Generally, the wider the range the greater the fire potential. Flange: It is a flat end of a pipe that is used to bolt up to a flange on another piece of piping. Bolts, with nuts at each end, are used to force the flanges together. Flange Rating: Connections on vessels, spool pieces and valves have a pressure rating called a flange rating. This rating can be confusing; e.g., a 150 psig flange rating is actually good for about 230 psi design. Flare: 1. A burner on a remote line used for disposal of hydrocarbons during clean-up, for emergency shut downs, and for disposal of small-volume waste streams of mixed gases that cannot easily or safely be separated. 2. A flame used to burn off unwanted natural gas; a “flare stack” is the steel structure on a processing facility from which gas is flared. 3. An open flame used to burn off unwanted natural gas. 4. To burn unwanted gas through a pipe or stack. 5. The flame from a flare; the pipe or the stack itself. Flared: Gas disposed of by burning in flares usually at the production sites or at gas processing plants. Flare Stack: The steel structure on an offshore rig or at a processing facility from which gas is flared. Flare System: This is a piping network that runs through the plant to collect vents of gas so that they can be combusted at a safe location in the flare stack. Flaring: Is the burning of a natural gas that cannot be processed or sold. Flaring disposes off gas, and it releases emissions into the atmosphere. Flaring/Venting: The controlled burning (flare) or release (vent) of natural gas that cannot be processed

for sale or use because of technical or economic reasons. Flashing: Vaporization of water or light ends as pressure is released during production or processing. Flash Calculation: Determination of the compositions and quantities of liquid and vapor that co-exist in a mixture under equilibrium conditions. Flash Chamber: A wide vessel in a vacuum flasher thermal cracking plant or similar operation into which a hot stream is introduced causing the lighter fractions of that stream to vaporize and leave by the top. Flash Fire: The combustion of a flammable vapor and air mixture in which flame passes through that mixture at less than sonic velocity, such that negligible damaging overpressure is generated. Flash Point: 1. The minimum temperature at which a liquid, under specific test condition gives off sufficient flammable vapor to ignite momentarily on the application of ignition source. 2. The lowest temperature at which any combustible liquid will give off sufficient vapor to form an inflammable mixture with air (i.e., that can be readily ignited). Flash points are used to specify the volatility of fuel oils, mostly for safety reasons. They are generally used as an indication of the fire and explosion potential of a product; ASTM D-56, D-92, D-93, D-134, D-1310. 3. Hold a flame over a cup of diesel fuel; it will start to burn at its 160°F (71°C) flash temperature. Gasoline’s flash point is below room temperature. Jet fuel is 110°F (43°C). The lighter the hydrocarbon, the lower the flash point. Flash Tank: Container where the separation of gas and liquid phases is achieved after pressure reduction in flow fluid. Both phases appear when pressure is decreased as a consequence of the Joule-Thomson effect. Flash Vapors: Vapors released from a stream of natural gas liquids as a result of an increase in temperature or a decrease in pressure. Flash Zone: The section of a distillation/fractionating column containing the column feed nozzle(s). The column feed separates or “flashes” into liquid and vapor at it expands through the feed nozzle(s) and enters the column. Flexicoking: A thermal cracking process which converts heavy hydrocarbons such as crude oil, oil sands bitumen, and distillation residues into light

868  Petroleum Refining Design and Application Handbook Volume 2 hydrocarbons. Feedstocks can be any pumpable hydrocarbons including those containing high concentrations of sulfur and metals. Flooding: 1. An excessive build-up of liquid in absorption columns or on the plate of a distillation column. It is due to high vapor flow rates up the column. In distillation columns, this is caused by high heating rates in the reboiler. 2. An all-inclusive term that is given to non-equilibrium behavior in a distillation/fractionating column because of larger flows of liquid and/or vapor than the column can process. Flooding can be caused by liquid backing up in the column, vapor blowing through the column and lifting the liquid off the trays, etc. All columns are designed to handle about 80% of the flow before flooding occurs. Sometimes flooding is caused by mechanical restrictions or damage to the internals in the column. The flooding point is a condition in a packed column such as an absorption column which receives a counter current flow of gas at the bottom and a liquid descending under gravity from the top where there is insufficient liquid hold-up in the packing for mass transfer to take place effectively. The liquid therefore descends to the bottom of the column without mass transfer. The rate of flow through the packing for effective mass transfer is controlled by the pressure drop across the packing material. Flow: The movement of a fluid under the influence of an external force such as gravity or a pump. Flowline: A pipeline that carries materials from one place to another. In the offshore industry, a flowline is a pipeline that carries oil on the seabed from a well to a riser. On a process flow diagram, the flowline is indicated by a line entering and leaving a vessel or unit operation. An arrow indicates the direction of flow. Flow meter: A device used to measure the flow of process fluids. Flow meters are mainly classified into those that are intrusive and those that are nonintrusive to the flow of the fluid. Flow meters include differential pressure meters, positive displacement meters, mechanical, acoustic and electrically heated meters. The measurement of the flow of process fluids is essential not only for safe plant control but also for fiscal monitoring purposes. It is essential to select correctly the flow meter for a particular application, which requires a knowledge and comprehension of the nature of the fluid to be measured and an understanding of the operating principles of flow meters.

Flow rate: The movement of material per unit time. The material may be a gas, liquid or solid particulates in suspension or combination of all of these, and expressed on a mass, volumetric or molar basis. The volumetric flow of material moving through a pipe is the product of its average velocity and the cross-sectional area of the pipe. Flow regime: The behavior of a combined gas and liquid flow through a duct, channel or pipe can take many forms, and there are descriptions used to define the possible flow patterns. Depending on the conditions of flow of the two phases, one phase is considered to be the continuous phase while the other is the discontinuous phase. An example is the flow of mist or fine dispersion of liquid droplets in a gas phase. The smaller the liquid droplets, the higher are the surface tension effects. Distortion of the discontinuous phse results in the shape to become non-spherical. Also, there is a tendency for the liquid phase to wet the wall of the pipe and for the gas phase to congregate at the center. An exception to this is in evaporation such as in refrigeration where nuclear boiling occurs on the pipe surface resulting in a vapor film or bubbles forming at the surface with a central core of liquid. The flow of fluids through pipes and over surfaces can be described as: 1. Steady flow in which flow parameters at any given point do not vary with time. 2. Unsteady flow in which flow parameters at any given point vary with time. 3. Laminar flow in which flow is generally considered to be smooth and streamline. 4. Turbulent flow in which flow is broken up into eddies and turbulence. 5. Transition flow, which is a condition lying between the laminar and turbulent flow regimes Flow regime maps are charts representing the various flow patterns that are possible for two-phase gasliquid flow in both horizontal and vertical pipes and tubes. There are many types of flow regime maps that have been developed. The simplest form of the map involves a plot of superficial velocities or flow rates for the two phases with the most widely used generalized flow regime map for horizontal flow as shown below: The maps are populated with experimental data in which lines are drawn to represent the boundaries between the various flow regimes. These include dispersed, bubble or froth, wavy, annular, stratified, slug and plug flow. The boundaries between the various flow

Glossary of Petroleum and Technical Terminology  869 Segregated

By

100,000 Dispersed flow

Stratified Wave flow

Bubble or froth flow

Annular flow

10,000

Wavy Stratified flow

Slug flow

1,000

Annular Intermittant Plug flow

100

(a)

0.1

0.2

0.4 0.6 0.8 1.0

2

4

6 8 10

2

4 6 8 100

2

4

6 8 1,000 2

4

6 8 10,000

Plug

Bx

Slug Distributed

Bubble

(b)

Mist

Figure 9 (a)Flow patterns for horizontal two-phase flow (Based on data from 1, 2, and 4 in. pipe by Baker, O., Oil & Gas J., Nov. 10, p. 156, 1958.). (b) Representative forms of horizontal two-phase flow patterns as indicated in Figure 9a.

patterns are due to the regime becoming unstable as it approaches the boundary with the transition to another flow pattern. As with the transition between laminar and turbulent flow in a pipe, the transitions in a flow regime are unpredictable. The boundaries are therefore not distinct lines but loosely defined transition zones. A limitation of the maps is that they tend to be specific to a particular fluid and pipe. The seven types of flow regimes in order of increasing gas rate at constant liquid flow rate are given below (See Figure 9). Bubble or Froth flow: Bubbles of gas are dispersed throughout the liquid and are characterized by bubbles of gas moving along the upper part of the pipe at approximately the same velocity as the liquid. This type of flow can be expected when the gas content is less than about 30% of the total (weight) volume flow rate. (Note: 30% gas by weight is over 99.9% by volume, normally.) Plug flow: Alternate plugs of liquid and gas move along the upper part of the pipe and liquid moves along the bottom of the pipe.

Stratified flow: The liquid phase flows along the bottom of the pipe while the gas flows over a smooth liquid-gas interface. Wave flow: Wave flow is similar to stratified flow except that the gas is moving at a higher velocity and the gas-liquid interface is distributed by waves moving in the direction of flow. Slug flow: This pattern occurs when waves are picked up periodically by the more rapidly moving gas. These form frothy slugs that move along the pipeline at a much higher velocity than the average liquid velocity. This type of flow causes severe and in most cases, dangerous vibrations in equipment because of the high velocity slugs against fittings. Annular flow: In annular flow, liquid forms around the inside wall of the pipe and gas flows at a high velocity through the central core. Dispersed, Spray or Mist flow: Here, all of the liquid is entrained as fine droplets by the gas phase. This type

870  Petroleum Refining Design and Application Handbook Volume 2 of flow can be expected when the gas content is more than roughly 30% of the total weight flow rate. Some overhead condenser and reboiler-return lines have dispersed flow. Flowsheet: A schematic diagram or representation of a process illustrating the layout of process units and their functions linked together by interconnecting process streams. The development of a flowsheet involves the process synthesis, analysis and optimization. The heat and material balances are solved using thermodynamic properties and models. An economic analysis is also completed as well as a safety and environmental impact assessment. The choice of equipment and their interconnectivity are optimized along with the choice of operating parameters such as temperature, pressure and flows. Steady-state flowsheet computer software packages are frequently used to develop flowsheets. Flue: Passage through which flue gases pass from a combustion chamber to the outside atmosphere. Flue Gas: 1. A mixture of gases produced as a result of combustion that emerge from a stack or chimney. The gases contain smoke, particulates, carbon dioxide, water vapor, unburnt oxygen, nitrogen, etc. An Orsat analysis is a reliable device to determine the composition of the flue gas and the efficiency of combustion although it has been replaced by other techniques. 2. Gas from the various furnaces going up to the flue (stack). Fluid Catalytic Cracking (FCC): A thermal process in which the oil is cracked in the presence of finely divided catalyst which is maintained in an aerated or fluidized state by the oil vapors. The powder or fluid catalyst is continuously circulated between the reactor and the regenerator, using air, oil vapor and steam as the conveying media. The most commonly used catalytic cracking process. The catalyst is a fine powder that is designed to form a fluidized bed in the reactor and regenerator. Fluid Coking: 1. A coking process in which the feed is preheated and sprayed into a reactor where it contacts a hot fluidized bed of coke returning from a burner vessel. The hot oil products are stripped from the coke which is circulated back to the burner vessel. Coke not returned to the reactor from the burner vessel is withdrawn as a coke product. 2. A thermal cracking process utilizing the fluidized-solids technique to remove carbon (coke) for continuous conversion of heavy, low-grade oils into lighter products.

Fossil Fuels: Fuels formed by natural processes such as anaerobic decomposition of buried dead organisms. The age of the organisms and their resulting fossil fuels is typically millions of years, and sometimes exceeds 650 million years. Fossil fuels contain high percentage of carbon and include coal, petroleum and natural gas. Other more commonly used derivatives of fossil fuels are kerosene, and propane. They range from volatile materials with low carbon: hydrogen ratios like methane, to liquid petroleum to nonvolatile materials composed of almost pure carbon, like anthracite coal. Methane can be found in hydrocarbon fields, alone, associated with oil, or in the form of methane clathrates (See Figure 10). Georg Agricola in 1556 first introduced the theory that fossil fuels were formed from the fossilized remains of dead plants by exposure to heat and pressure in the Earth’s crust over millions of years. The theory was later expounded by Mikhail Lomonosov in the 18th century. Coal is one of the fossil fuels (See Figure 10). The use of fossil fuels raises serious environmental concerns. The burning of fossil fuels produces around 21.3 billion tonnes (21.3 gigatonnes) of carbon dioxide (CO2) per year, but it is estimated that natural processes can only absorb about half of that amount, so there is a net increase of 10.65 billion tonnes of atmospheric carbon dioxide per year (one tonne of atmospheric carbon is equivalent to 44/12 or 3.7 tonnes of carbon dioxide). Carbon dioxide is one of the greenhouse gases that enhances the radiative forcing and contributes to global warming, causing the average surface temperature of the Earth to rise with major adverse climatic effects. A global movement towards the generation of renewable energy is therefore essential to help reduce global greenhouse gas emissions. Ratio of gross domestic product to kilograms of fossil fuel carbon consumed, for the world’s 20 largest economies. The two countries with the highest GDP per

Figure 10 Coal.

Glossary of Petroleum and Technical Terminology  871 GDP dollars / kg carbon emitted

20

Economic efficiency of fossil fuel usage (world’s 20 largest economies)

16 12 Global average 8 4

Brazil France Italy UK Spain Japan Germany India Indonesia Mexico Taiwan Turkey Thailand China South Korea United States Canada Australia Iran Russia

0

Figure 11 Economic efficiency of fossil fuel usage.

kilogram carbon ratios, Brazil and France, produce large amounts of hydroelectric and nuclear power, respectively (See Figure 11). Fractionation: The general name given to a process for separating mixtures of hydrocarbons or other chemicals into separate streams or cuts or fractions. Free Carbon: The organic materials in tars which are insoluble in carbon disulfide. Free Energy of Formation: the change in free energy when a compound is formed from its elements with each substance in its standard state at 77°F (25°C). The heat of reaction at 25°C may be calculated by subtracting the sum of the free energies of formation of the reactants from the sum of the free energies of formation of the products. Free Water: Condensed water that exits as a separate liquid phase. Most refinery distillation columns are designed such that free water will not be present, since it can result in column upsets and promote corrosion of the metal in the column. Freeze Point: 1. The temperature at which the hydrocarbon liquid solidifies at atmospheric pressure. It’s an important property for kerosene and jet fuels, because of the very low temperatures encountered at high altitudes in jet planes. One of the standard test methods for the freeze point is ASTM D4790. 2. The temperature at which a chilled petroleum product becomes solid and will no longer pour when a sample tube is tipped. Freeze point is a laboratory test. 3. The temperature at which crystals first appear as a liquid is

cooled, which is especially important in aviation fuels, diesel and furnace oil. Front-End Engineering and Design (FEED) Contract: 1. A legal agreement setting out the terms for all activities required to define the design of a facility to a level of definition necessary for the starting point an EPC contract. 2. Generally, the second contracting phase for the development of the export facilities in the LNG chain that provides greater definition than the prior conceptual design phase. In an LNG project, the single most important function of the FEED contract is to provide the maximum possible definition for the work ultimately to be performed by the engineering, procurement, and construction (EPC) contractor. 3. A study used to analyze the various technical options for new field developments with the objective to define the facilities required. 4. The stage of design between concept evaluation and detailed design during which the chosen concept is developed such that most key decisions can be taken. Output of FEED includes estimate of total installed cost and schedule. See also Engineering, procurement and construction contract. Fuel Gas: 1. A process stream internal to a facility that is used to provide energy for operating the facility. 2. Gas used as fuel in a liquefaction plant. It typically involves processing waste streams to LNG that are not profitable. It is used in gas turbines, boilers and reaction furnaces. Fuel Oil: Usually residual fuel but sometimes distillate fuel. Fuel Oil Equivalent (FOE): The heating value of a standard barrel of fuel oil, equal to 6.05 x 106 Btu (LHV). On a yield chart, dry gas and refinery fuel gas are usually expressed in FOE barrels. Furnace Oil: A distillate fuel made of cracked and straight run light gas oils primarily for domestic heating because of its ease of handling and storing. FVT: The final vapor temperature of a cut. Boiling ranges expressed in this manner are usually on a crude assay, true boiling point basis. Gas/Liquid chromatography (GC, GLC): Equipment used to determine the composition of a sample in the laboratory. Gap: Gas is usually based on ASTM 86 distillation temperatures and is defined as the 5% distilled temperature of a distillation column product minus the 95%

872  Petroleum Refining Design and Application Handbook Volume 2 distilled temperature of the next higher product in the column. When the difference is positive, the difference is called a gap. When the difference is negative, the difference is sometimes called an overlap. The gap or overlap is a measure of the sharpness of the separation between adjacent products in a distillation column.

process uses an absorber unit and a regenerator. The amine solution flows down the scrubber and absorbs the hydrogen sulfide as well as carbon dioxide from the upflowing gases. The regenerator is used to strip the amine solution of the gases for reuse. It is known as gas sweetening as the foul smell is removed from the gas.

Gas Cap: An accumulation of natural gas at the top of a crude oil reservoir. The gas cap often provides the pressure to rapidly evacuate the crude oil from the reservoir.

Gas Treating: Amine treating of light gases to remove such impurities as H2S and CO2. Molecular sieves are also used to concentrated hydrogen streams by removing inerts and light hydrocarbon contaminants.

Gasket: This is the softer material that is pressed between flanges to keep the fluid from leaking. Using the wrong gasket is a common cause of fires in process plants. Gaskets have different temperature and pressure ratings.

Gas Turbine: An engine that uses internal combustion to convert the chemical energy of a fuel into mechanical energy and electrical energy. It uses air, which is compressed by a rotary compressor driven by the turbine, and fed into a combustion chamber where it is mixed with the fuel, such as kerosene. The air and fuel are burnt under constant pressure conditions. The combustion gases are expanded through the turbine causing the blades on the shaft to rotate. This is then converted to electrical energy. Gas turbines are used in the process industries and on offshore gas platforms for electrical generation.

Gasoline Blending Components: Naphthas which will be used for blending or compounding into finished aviation or motor gasoline (e.g., straight-run gasoline, alkylate, reformate benzene, toluene, and xylenes). Excludes oxygenates (alcohols, ethers), butane, and natural gasoline. Gas sweetening: A process used to remove hydrogen sulfide and mercaptans from natural gas. Commonly used in petroleum refineries, the gas treatment uses amine solution such as monoethanolamine. The

1200

1000

800 70

P

TB

600

60 50 40

400

API

30

200

20 10

0

0

10

20

30

40 50 60 70 Percent distilled

80

Figure 12 TBP and gravity – mid percent curves.

90 100

API gravity, •

Gasoline: 1. A light petroleum product in the range of 80–400°F (27–204°C) for use in spark-ignition internal combustion engines. 2. An all-inclusive name for petroleum stocks that are used as fuel for internal combustion engines. Retail gasoline is a blend of several refinery gasolines and must meet specifications of octane, Reid vapor pressure, distilling boiling range, sulfur content, and so on. Additives such as ethers or alcohols are used to improve the octane for the blended product.

Grain: A unit of mass where one pound is equivalent to 7000 grains and a specification of 0.25 grain of H2S per 100 scf is equivalent to an H2S concentration of 4.0 ppmv.

Temperature, °F

Gas Oil: 1. Any distillate stream having molecular weights and boiling points higher than heavy naphtha > 400°F (> 205°C). The name gas oil probably traces its roots to “gasoline” bearing oil in the early days of refining. Early refiners used thermal cracking processes to produce more motor gasoline (MOG) from gas oil stocks. 2. The term is used for petroleum stocks with boiling ranges between approximately 650–1100°F (344–594 °C). Unreacted gas oils produced by distilling crude oil in crude and vacuum columns. Cracked gas oils are produced in refinery reaction processes, such as thermal and catalytic cracking, coking, visbreaking and hydrocracking.

Glossary of Petroleum and Technical Terminology  873 Gravity: The specific gravity (Sp.Gr.) of a stream, often expressed as API Gravity by petroleum refiners. The basis is always the density of water. Gravity Curve: The gravity of the material distilled from a petroleum stock in a laboratory still. The gravity curve is plotted against the percent distilled for the stock. Gravity curves are most commonly reported for true boiling point distillation (See Figure 12). Greenhouse Gas (GHG): A greenhouse gas is a gas in an atmosphere that absorbs and emits radiation within the thermal infrared range. This process is the fundamental cause of the greenhouse effect. The primary greenhouse gases in Earth’s atmosphere are water vapor, carbon dioxide, methane, nitrous oxide and ozone. Without greenhouse gases, the average temperature of Earth’s surface would be about 15°C (27°F) colder than the present average of 14°C (57°F). Gross Heating Value: Is the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid. The gross heating is an ideal gas property in a hypothetical state (the water cannot all condense to liquid because some of the water would saturate the CO2 in the products). Gross Heating Value of Fuels (GHV): The heat produced by complete oxidation of material of 60°F (25°C) to carbon dioxide and liquid water at 60°F (25°C). Gross Input to Atmospheric Crude Oil Distillation Units: Total inputs to atmospheric crude oil distillation units. Includes all crude oil, lease condensate, natural gas plant liquids, unfinished oils. Liquefied refinery gases, slop oils, and other liquid hydrocarbons produced from oil sands, gilsonite and oil shale. Gum: A complex sticky substance that forms by the oxidation of gasoline especially those stored over a long period of time. Gum fouls car engines especially the fuel injection ports. Harm: Physical injury or damage to the health of people, either directly or indirectly, as a result of damage to property or to the environment. Hazard: 1. A condition or object that has the potential to cause harm. 2. An unsafe condition, which if not eliminated or controlled may cause injury, illness or death. 3. A physical or chemical characteristic that has the potential for causing harm to people, the environment, or property. Examples of hazards:

• Combustible/Flammable substance. E.g., Ethylene is flammable • Corrosive. E.g., Sulfuric acid is extremely corrosive to the skin. • Explosive substance. E.g., Acrylic acid can polymerize, releasing large amounts of heat. • Toxic fumes. E.g., Chlorine is toxic by inhalation. • Substances kept at high pressure in containment (e.g., a vessel, tank) • Objects or material with a high or low temperature. • Radiation from heat source. • Ionizing radiation source. • Energy release during decomposition of a substance. E.g., Steam confined in a drum at 600 psig contains a significant amount of potential energy (See Figure 13). Hazard Analysis: Is the first step in a process used to assess risk. The result of a hazard analysis is the identification of different type of hazards. It is assigned a classification, based on the worst-case severity of the end condition. Risk is the combination of probability and severity. Preliminary risk levels can be provided in the hazard analysis. The validation, more precise prediction (verification) and acceptance of risk is determined in the risk assessment (analysis). The main goal of both is to provide the best selection of means of controlling or eliminating the risk. Hazard Communication: Employees’ “right-toknow” legislation requires the employers to inform employees (pretreatment inspectors) of the possible health effects resulting from contact with hazardous substances. At locations where this legislation is in force, employers must provide employees with information regarding any hazardous substances, which they might be exposed to under normal work conditions or reasonably foreseeable emergency conditions

Crude oil Hazard

Consider pressure, temperature, composition, quantity, etc. into account.

Figure 13 A hazard.

874  Petroleum Refining Design and Application Handbook Volume 2 resulting from workplace conditions. OSHA’s Hazard Communication Standard (HCS) (Title 29 CFR Part 1910.2100) is the federal regulation and state statutes are called Workers’ Right-to-Know Laws. Hazard Communication Program: A written plan to manage the hazards associated with the use of chemicals in the workplace. Hazardous Chemical: A substance that may harm the worker either physically (e.g., fire, explosion) or chemically (e.g., toxic, corrosive). Hazardous Events: Hazardous event is defined as hazardous situation which results in harm. Each identified hazard could give a number of different hazardous events. For each identified hazardous event, it should also be described which factors contributed to it. E.g., the hazard combustible substance could give the following hazardous events: • Pool fire outside a tank, due to leakage, when an ignition source is present. • Flash fire inside a tank when an ignition source is present. • Factors that could contribute to the leakage in the tank could for instance be: • Bad connection joint. • Gasket damage. • Tube damage. • Pipe damage. Hazardous Situation: Circumstance in which a person is exposed to hazards. HAZID/HAZOP: 1. HAZard Identification/ HAZard and Operability analysis systematic design review methods to identify and address hazards to ensure that the necessary safety measures to eliminate or mitigate hazards are incorporated in the design and operation of the unit. 2. A qualitative process risk analysis tool used to identify hazards and evaluate if suitable protective arrangements are in place. If the process were not to perform as intended, and unexpected consequences were to result. HCGO: Heavy coker gas oil. HCO: Heavy FCC cycle gas oil. See Heavy Cycle Oil. Heart cut recycle: That unconverted portion of the catalytically cracked material which is recycled to the catalytic cracker. This recycle is usually in the boiling

range of the feed, and by definition, contains no bottoms. Recycle allows less severed operation and suppresses the further cracking of desirable products. Heat Balance: See energy balance. Heat Exchangers: A pressure vessel for transferring heat from one liquid or vapor stream to another. A typical heat exchanger consists of a cylindrical vessel and nozzles through which one stream can flow and a set of pipes or tubes in series in the cylinder through which the other can flow. Heat transfer mechanisms are conduction and convection. See also Shell & Tube Heat Exchanger. Heat Flux: The rate of heat transfer per unit area normal to the direction of heat flow. It is the total heat transmitted by radiation, conduction and convection. Heat Pump: Thermodynamic heating/refrigerating system to transfer heat. The condenser and evaporator may change roles to transfer heat in either direction. Heat Rate: The measure of efficiency in converting input fuel to electricity. Heat rate is expressed as the number of Btu of fuel (e.g., natural gas) per kilowatt hour (Btu/kWh). Heat rate for power plants depends on the individual plant design, its operating conditions, and its level of electric power output. The lower the heat rate, the more efficient is the plant. Heat Recovery: Heat utilized that would otherwise be wasted from a heating system. Heat Transfer Coefficient: Coefficient describing the total resistance to heat loss from a producing pipe to its surroundings. Includes heat loss by conduction, convection and radiation. Heating Oil: Any distillate or residual fuel. 1. Oil used for residential heating. 2. Trade term for the group of distillate fuel oils used in heating homes and buildings as distinguished from residual fuel oils used in heating and power installations. Both are burner fuel oils. Heating Value: 1. The average number of British thermal units per cubic foot of natural gas as determined from tests of fuel samples. 2. The amount of heat produced from the complete combustion of a unit quantity of fuel. 3. The amount of energy or heat that is generated when a hydrocarbon is burned (chemically combined with oxygen). 4. Energy released in the complete combustion of a unit of mass, matter or volume

Glossary of Petroleum and Technical Terminology  875 of a fuel in a stoichiometric mixture with air. 5. The amount of heat produced by the complete combustion of a unit quantity of fuel. Heat of Combustion: The amount of heat released in burning completely an amount of substance is its heat of combustion. The general formula for the combustion of a hydrocarbon compound is: CnH2n+2 + (3n+1)/2 O2 → (n+1) H2O + n CO2 + Energy Heat of Reaction: The heat release of heat absorbed when a chemical reaction takes place. The heat of reaction may be computed from the free energies of formation for the reacting components and the resultant products at the standard temperature of 77°F (25°C). Heat of Vaporization: The amount of heat energy required to transform an amount of a substance from the liquid phase to the gas phase. Heavy Crude: Crude oil of 20° API gravity or less; often very thick and viscous. Heavy Cycle Oil (HCO): Gas oil produced in an FCC operation that boils in the approximate TBP range of 400–1000°F (205–358°C). Heavy cycle oil is not generally withdrawn as a product, but it is recycled back to the reactor for further cracking to improve the overall conversion of the process. Heavy Ends: The highest boiling portion of a gasoline or other petroleum oil. The end point as determined by the distillate test reflects the amount and character of the heavy ends present in a gasoline. Heavy Gas Oil: Petroleum distillates with an approximate boiling range from 651°F to 1000°F (344°C to 538°C). Heavy Key: A distributed component in a distillation section that is recovered in the (bottom) heavy product, with a small, specified amount leaving in the top product. Heavy Oil: Lower gravity, often higher viscosity oils. Normally less than 28° API gravity. Hempel distillation: U.S. Bureau of Mines (now Department of Energy, DOE). Routine method of distillation. Results are frequently used interchangeably with TBP distillation. Heptane (nC7H16): Normal heptane is a straight chain alkane hydrocarbon with the chemical formula H3C(CH2)5CH3 or C7H16. Heptane (and its many

isomers) is widely applied in laboratories as a totally non-polar solvent. As a liquid, it is ideal for transport and storage. Heptane is commercially available as mixed isomers for use in paints and coatings, as pure n- heptane for research and development and pharmaceutical manufacturing and as a minor component of gasoline. n – heptane is defined as the zero point of the octane rating scale. It is undesirable in gasoline because it burns explosively, causing engine knocking, as opposed to branched-chain octane isomers, which burn more slowly and give better performance. When used as a fuel component in antiknock test engines, a 100% heptane fuel is the zero point of the octane rating scale (the 100 point is 100% iso-octane). Octane number equates to the antiknock qualities of a comparison mixture of heptane and isooctane which is expressed as the percentage of isooctane in heptane and is listed in pumps for gasoline dispensed in the U.S. and internationally. HF Alkylation: alkylation using hydrofluoric acid as a catalyst. High Pressure (HP): A processing unit operating at either equal to or greater than 225 psig measured at the outlet separator. High Temperature Simulated Distillation (HTSD): Laboratory test designed for petroleum stocks boiling up to 1382°F (750°C). HSR: Heavy Straight-Run. Usually naphtha side stream from the atmospheric distillation tower. HVGO: Heavy vacuum gas oil. A side stream from the vacuum distillation tower. Hydrocarbon: Any organic compound that is comprised of hydrogen and carbon atoms, including crude oil, natural gas and coal. Hydrocrackate: The gasoline range product from a hydrocracker. Hydrocracking: 1. A process in which high or heavy gas oils or residue hydrocarbons are mixed with hydrogen under high pressure and temperature and in the presence of a catalyst to produce light oils. 2. A refining process in which a heavy oil fraction or wax is treated with hydrogen over a catalyst under relatively high pressure and temperature to give products of lower molecular mass.

876  Petroleum Refining Design and Application Handbook Volume 2 Hydrocracked Naphtha: A high-quality blending stream obtained when high boiling cracked distillates undergo a combination of processes like cracking, hydrogenation and reforming in the presence of a catalyst and hydrogen. Hydrocyclone: A cone-shaped device for separating fluids and the solids dispersed in fluids. Hydrodesulfurization: A process in which sulfur is removed from the molecules in a refinery stream by reacting it with hydrogen in the presence of a catalyst. Hydrodesulfurizing: A process for combining hydrogen with the sulfur in refinery petroleum streams to make hydrogen sulfide, which is removed from the oil as a gas. Hydrogen: The lightest of all gases, the element (hydrogen) occurs chiefly in combination with oxygen in water. It also exists in acids, bases, alcohols, petroleum and other hydrocarbons. Hydrogen Consumption: The amount of hydrogen that is consumed in a hydrocracking or hydrotreating process, usually expressed on per unit of feed basis. Hydrogen may be consumed in chemical reactions and dissolved and lost from the process in the liquid hydrocarbon products. Hydrogen Embrittlement: A corrosion mechanism in which atomic hydrogen enters between the grains of the steel and causes the steel to become very brittle. Hydrogen-Induced Cracking: Stepwise internal cracks that connect hydrogen blisters. Hydrogen Sulfide: 1. “Rotten egg gas”, H2S. It is responsible for the distinctive odor of Rotorua. 2. An objectionable impurity present in some natural gas and crude oils and formed during the refining of sulfurcontaining oils. It is removed from products by various treatment methods at the refining. 3. Hydrogen sulfide is a gas with a rotten egg odor. This gas is produced under anaerobic conditions. Hydrogen sulfide gas is particularly dangerous because it dulls the sense of smell so that one does not notice it after one has been around it for a while. In high concentrations, hydrogen sulfide gas is only noticeable for a very short time before it dulls the sense of smell. The gas is very poisonous to the respiratory system, explosive, flammable, colorless and heavier than air. 4. A toxic, corrosive, colorless gas with the characteristic smell of rotten eggs in low concentration. An acid gas.

Hydrogen Sulfide Cracking: Minute cracking just under a metal’s surface caused by exposure to hydrogen sulfide gas. Hydrogenation: 1. Filling in with hydrogen the “free” places around the double bonds in an unsaturated hydrocarbon molecule. 2. A refinery process in which hydrogen is added to the molecules of unsaturated hydrocarbon fractions. Hydrofining: A process of treating petroleum fractions and unfinished oils in the presence of catalysts and substantial quantities of hydrogen to upgrade their quality. Hydroforming: A process in which naphtha is passed over a solid catalyst at elevated temperature and moderate pressures in the presence of added hydrogen to obtain high-octane motor fuels. Hydroskimming Refinery: A topping refinery with a catalytic reformer. Hydrostatic Pressure: Pressure created by a column of fluid that expresses uniform pressure in all directions at a specific depth and fluid composition above the measurement point. Hydrotreating: 1. A refinery process to remove sulfur and nitrogen from crude oil and other feedstocks. 2. This is a term for a process by which product streams may be purified and otherwise be brought up to marketing specifications as to odor, color, stability, etc. 3. A process in which a hydrocarbon is subjected to heat and pressure in the presence of a catalyst to remove sulfur and other contaminants such as nitrogen and metals and in which some hydrogenation can take place. Hydrotreating for the removal of sulfur is the major treating process in refineries. Cracked streams could be saturated and stabilized by converting olefins, albeit under more severe treating conditions. The process involves hydrogen under suitable temperature, pressure and a catalyst. Hyperforming: A catalytic hydrogenation process used for improving the octane number of naphtha by the removal of sulfur and nitrogen compounds. H2/Oil Ratio and Recycle Gas Rate: The H2/oil ratio in standard cubic feet (scf) per barrel (bbl) is determined by H2 total hydrogen gas to the reactor, scf/day scf = [= ] bbl oil total feel to the reactor, bbl/day

Glossary of Petroleum and Technical Terminology  877 H2/oil ratio in m3/bbl is obtained by multiplying H2/ oil ratio in (scf/bbl) by a conversion factor 0.028317. A molar H2/oil ratio can be calculated from the volumetric H2/oil ratio by the following equation:

molar H2 oil

 H scf  MWoil rH2 = 1.78093 × 10 −7  2  oil bbl  MWH roil 2

where MWoil and MWH2 are the molecular weights of the oil to be hydrotreated and of hydrogen respectively, and oil and H are the densities of the oil and hydro2 gen (pH at 15°C and 1 atm. is 0.0898 kg/cm2). 2

Hypothetical State: Is defined as a fluid in a state that cannot actually exist, e.g., methane as a liquid at 60°F and 14.696 psia. Methane cannot be in its liquid phase at this temperature and pressure, but such a state when defined, can be used in calculations. Identification and Structural Group Analysis: The crude oil is a complex mixture of saturated hydrocarbons, saturated hetero-compounds, and aromatic hydrocarbons, olefinic hydrocarbons and aromatic hetero-compounds. With the advancement of the instrumental analysis techniques like chromatography and spectroscopic methods, now it has been possible to study in depth, the identification and structural group analysis. Some of the major analytical instruments used are gas chromatography, ion exchange chromatography, simulated distillation by gas chromatography, absorption chromatography, gel permeation chromatography, high-performance liquid chromatography and supercritical fluid chromatography. The application of spectroscopy, mass spectroscopy, electron spin resonance, X-ray diffraction, inductively coupled plasma emission spectroscopy, X-ray absorption spectroscopy and atomic absorption spectrophotometer. Initial boiling point (IBP): Initial boiling point of a cut, usually on an ASTM basis. The lowest temperature at which a petroleum product will begin to boil. The boiling temperature in a laboratory still at which the first drop of distilled liquid is condensed. The initial boiling point may be higher than the boiling point for light components in the sample that are not condensed by the apparatus. Ignition: The process of starting a combustion process through the input of energy. Ignition occurs when the temperature of a substance is raised to the point at which its molecules will react spontaneously with an oxidizer and combustion occurs.

Ignition Quality: Ignition quality is very important in the case of high-speed automotive diesel engines. The diesel engine knock, engine noise, smoke, gaseous emissions and so on, all depend upon this factor. Ignition quality is measured in terms of cetane number using an ASTM standard test engine. The test method designated as D613 comprises a single-cylinder engine with a variable compression ratio combustion pre-chamber. Incident: See Accident Independent Protection Layer (IPL): Protection measures that reduce the level of risk of a serious event to 100 times, which have a highly degree of availability (greater than 0.99) or have specificity, independence, dependability and auditability. Inerting: The process of removing an oxidizer (usually air or oxygen) to prevent a combustion process from occurring, normally accomplished by purging. Inflammable: Identical meaning as flammable, however the prefix “in” indicates a negative in many words and can cause confusion, therefore the use of flammable is preferred over inflammable. Inherently Safer: 1. A chemical process is inherently safer if it reduces or eliminates the hazards associated with materials and operations used in the process, and this reduction or elimination is permanent and inseparable. 2. An essential character of a process, system or equipment that makes it without or very low in hazard or risk. Inherent safety is a way of looking at processes in order to achieve this. There are four main keywords: • Minimize (Intensification): Reduce stocks of hazardous chemicals. • Substitute: Replace hazardous chemicals with less hazardous ones. • Moderate(Attenuation): Reduce the energy of the system – lower pressures and temperatures or adding stabilizing additives generally make for lower hazards. • Simplify: Make the plant and process simpler to design, build and operate, hence less prone to equipment control and human failings. Note: The principles of inherent safety are applied at conceptual design stage to the proposed process chemistry. In certain instances, these hazards cannot be avoided; they are basic properties of the materials and the conditions of usage. The inherently safer approach is to

878  Petroleum Refining Design and Application Handbook Volume 2 reduce the hazard by reducing the quantity of hazardous material, or energy or by completely eliminating the hazardous agent. Inherently Safer Design: Is a fundamentally different way of thinking about the design of chemical processes and plants. It focuses on the elimination or reduction of the hazards, rather than on management and control. This approach should result in safer and more robust processes, and it is likely that these inherently safer processes will also be more economical in due course. Instrument: Apparatus used in performing an action (typically found in instrumented systems). Note: Instrumented systems in the process sector typically composed of sensors (e.g., pressure, flow, temperature transmitters), logic solvers or control systems (e.g., programmable controllers, distributed control systems), and final elements (e.g., control valves). In special cases, instrumented systems can be safety instrumented systems. Internal Combustion Engine (ICE): Is a heat engine where the combustion of a fuel occurs with an oxidizer (usually air) in a combustion chamber that is an integral part of the working fluid flow circuit. In an internal combustion engine, the expansion of the high-temperature and high-pressure gases produced by combustion apply direct force to some component of the engine. The force is applied typically to pistons, turbine blades or a nozzle. This force moves the component over a distance transforming chemical energy into useful mechanical energy (See Figure 14). C E I

Crankshaft Exhaust camshaft Inlet camshaft E

S

I V

W P R C

Figure 14 Diagram of a cylinder as found in 4-stroke gasoline engines.

P R S V W

Piston Connecting rod Spark plug Valves. Red: exhaust, blue: intake Cooling water jacket Gray structure: Engine block.

Intrinsically Safe (IS): A circuit or device in which any spark or thermal effect is incapable of causing ignition of a mixture of flammable or combustible material in air under prescribed test conditions. IPTBE: Isopropyl tertiary butyl ether. An oxygenate used in motor fuels. Isocracking: A hydrocracking process for the conversion of hydrocarbons to more valuable lower boiling products by operation at relatively lower temperatures and pressures in the presence of hydrogen and catalyst. Isomerate: The product of an isomerization process. Isomerization: 1. A refining process, which alters the fundamental arrangement of atoms in the molecule without adding or removing anything from the original material. Used to convert normal butane into isobutane (iC4H10), an alkylation process feedstock, and normal pentane and hexane into isopentane (iC5H12) and isohexane (iC6H14) high-octane gasoline components. 2. The rearrangement of straight-chain hydrocarbon molecules to form branched-chain products. Pentanes and hexanes, which are difficult to reform are isomerized using precious metal catalysts to form gasoline blending components of fairly high octane value. Normal butane may be isomerized to provide a portion of the isobutene feed needed for alkylation processes. The objective of isomerization is to convert low-octane n-paraffins to high-octane i-paraffins by using a chloride-promoted fixed bed reactor. 3. Isomerization is the process by which one molecule is transformed into another molecule that has exactly the same atoms, but the atoms are rearranged. In some molecules and under some conditions, isomerization occurs spontaneously. Many isomers are equal or roughly equal in bond energy, and so exist in roughly equal amounts, provided that they can interconvert relatively freely, that is the energy barrier between the two isomers is not too high. When the isomerization occurs intermolecularly, it is considered a rearrangement reaction.

Glossary of Petroleum and Technical Terminology  879 Ph

Ph Ph Ph

Ph

Ph

Reflux

Ph

Fe

Xylene, 12 h

Fe+

Ph

Ph

Ph

Ph

Ph

Ph Ph Ph

Ph

Ph

Ph

Ph

Figure 15

H2 C

H2 C

H3C

C H2

CH3

C H2

H3C

H2 C

CH3

H2 C

H C

C H2

H3C

CH3

CH3

CH3

CH3

H2 C

H3C C H2

CH3

H C

CH3 H3C

CH3

C H

CH3

H C CH3

Figure 16

H H H H

H

H

H

H

H

H

H

C

C

C

C

C

C

C

C

H

H

H

H

H

H

H

H

H

Isomerization

H

C

H

H

H

H

H

C

C

C

C

C

C

H

H

H

H

H H

C

H H

H

H n - Octane (C8H18)

2, 5 Dimethylhexane

Figure 17

An example of an organometallic isomerization is the production of decaphenylferrocene, [(η5-C5 Ph5)2Fe] from its linkage isomer. Isomers: Two compounds composed of identical atoms, but with different structures/configurations giving different physical properties. For example,

hexane (C6H14) could be n-hexane, 2- methyl pentane, 3- methyl pentane, 2, 3-dimethyl butane, and 2, 2, - dimethylbutane. A simple example of isomerism is given by propanol. It has the formula C3H8O (or C3H7OH) and occurs as two isomers: propanol-1 – ol (n-propyl alcohol; II) and propanol- 2- ol (isopropyl alcohol; III)

880  Petroleum Refining Design and Application Handbook Volume 2 One methyl group on fourth carbon H H Two methyl group on second carbon

C

H H H

H

C

C

H H

C

H

H

C H

H

H H

C

C

C

H

H

H

H

Note that all the carbon-carbon bonds are single bonds.

Figure 18

Note that the position of the oxygen atom differs between the two: It is attached to an end carbon in the first isomer, and to the center carbon in the second. Isomerization of n-Octane to 2, 5 Dimethylhexane (See Figures 15, 16 and 17)

Joule Thompson expansion: The pressure of a mixture is reduced with no heat transfer to or from the surroundings. A pressure decrease typically results in a temperature decrease except for systems comprised largely of hydrogen gas.

Isooctane - 2, 2, 4 – Trimethlypentane: Also known as isooctane or iso-octane is an organic compound with the structure formula (CH3)3CCH2CH(CH3)2 It is one of several isomers of octane (C8H18). Engine knocking is an unwanted process that can occur during combustion in internal combustion engines. Graham Edgar in 1926 added different amounts of n- heptane and 2,2,4 – trimethylpentane to gasoline, and discovered that the knocking stopped when 2,2,4 trimethlypentane was added. Test motors, using 2,2,4 trimethylpentane gave a certain performance which was standardized as 100 octane. The same test motors, run in the same fashion, using heptane gave a performance which was standardized as 0 octane. All other compounds and blends of components then were graded against these two standards and assigned octane numbers. 2,2,4 trimethylpentane is the liquid used with normal heptanes (nC7H16) to measure the octane number of gasoline. It is an important component of gasoline, frequently used in relatively large proportions to increase the knock resistance of the fuel (See Figure 18).

Joule-Thompson Effect: 1. The change in temperature of a fluid that occurs when the fluid is allowed to expand in such a way that no external work is done and no heat transfer takes place. The case of most interest is cooling of a compressed gas upon J-T expansion. NB: the J-T effect is not limited to gases; J-T expansion can, in some cases, produce an increase in temperature rather than a decrease, although this is not frequently encountered. 2. Thermodynamic effect in a fluid whereby the reduction in its temperature is caused by pressure reduction without energy exchange with the environment. 3. When a real (not ideal) gas expands, the temperature of the gas drops. During passage of a gas through a choke, the internal energy is transferred to kinetic energy with a corresponding reduction in temperature as velocity increases. The effect for natural gas is approximately 7°F for every 100 psi pressure reduction.

Isopentane: See Natural Gasoline. IVT: Initial vaporization temperature of a cut, usually based on a crude assay distillation. Jack: An oil well pumping unit that operates with an up-and-down, or seesawing motion; also called a pumping jack. Jet fuel: A kerosene material of typical ASTM D86 boiling point range 400–550 °F (205–288 °C) used as a fuel for commercial jet aircraft.

Joule-Thompson Valve: A device which, taking an advantage of the Joule-Thompson effect enables the cooling of a fluid through throttling or reduction of its pressure. K factor: Sometimes used as synonym for characterization factor. K-value: Shortcut notation for the equilibrium K value. Kerogene: An initial stage of oil that never developed completely into crude. Typical of oil shales. Kerosene/Kerosine: 1. A medium range (C9 – C16) straight chain blend of hydrocarbons. The flash point is

Glossary of Petroleum and Technical Terminology  881 about 140°F (60°C), the boiling point is 345°F – 550°F (174°C – 288°C) and the density is 747–775 kg/m3. 2. A medium-light distillate from the oil refining process; used for lighting and heating and for the manufacture of fuel for jet and turboprop aircraft engines. 3. Any petroleum product with a boiling range between the approximate limits of 284°F and 518°F (140°C and 270°C), which satisfies a specific quantity requirements. 4. A middle distillate product material from distillation of crude oil that boils in the approximate ASTM D86 range of 400–550°F (205–288°C) or from thermal and catalytic cracking operations (coker, visbreaker, FCC, hydrocracker, etc.). The exact cut is determined by various specifications of the finished kerosene. 5. A light petroleum distillate that is used in space heaters, cook stoves, and water heaters and is suitable for use as a light source when burned in wick-fed lamps. Kerosene has a maximum distillation temperature of 400°F (204°C) at the 10% recovery point, a final boiling point of 572°F (300°C), and a minimum flash point of 100°F (38°C). Included are No. 1-K and No. 2 – K, the two grades recognized by the American Society of Testing Materials (ASTM) Specification D3699 as well as all other grades of kerosene called range or stove oil, which have properties similar to those of No. 1 fuel oil. It is colorless and has a characteristic odor and taste. Kerosene is insoluble in water, moderately soluble in alcohol and very soluble in ether, chloroform or benzene. Key Components: In a conventional distillation column with two products, two components or groups of components that define the separation. Both components must be distributed to the top and bottom products. The light key appears in the bottom product in a small significant quantity and the heavy key appears in the top product in small significant quantity. Kinematic viscosity: Viscosity in centipoises (cP) divided by the liquid density at the same temperature gives kinematic viscosity in centistokes (cS) (100 cSt = 1 stoke). Water is the primary viscosity standard with an accepted viscosity at 20°C of 0.01002 poise. Kinematic viscosity is usually determined by the flow of a substance between two points in a capillary tube.

K inematic viscosity =

Dynamic viscosity

Density of fluid m v= r

, cSt

Kinetic: The word “kinetic” is derived from the Greek word for “motion”. In chemistry, kinetics is the study of how fast reactions occur. In many chemical reactions where there are a number of possible products, the first product formed may be the one that is formed most quickly, not necessarily the one that is most stable; if the reaction is left to proceed, eventually a product is formed that involves the greatest change in bond energy – the thermodynamic product. Knock: 1. The sound associated with the auto ignition in the combustion chamber of an automobile engine of a portion of the fuel-air mixture ahead of the advancing flame front. 2. The noise associated with premature ignition of the fuel-air mixture in the combustion chamber; also known as detonation or pinking. Knocking (Knock, Detonation, Spark knock, Pinging or Pinking): In spark-ignition internal combustion engines occurs when combustion of the air/ fuel mixture in the cylinder does not start off correctly in response to ignition by the spark plug, but one or more pockets of air/fuel mixture explode outside the envelope of the normal combustion front. See also Engine Knocking. Knocking is more or less unavoidable in diesel engines, where fuel is injected into highly compressed air towards the end of the compression stroke. There is a short lag between the fuel being injected and combustion starting. By this time there is already a quantity of fuel in the combustion chamber which will ignite first in areas of greater oxygen density prior to the combustion of the complete charge. This sudden increase in pressure and temperature causes the distinctive diesel “knock” or “clatter”, some of which must be allowed for in the engine design. Careful design of the injector pump, fuel injector, combustion chamber, piston crown and cylinder head can reduce knocking greatly, and modern engines using electronic common rail injection have very low levels of knock. Engines using indirect injection generally have lower levels of knock than direct injection engine, due to the greater dispersal of oxygen in the combustion chamber and lower injection pressures providing more complete mixing of fuel and air. Knocking should not be confused with pre-ignition – they are two separate events. However, pre-ignition is usually followed by knocking. See Pre-ignition. Knockout: A separator used to remove excess gas or water from the produced fluid stream. Knockout Drum: A vessel wherein suspended liquid is separated from gas or vapor.

882  Petroleum Refining Design and Application Handbook Volume 2 Laminar flow: The streamline flow of a fluid in which a fluid flows without fluctuations or turbulence. The velocities of fluid molecules are in the direction of flow with only minor movement across the streamlines caused by molecular diffusion. The existence was first demonstrated by Osborne Reynolds who injected a trace of colored fluid into a flow of water in a glass pipe. At low flow rates, the colored fluid was observed to remain as discrete filaments along the tube axis, indicating flow in parallel streams. At increased flow rates, oscillations were observed in the filaments, which eventually broke up and dispersed across the tube. There appeared to be a critical point for a particular tube and fluid above which the oscillations occurred. By varying the various parameters, Reynolds showed that the results could be correlated into terms of a dimensionless number called the Reynolds number, Re. This is expressed by:

Re =

r vd m

where ρ is the density of the fluid, v is the velocity of the fluid, d is the inside diameter of the pipe, and µ is the fluid viscosity. The critical value of Re for the break-up of laminar flow in the pipes of circular cross-section is about 2000. LCGO: Light coker gas oil. Leaded Gasoline: A gasoline that has TEL (tetraethyl lead) added to boost the octane number. Lean Oil: The absorption oil entering the top tray of an absorber column. Lease Condensate: A mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas liquids, such as propane and butane, which are recovered at downstream natural gas processing plants or facilities. See also Natural Gas Liquids. LHSV: Liquid hour space velocity, volume of feed per hour per volume of catalyst. LHV: Lower heating value of fuels (net heat of combustion). The heat produced by complete oxidation of materials at 60°F (25°C) to carbon dioxide and water vapor at 60°F (25°C). Light Cycle Oil (LCO): Gas oil produced in a catalytic cracking operation that boils in the approximate ASTM D86 range of 400–695 °F (205–369°C).

Light Ends: Hydrocarbon fractions in the butane (C4H10) and lighter boiling range. Light Gas Oils: Liquid petroleum distillates heavier than naphtha, with an approximate boiling range from 401–650°F (205–343°C). Light key: A distributed component in a distillation section that is recovered in the top light product, with a small specified amount leaving the bottoms product. Light oil: Generally gasoline, kerosene and distillate fuels. Light Straight Run (LSR): The low-boiling naphtha stream from the atmospheric distillation, usually composed of pentanes and hexanes. Liquefaction: 1. The process by which gaseous natural gas is converted into liquid natural gas. 2. Physical process of gas to liquid that is condensation. For natural gas, this process requires cryogenic temperature since it is impossible to liquefy methane – main component of natural gas – at a temperature above-117°F (-82.6°C), which is its critical temperature. Liquefaction of Gases: Any process in which a gas is converted from its gaseous into liquid phase. Liquefaction Plant: Industrial complex that processes natural gas into LNG by removing contaminants and cooling the natural gas into its condensation. Liquefaction Unit or Liquefaction Train: Equipment that processes purified natural gas and brings it to liquid state. Natural gas has been purified in the pretreatment unit before cooling and liquefying it. Liquefied Natural Gas (LNG): 1. Natural gas that has been refrigerated to temperatures at which it exists in a liquid state. 2. An odorless, colorless, noncorrosive and non-toxic product of natural gas consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure. 3. Natural gas liquefied either by refrigeration or by pressure to facilitate storage or transportation. 4. A liquid composed of chiefly of natural gas (e.g., mostly methane, CH4). Natural gas is liquefied to make it easy to transport if a pipeline is not feasible (e.g., as across a body of water). LNG must be put under low temperature and high pressure or under extremely low (cryogenic) temperature and close to atmospheric pressure to liquefy. 5. Natural gas mainly methane refrigerated to reach liquid phase suitable for transportation in specialized vessels. 6. Natural gas that has been cooled to -26°F (-32°C) and converted into a liquid so that

Glossary of Petroleum and Technical Terminology  883 its volume will be reduced for transportation. 7. Hydrocarbons mixture, predominantly methane, kept in liquid state at a temperature below its boiling point. 8. Methane that has been compressed and cooled to the liquefaction point for shipping. Liquefied Petroleum Gas (LPG): 1. Gaseous hydrocarbons at normal temperatures and pressures but that readily turns into liquids under moderate pressure at normal temperatures, i.e., propane, (C3H8) and butane (C4H10). 2. Butane and propane mixture, separated from well fluid stream. LPG can be transported under pressure in refrigerated vessels (LPG carriers). 3. A mixture of propane and butane, and other light hydrocarbons derived from refining crude oil. At normal temperatures, it is a gas, but it can be cooled or subjected to pressure to facilitate storage and transportation. 4. of the gaseous hydrocarbons, propanes and butanes can be liquefied under relatively low pressure and at ambient temperature. Mixtures of these are known as LPG. 5. A mixture of propane, propylene, butane and butylenes. When compressed moderately at normal temperature, it becomes a liquid. It is obtained as light ends from fractionation of crude oil. It has a good caloric value; it is used as cooking fuel; because LPG has no natural odor, a distinctive odorant is added so that it will be noticeable should a leak occur. 6. Light ends, usually C3 and C4 gases liquefied for storage and transport. 7. Propane, propylene, normal butane, butylenes, isobutane and isobutylene produced at refineries or natural gas processing plant (includes plants that fractionate raw natural gas plant liquids). 8. A group of hydrocarbonsbased gases derived from crude oil refining or natural gas fractionation. They include ethane, ethylene, propane, propylene, normal butane, butylenes, isobutane and isobutylene. For convenience of transportation, these gases are liquefied through pressurization. Liquefied Refinery Gases: Liquefied petroleum gases fractionated from refinery or still gases. Through compression and/or refrigeration, they are retained in liquid state. The reported categories are ethane/ ethylene, propane/propylene, normal butane/butylene and isobutane/isobutylene. Liquid Extraction: Light and heavy liquid phases are contacted in a column with contact surfaces and possibly mixing. Some components are transferred (extracted) from one liquid phase to the other. Lock-Out-Tag-Out (LOTO): Refers to a program to control hazardous energy during the servicing and

maintenance of machinery and equipment. Lock-out refers to the placement of a locking mechanism on energy-isolating device, such as a valve, so that the equipment cannot be operated until the mechanism is removed. Tag-out refers to the secure placement of a tag on energy-isolating device to indicate that the equipment cannot be operated until the tag is removed. Long Residue: The bottoms stream from the atmospheric distillation tower. Long-term exposure limit (LTEL): The timeweighted average concentration of a substance over an 8-h period thought not to be injurious to health. Lower Explosive Limit (LEL): The minimum concentration of combustible gas or vapor in air below which propagation of flame does not occur on contact with an ignition source. Also known as the lower flammable limit or the lower explosion limit. Low Pressure (LP): A processing unit operating at less than 225 psig measured at the outlet separator. Lubricants: Substances used to reduce friction between bearing surfaces or as process materials either incorporated into other materials used as processing aids in the manufacture of other products, or used as carriers of other materials. Petroleum lubricants may be produced either from distillates or residues. Lubricants include all grades of lubricating oils from spindle oil to cylinder oil and those used in greases. Light Vacuum Gas Oil (LVGO): A side stream from the vacuum distillation tower. Make Up Stream: A feed to a process to replace a component that reacts or is otherwise depleted in a process. Main Cryogenic Heat Exchanger: Main heat exchanger in the liquefaction unit where cooling and liquefaction of natural gas take place by means of heat exchange with cooling fluids. Main Fractionators: The first distillation column for a FCC or coking process. Main Line: Branch or lateral sewers that collect wastewater from building sewers and service lines. Main Sewers: A sewer that receives wastewater from many tributary branches and sewer lines and serves as an outlet for a large territory or is used to feed an intercepting sewer.

884  Petroleum Refining Design and Application Handbook Volume 2 Management of Change (MOC): 1. A process to understand all the implications of a change to a procedure. 2. A process for evaluating and controlling hazards that may be introduced during modifications to facility, equipment, operations, personnel or activities; MOCs can also be used to identify, evaluate and control unintended hazards introduced by modifying procedures or when developing a new plan or procedure. Manhole: An opening in a sewer provided for the purpose of permitting operators or equipment to enter or leave a sewer. Sometimes called an “access hole” or a “maintenance hole”. Manifold(s): 1. A junction or center for connecting several pipes and selectively routing the flow. 2. A pipe spool in which a number of incoming pipes are combined to feed to a common output line. Manometer: Instrument for measuring head or pressure; basically a U-tube partially filled with a liquid, so constructed that the difference in level of the liquid leg indicates the pressure exerted on the instrument. MAOP: See Maximum allowable operating pressure. Mass Balance: Summation of the mass entering a process and the summation of the mass leaving a process. They must equal for a steady-state process. Material Safety Data Sheet (MSDS): 1. A description of the Health, Safety and Environment (HSE) data for a marketed product. 2. Printed information that describes the properties of a hazardous chemical and ways to control its hazards. 3. A document that provides pertinent information and a profile of a particular hazardous substance or mixture. An MSDS is normally developed by the manufacturer or formulator of the hazardous substance or mixture. The MSDS is required to be made available to employees and operators whenever there is the likelihood of the hazardous substance or mixture being introduced into the workplace. MAWP: See Maximum allowable working pressure. Maximum Allowable Operating Pressure (MAOP): The maximum gas pressure at which a pipeline system or process facility is allowed to operate. Maximum Allowable Working Pressure (MAWP): 1. This is a legal maximum pressure that a process vessel is allowed to experience. Above this pressure, a relief valve should open to protect the vessel from catastrophic failure. 2. The maximum pressure to which a surface

vessel can be operated or the maximum pressure during treating to which a well should be exposed. Mechanical Seal: This is the part of a centrifugal pump that keeps the liquid from squirting out along the shaft. It is often subject to leakage due to pump vibration and cavitation. Melting Point: The temperature at which a solid turns into a liquid. As temperature is a measure of the kinetic energy of molecules (i.e., how much they are moving around), this means that the molecules are moving too much to stay in one place. Mercaptans: 1. Compounds of carbon, hydrogen, and sulfur (RSH, R = CH3) found in sour crude and gas; the lower mercaptans have a strong, repulsive odor and are used, among other things to odorize natural gas. 2. A class of compounds containing carbon, hydrogen, and sulfur. The shorter chain materials are used as odor marker in natural gas. 3. Organic sulfides of the formula RSH where R represents the organic radical and SH represents the thiol group. Methane (CH4): A light odorless flammable gas that is the principal component of natural gas. Methanol (CH3OH): Methyl alcohol from the general formula (ROH), where R = CnH2n+1 is known as a radical and n = 1, 2, 3, etc. Methanol can be made by the destructive distillation of wood or through a process starting with methane or a heavier hydrocarbon, decomposing it to synthesis gas and recombining it to methanol. Methyl Tertiary Butyl Ether (MTBE, (CH3)3COCH3): 1. Is manufactured by etherification of methanol and isobutylene. Methanol is derived from natural gas and isobutylene is derived from butane obtained from crude oil and natural gas. 2. A gasoline additive used to increase octane number. MTBE is produced by reacting methanol (CH3OH) with isobutylene (iC4H8). 3. Blends up to 15.0% by volume of MTBE which must meet the ASTM D4814 specifications. Blenders must take precautions that the blends are not used as base gasolines for other oxygenated blends (commonly referred to as the “Sun waiver”). An ether intended for gasoline blending as described in oxygenate definition. In the U.S. it has been used in gasoline at low levels since 1979 to replace tetraethyl lead and to increase its octane rating helping prevent engine knocking. Oxygenates help gasoline burn more completely, reducing tailpipe emissions

Glossary of Petroleum and Technical Terminology  885 from pre-1984 motor vehicles; dilutes or displaces gasoline components such as aromatics (e.g., benzene) and sulfur; and optimizes the oxidation during combustion. Most refiners chose MTBE over other oxygenates primarily for its blending characteristics and low cost. Middle Distillates: Atmospheric pipe still cuts boiling in the range of 300 - 700°F (149 - 371°C) vaporization temperature. The exact cut is determined by the specifications of the product. 1. A general classification of refined petroleum products that include distillate fuel oil and kerosene. 2. Medium-density refined petroleum products, including kerosene, stove oil, jet fuel and light fuel oil. 3. Refinery products in the middle distillation range of refined products: kerosene, heating oil and jet fuel. Mid-Percent Point: The vapor temperature at which one half of the material of a cut has been vaporized. Mid-percent point is used to characterize a cut in place of temperature limits. Mixed Phase: More than one phase. Usually implies both vapor and liquid phase(s) present. Molecular Sieve: A separation process that usually works by gaseous diffusion. A membrane is selected through which the compounds being removed or purified can pass while the remaining compounds in the stream being processed cannot pass. MONC: Motor octane number clear (unleaded). Motor Octane Number (MON, ASTM ON F2): A measure of resistance to self-ignition (knocking) of a gasoline under laboratory conditions that correlates with road performance during highway driving conditions. The percentage by volume of isooctane in a mixture of isooctane and n-heptane that knocks with the same intensity as the fuel being tested. A standardized test engine operating under standardized conditions (900 rpm) is used. This test approximates cruising conditions of an automobile; ASTM D – 2723. MPHC: Medium pressure hydrocracking or partial conversion hydrocracking. Motor Gasoline or Petrol: Gasoline is a volatile, flammable, complex petroleum fuel used mainly in internal combustion engines. It is used as fuel in specially designed heaters and lamps. Motor Gasoline Blending: 1. Naphthas (e.g., straight-run gasoline, alkylate, reformate, benzene, toluene, xylenes) used for blending or compounding

into finished motor gasoline. Includes receipts and inputs of Gasoline Treated as Blendstock (GTAB). Excludes conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending, oxygenates (e.g., fuel ethanol and methyl tertiary butyl ether), butane, and natural gasoline. 2. Mechanical mixing of motor gasoline blending components, and oxygenates when required, to produce finished motor gasoline. Finished motor gasoline may be further mixed with other motor gasoline blending components or oxygenates, resulting in increased volumes of finished motor gasoline and/or changes in the formulation of finished motor gasoline (e.g., conventional motor gasoline mixed with MTBE to produce oxygenated motor gasoline). Motor Gasoline Blending Components: Naphthas (e.g., straight-run gasoline, alkylate, reformate, benzene, toluene, xylene) used for blending or compounding into finished motor gasoline. These components include reformulated gasoline blendstock for oxygenate blending (RBOB), but exclude oxygenates (alcohols, ethers), butane and pentanes plus. Motor gasoline (finished): A complex mixture of relatively volatile hydrocarbons with or without small quantities of additives, blended to form a fuel suitable for use in spark-ignition engines. Motor gasoline as defined in ASTM Specification D4814 or Federal Specification VV – G – 1690C, is characterized as having boiling range of 122°F to 158°F (50°C to 70°C) at the 10% recovery point to 365°F to 374°F (185°C to 190°C) at the 90% recovery point. “Motor gasoline” includes conventional gasoline; all types of oxygenated gasoline, including gasohol; and reformulated gasoline but excludes aviation gasoline Naphtha: 1. Straight-run gasoline distillate, below the boiling point of kerosene. Naphthas are generally unsuitable for blending as a component of premium gasoline; hence they are used as a feedstock for catalytic reforming in hydrocarbon production processes or in chemical manufacturing processes. 2. A term that is applied to low boiling mixtures of hydrocarbons with typical TBP boiling ranges between 150–450°F (66–233°C). Light and heavy naphthas are produced in the distillation of crude oils. Cracked naphthas are also produced by many of the refinery reaction processes. Naphthas are subdivided according to the actual pipe still cuts – into light, intermediate and heavy and very heavy virgin naphthas. A typical pipe still operation would be

886  Petroleum Refining Design and Application Handbook Volume 2 C5–160°F (C5–71°C): light virgin naphtha 160–280°F (71–138°C): intermediate virgin naphtha 280–380°F (138–193°C): heavy virgin naphtha Naphtha, the major constituents of gasoline, generally needs processing to make a suitable quality gasoline. Naphtha less than 401oF: A naphtha with a boiling range of less than 401°F (205°C) that is intended for use as a petrochemical feedstock. Naphtha-Type Jet Fuel: A fuel in the heavy naphtha boiling range having an average gravity of 52.8 °API, 20 to 90 percent distillation temperature of 290–470°F (143–243°C) and meeting Military Specification MIL – T- 5624L (Grade JP – 4). It is used primarily for military turbojet and turboprop aircraft engines because it has a lower freeze point than other aviation fuels and meets engine requirements at high altitudes and speeds. Special Naphthas: All finished products within the naphtha boiling range that are used as paint thinners, cleaners, or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D 1836 and D484, respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline and synthetic natural gas (SNG) feedstocks are excluded. Naphthenes: Hydrocarbons of the cyclane family, sometimes called cycloalkanes. Naphthenes have no double bonds and are saturated ring structures with the general formula CnH2n, where C = carbon atoms, H = hydrogen atoms, and n = 6, 7, 8, … Naphthenic: Having the characteristics of naphthenes, saturated hydrocarbons whose molecules contain at least one closed ring of carbon atoms. Naphthenic Acids: Organic acids occurring in petroleum that contain a naphthenic ring and one or more carboxylic acid groups. Naphthenic acids are used in the manufacture of paint driers and industrial soaps. Naphthenic Crudes: A type of crude petroleum containing a relatively large proportion of naphthenictype hydrocarbon. Natural Gas: Naturally occurring gas consisting predominantly of methane, sometimes in conjunction with crude (associated gas) and sometimes alone (unassociated gas). 1. A mixture of light hydrocarbons found naturally in the Earth’s crust, often in association with oil (when it is known as associated gas). Methane is the

most dominant component. It may also include some short-chain hydrocarbons (ethane, propane, butane) that may be in gaseous state at standard conditions. 2. A mixture of hydrocarbon compounds and small quantities of various non-hydrocarbons existing in the gaseous phase or in solution with crude oil in natural underground reservoirs at reservoir conditions. The primary constituent compound is CH4. Gas coming from wells also can contain significant amounts of ethane (C2H6), propane (C3H8), butane (C4H10) and pentanes (C5H12) and widely varying amounts of carbon dioxide (CO2) and nitrogen (N2). Natural Gas Heating Value: The amount of thermal energy released by the complete combustion of one standard cubic foot of natural gas. Natural Gas Liquids (NGL): 1. Liquid hydrocarbons, such as ethane, propane, butane, pentane, and natural gasoline, extracted from field natural gas. 2. Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods of gas processing or cycling plants. Generally, such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane. See Natural gas plant liquids and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities. 3. Liquids obtained during natural gas production that include ethane, propane, butanes and condensate. Natural Gasoline: A gasoline range product separated at a location near the point of production from natural gas streams and used as a gasoline blending component. Natural Gasoline and Isopentane: A mixture of hydrocarbons, mostly pentanes and heavier, extracted from natural gas, that meets vapor pressure, end point and other specifications for natural gasoline set by the Gas Processors Association. Includes isopentane that is a saturated branch-chain hydrocarbon (iC5H12), obtained by fractionation of natural gasoline or isomerization of normal pentane (nC5H12). Natural Gas Plant Liquids: Those hydrocarbons in natural gas that are separated as liquids at natural gas processing plants, fractionating and cycling plants, and in some instances, field facilities. Lease condensate is excluded. Products obtained include ethane, liquefied

Glossary of Petroleum and Technical Terminology  887 petroleum gases (propane, butanes, propane-butane mixtures, ethane-propane mixtures), isopentane, and other small quantities of finished products, such as motor gasoline, special naphthas, jet fuel, kerosene and distillate fuel oil. Natural Gas Processing: 1. The purification of field gas at natural gas processing plants (or gas plants) or the fractionation of mixed NGLs to natural gas products to meet specifications for use of pipeline-quality gas. Gas processing includes removing liquids, solids and vapors absorbing impurities and odorizing. 2. The process of separating natural gas liquids (NGLs) by absorption, adsorption, refrigeration, or cryogenics from a steam of natural gas. Natural Gas Processing Plant: Facilities designed to recover natural gas liquids from a stream of natural gas that may or may not have passed through lease separators and/or field separation facilities. These facilities control the quality of the natural gas to be marketed. Cycling plants are classified as gas processing plants. Net Heating Value: is the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as vapor. The net heating is an ideal gas property in a hypothetical state (the water cannot all remain vapor because, after the water saturates the CO2 in the products, the rest would condense). Net Positive Suction Head (NPSH): The net positive suction head required to keep a centrifugal pump from cavitating. Cooling a liquid in a pump’s suction line increases the pump’s available NPSH, as does increasing the liquid level in the suction drum. Nonassociated gas: Natural gas that exists in a reservoir alone and is produced without any crude oil. Normal boiling point: See boiling point. Nusselt number (Nu): A dimensionless number Nu is used in heat transfer calculations characterizing the relation between the convective heat transfer of the boundary layer of a fluid and its thermal conductivity.

Nu =

hd k

Where h is the surface heat transfer coefficient, d is the thickness of the fluid film, and k is the thermal conductivity.

Octane (C8H18): 1. Is a hydrocarbon and an alkane withthechemicalformulaC8H18, and thecondensed structural formula CH3(CH2)6CH3. Octane has many structural isomers that differ by the amount and location of branching in the carbon chain. One of the isomers, 2, 2, 4 – trimethylpentane (isooctane) (CH3)3CCH2CH(CH3)2 H

H C H

H

H C

H

C H

C

H

H C H

H

H C

C H

H

H C H

H

is used as one of the

H

standard values in the octane rating scale. Octane is a component of gasoline (petrol). As with all low molecular weight hydrocarbons, octane is volatile and very flammable. 2. A test used to measure the suitability of a gasoline as motor fuel. The octane test determines the knocking characteristics of a gasoline in a standard test engine relative to a standard of 2-2-4 trimethyl pentane (2 2 4 TMP). 2 2 4 TMP is assigned an octane number of 100.0. There are two octane tests. One is designated the research octane (F-1) and the second as the motor octane (F-2). Motor octane is determined in an engine more representative of actual operating conditions for automobiles and is lower than research octane for any gasoline stock. Historically, gasoline was marketed based on the F-1 octane, but in recent years, the average of the F-1 and F-2 octane has been used. At the gasoline pump, this is reported as (R + M)/2. The Research Octane Number (RON) test simulates driving mild conditions while the Motor Octane Number (MON) test simulates driving under more severe conditions, i.e., under load and at high speeds. The arithmetic average of RON and MON, which gives an indication of the performance of the engine under the full range of condition, is projected as Anti Knock Index (AKI), i.e. Anti Knock Index (AKI) = (RON + MON)/2. Octane Number: 1. Is a measure of the knocking characteristics of a fuel in a laboratory gasoline engine according to ASTM D2700. We determine the octane number of a fuel by measuring its knocking value compared to the knocking of a mixture of n-heptane and isooctane of 2-2-4 trimethylpentane (224 TMP). 2. An index measured by finding a blend of isooctane (iC8H18) and normal heptanes (nC7H16) that knocks under the identical conditions as the gasoline being evaluated. It is a measure of the ease of self-ignition of a fuel without the aid of a spark plug. 3. The octane number is a measure of the antiknock resistance of a gasoline. It is the percentage of iso-octane in a mixture of iso-octane and n-heptane, which gives a knock

888  Petroleum Refining Design and Application Handbook Volume 2 of the same intensity as the fuel being measured when compared in a standard engine. For example, if the fuel being tested matches in knocking to a blend of 90% iso-octane and 10% n-heptane, then the test fuel is said to have an octane number of 90. Iso-octane which produces the least knocking or which knocks only at a much higher compression ratio is given an octane number of 100, while n-heptane which is very poor in its resistance to knocking or which knocks at a much lower compression ratio is given an octane number of zero. CH3CH2-CH2-CH2-CH2-CH2-CH3

[Octane No = 0]

n-heptane

CH3

CH3

CH3-CH-CH2-CH-C-CH3

[Octane No = 100]

CH3 Iso-octane [2,2,4 -trimethyl pentane]

Generally, octane number increases as the degree of branching of the carbon chain increases and thus iso-paraffins are found to give higher octane numbers than the corresponding normal isomers. Olefins are found to give higher octane numbers than the related paraffins. Naphthenes also give better octane numbers than the corresponding normal paraffins. Aromatics usually exhibit high octane numbers. A single cylinder test engine is made to obtain the antiknock characteristics of gasoline in terms of octane numbers. The octane numbers formed a scale ranging

from 0 to 100; the higher the number the greater the antiknock characteristics. The scale has been extended above 100 by comparing the knocking intensity with iso-octane to which tetraethyl lead (TEL) is added. Numbers greater 100 on the scale are referred to as performance numbers rather than octane numbers. See also Motor Octane number and Research Octane number. Octane numbers are very relevant in the reforming, isomerization and alkylation processes in refining facilities. These processes enable the successful reactive transformations to yield long side chain paraffins and aromatics that possess higher octane numbers than the feed constituents which do not consist of higher quantities of constituents possessing straight chain paraffins and non-aromatics (naphthenes). It is a measure of the ease of self-ignition of a fuel without the aid of a spark plug. Octane Scale: A series of arbitrary numbers from 0 to 120.3 used to rate the octane number of gasoline. Three reference materials define the scale; n-heptane (Octane number = 0), isooctane (Octane number = 100), and isooctane plus six ml tetramethyl lead (Octane number = 120.3). Above 100, the octane number of a fuel is based on the engine ratings, in terms of ml of tetra ethyl lead in isooctane which matches that of the unknown fuel. Off Gas: The gas leaving a reflux drum or top tray of an absorber column. Off Line: When a process unit is shut down it is said to be off line.

Table 1 Octane numbers of pure hydrocarbons* Hydrocarbon

RON

MON

Hydrocarbon

RON

MON

n-pentane

61.7

61.9

2,4 – Dimethyl hexane

62.5

69.9

n-hexane

24.8

26.0

2,2,4 –Trimethyl pentane (iso-octane)

100.0

100.0

n-heptane

0.0

0.0

1 – Pentene

90.9

77.1

n-octane

–19.5

–15.0

1 – Octane

28.7

34.7

n-nonane

–17.0

–20.0

3 - Octene

72.5

68.1

2-methyl butane (Iso-pentane)

92.3

90.3

4 – Methyl – 1- Pentene

95.7

80.9

2 – Methyl hexane (Iso-heptane)

42.4

46.4

Benzene

–

114.8

2 – Methyl heptane (Iso-octane)

21.7

23.8

Toluene

120.1

103.5

*(Source: Speight, James G., The Chemistry & Technology of Petroleum, Marcel Dekker, Inc. 1991).

Glossary of Petroleum and Technical Terminology  889 Oil: One of the various liquid, viscid, usually inflammable, chemically neutral substances that is lighter and insoluble in water, but soluble in alcohol and ether and classified as non-volatile. Natural plant oils comprise terpenes and simple esters such as essential oils. Animal oils are glycerides of fatty acids. Mineral oils are mixtures of hydrocarbons. Oils have many uses and include fuels lubricants, soap constituents, vanishes, etc. Oil and gas: Refer to the industry associated with the recovery of liquid and gaseous hydrocarbons from underground deposits as reservoirs found both onshore and offshore around the world. A collection of localized deposits is known as an oil field or gas field. When they are drilled, they are known as oil and gas wells. Oil is mainly used as fuel for transportation purposes, whereas gas is primarily used as fuel for domestic and industrial purposes, and for converting into other chemicals such as plastic. Oil is widely transported in ships. Gas is transported in underground, sub-sea, or overland pipelines covering large distances. Oil refinery: An industrial process plant where crude oil is converted into useful products such as naphtha, diesel fuel, kerosene, and LPG. Also known as petroleum refinery, the process involves the separation of the crude oil into fraction in the process of fractional distillation. By boiling the crude oil, the light or more volatile components with the lowest boiling point rise towards the top of the column, whereas the heavy fractions with the highest boiling points remain at the bottom. The heavy bottom fractions are then thermally cracked to form more useful light products. All the fractions are then processed further in other parts of the oil refinery, which may typically feature vacuum distillation used to distill the bottoms; hydrotreating, which is used to remove sulfur from naphtha, catalytic cracking, fluid catalytic cracking, hydrocracking, visbreaking, isomerization, steam reforming, alkylation, hydrodesulfurization, and the Claus process used to convert hydrogen sulfide into sulfur, solvent dewaxing and water treatment. Olefins: Hydrocarbons of the alkenes family. Olefins have two carbon atoms in the molecular structure linked by a double bond to satisfy the absence of two hydrogen atoms that are present in the corresponding paraffin. This hydrogen deficiency is called unsaturation. The general formula for olefins is CnH2n, where C = carbon atoms, H = hydrogen atoms, and n = 2, 4, 6.

Olefins do not occur naturally in crude oil and are created in the thermal and catalytic cracking processes. Online: When a process unit is in operation and processing feed, it is said to be online. OPEC: Organization of Petroleum Exporting Countries. These countries have organized for the purpose of negotiating with oil companies on matters of oil production, prices and future concession rights. Current members are Algeria, Indonesia, Iran, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates and Venezuela. Operability Capacity: 1. The amount of capacity that, at the beginning of the period, is in operation; not in operation and not under active repair, but capable of being placed in operation within 30 days; or not in operation but under active repair that can be completed within 90 days. Operable capacity is the sum of the operating and idle capacity and is measured in barrels per calendar day or barrels per stream day. 2. The component of operable capacity that is operation at the beginning of the period. Operating Pressure: Pressure indicated by a gauge when the system is in normal operation (working pressure). Operation and Maintenance Manual: A manual that describes detailed procedures for operators to

1

2 Sharp edged orifice

Flow

Vena contracta

∆zm

Figure 19 Orifice Meter with Vena contracta formation.

890  Petroleum Refining Design and Application Handbook Volume 2 follow to operate and maintain specific water or wastewater treatment, pretreatment or process plants and the equipment of the plants.

wastewater collection systems, and wastewater treatment plants. OSHA also refers to the federal and state agencies that administer the OSHA regulations.

Operator: 1. Term used to describe a company appointed by venture stakeholders to take primary responsibility for day- to-day operations for a specific plant or activity. 2. The company or individual responsible for managing an exploration, development or production operation. 3. The company that has legal authority to drill wells and undertake the production of hydrocarbons that are found. The operator is often part of a consortium and acts on behalf of this consortium. 4. The company that makes the decisions and is responsible for drilling, completing, operating and repairing the well.

Oxidation: Oxidation is the addition of oxygen, removal of hydrogen, or the removal of electrons from an element or compound. In the environment, organic matter is oxidized to more stable substances. The opposite is the reduction.

Operable Utilization Rate: Represents the utilization of the atmospheric crude oil distillation units. The rate is calculated by dividing the gross input to these units by the operable refining capacity of the units. Organic Compounds: Compounds that include carbon and hydrogen atoms. Generally organic compounds can be classified as either aliphatics (straight chain compounds), cyclic (compounds with ring structures), and combinations of aliphatics and cyclic. Orifice: An opening in wall or plate used to control the rate of flow into or out of a tank or pipe. Orifice Meter: A single phase flow meter, primarily for gas that measures the pressure drop created by the hole as gas is flowed (See Figure 19). Orifice Plate: Part of an orifice metering system. A plate with a hole through which a single phase flow produces a pressure drop. Other Hydrocarbons: Materials received by a refinery and consumed as a raw material. Includes hydrogen, coal tar derivatives, gilsonite, and natural gas received by the refinery for reforming into hydrogen. Natural gas to be used as fuel is excluded. OSHA: 1. Occupational Safety and Health Administration: U.S. government agency. 2. The Williams-Steiger Occupational Safety and Health Act of 1970 (OSHA) is a federal law designed to protect the health and safety of industrial workers, including the operators of water supply and treatment systems and wastewater treatment plants. The Act regulates the design, construction, operation, and maintenance of water supply systems, water treatment plants,

Oxidation Inhibitor: A substance added in small quantities to a petroleum product to increase its oxidation resistance, thereby lengthening its service or storage life; also called an antioxidant. Oxidation of fuels creates gums which become colloidal, then agglomerate and precipitate. Cracked distillates are found more prone to oxidation and deterioration then straight run distillates. Oxidation fuels can also result in the formation of various acids, ketones, aldehydes and esters from hydrocarbons. Amino guanidine derivatives when used in the range 3–30 ppm are found effective as antioxidants. Cyclic borates of polymers alkanolamines are effective anti-oxidants even in the 10 ppm range. Oxidation Stability: 1. It is used for the evaluation of storage stability and resistance to oxidation as most of the oils, when exposed to air over time, react with oxygen, which are then degraded. Oil with poor oxidation stability, forms corrosive acids at high temperature condition in the engine. 2. Gasoline contains cracked components having tendency to form gum materials during storage and handling which affect performance. Oxidation stability provides an indication of the tendency of gasoline and aviation fuels to form gum in storage. In this test, the sample is oxidized inside a stainless steel pressure vessel initially charge with oxygen at 689 kPa and heated in a boiling water bath. The amount of time required for a specified drop in pressure (gasoline) or the amount of gum and precipitate formed after specific aging period (aviation fuel) is determined. Oxidizers: Reactants that oxidize, for example, bleach, chlorine, sodium hypochlorite, sodium persulfate. Also, a compound that releases oxygen. Oxidizing Agent: Any substance, such as oxygen (O2) or chlorine (Cl2) that will readily add (take on) electrons. The opposite is a reducing agent. Oxygen: A chemical element used by all known life forms for respiration.

Glossary of Petroleum and Technical Terminology  891 Oxygenated Fuel: Any organic compound containing oxygen. Specifically for the petroleum industry, this term refers to oxygen-containing organic compounds, such as ethers, and alcohols, added to fuels to reduce carbon monoxide in the engine exhausts. They are used as gasoline blending components. Oxygenated fuels tend to give a more complete combustion of its carbon into carbon dioxide (rather than monoxide), thereby reducing air pollution from exhaust emissions. Oxygenated Fuels Program Reformulated Gasoline: A reformulated gasoline that is intended for use in an oxygenated fuels program control area during an oxygenated fuels program control period. Oxygenated Gasoline: 1. Gasoline with an oxygen content of 1.8% or higher, by weight that has been formulated for use in motor vehicles. 2. Finished motor gasoline, other than reformulated gasoline, having an oxygen content 2.7% or higher by weight. It includes gasohol. Oxygenates: Substances that, when added to gasoline, increase the amount of oxygen in that gasoline blend, and thus boost the octane number of gasoline or petrol. Ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME) and methanol are common oxygenates. MTBE, ETBE, TAME have 1. Low water solubility, 2. Lower volatility and 3. Compatibility with hydrocarbon fuels. Overall Tray Efficiency: Overall tray efficiency can be defined as the number of theoretical trays in a distillation column section divided by the number of actual trays in the section and is reported as a percentage. Overall tray efficiencies are less than 100% for all refinery distillation columns. Overflash: The liquid that returns to the flash zone of a column. Overhead: Usually refers to the vapor leaving the top tray of a distillation column. For an absorber column the overhead and the top product are the same. Overlap: See Gap. Overpressure: Is any pressure relative to ambient pressure caused by an explosive blast, both positive and negative. Ozone (O3): An oxygen molecule with three oxygen atoms that occurs as a blue, harmful, pungent-smelling gas at room temperature. The stratosphere ozone layer,

which is a concentration of ozone molecules located at 6 to 30 miles above sea level, is in a state of dynamic equilibrium. Ultra violet radiation forms the ozone from oxygen but can also reduce the ozone back to oxygen. The process absorbs most of the ultraviolet radiation from the sun, shielding life from the harmful effects of radiation. Packed Bed Scrubber: Vertical or horizontal vessels, partially filled with packing or devices of large surface area, used for the continuous contact of liquid and gas such that absorption can take place. Frequently, the scrubber liquid or liquor has had chemicals added to react with the absorbed gas. Packing (Seals): Seals around a moving shaft or other equipment. Paraffins: 1. Hydrocarbons of the alkanes family. Paraffins are saturated compounds, i.e., hydrogen atoms are appropriately attached to the carbon atoms such that the carbon atoms have only single bonds in the molecular structure. General formula for paraffin is CnH2n+2, where C = carbon atoms, H = hydrogen atoms, and n = 1, 2, 3, 4, 5, …2. A white, odorless, tasteless, chemically inert, waxy substance derived from distilling petroleum; a crystalline, flammable substance composed of saturated hydrocarbons. 3. Normal or straight carbon chain alkanes with carbon chain lengths of C18+. The alkanes in this range solidify at temperatures from 80°F to over 200°F (27°C – 93°C). Partial Pressure: In a gaseous mixture, the pressure contribution for a particular component of the mixture. The sum of the partial pressures of the components in the mixture is the total pressure. For example, in a mixture of two components A and B, with partial pressures as pA, pB respectively. The total pressure pTotal is: PTotal = pA + pB. Penetration: A measure of the hardness and consistency of asphalt in terms of the depth that a special pointed device will penetrate the product in a set time and temperature. Performance Rating: A method of expressing the quality of a high-octane gasoline relative to isooctane. This rating is used for fuels that are of better quality than isooctane. Petroleum Administration for Defense Districts (PADD): Geographic aggregations of the 50 U.S.states and the District of Columbia into five districts by the Petroleum Administration for Defense in 1950. These

892  Petroleum Refining Design and Application Handbook Volume 2 districts were originally defined during World War II for purposes of administering oil allocation. Petroleum Coke: A residue high in carbon content and low in hydrogen that is the final product of thermal decomposition in the condensation process in cracking. This product is reported as marketable coke. The conversion is 5 barrels (of 42 U.S. gallons each) per short ton. Coke from petroleum has a heating value of 6.024 million Btu per barrel. Marketable coke: Those grades of coke produced in delayed or fluid cokers which may be recovered as relatively pure carbon. This “green” coke may be sold as is or further purified by calcining. Catalyst coke: The only catalytic coke used as a fuel is the coke on catalyst in the FCC process. In other catalytic processes there is coke deposited on catalyst, but it is not regenerated in a way such that the heat of combustion is recovered. Petrolatum: Microcrystalline wax or Petroleum jelly. Petroleum ether: A volatile fraction of petroleum consisting mainly pentanes and hexanes. Petrochemical Feedstocks: Chemical feedstocks derived from petroleum principally for the manufacture of chemicals, synthetic rubber, and a variety of plastics. These categories reported are “Naphthas less than 401°F and Other Oils Equal to or greater than 401°F”. Petroleum Products: Petroleum products are obtained from the processing of crude oil (including P Cricondenbar Critical point

Gaseous phase

Dew line Liquid phase Bubble line

Liquid - gaseous phase

Cricondentherm

Figure 20 Phase diagram (Phase Envelope).

T

lease condensate), natural gas, and other hydrocarbon compounds. Petroleum products include unfinished oils, liquefied petroleum gases, pentanes plus, aviation gasoline, motor gasoline, naphtha type jet fuel, kerosene-type jet fuel, kerosene, distillate fuel oil, residual fuel oil, petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt, road oil, still gas, and miscellaneous products. Phase Envelope: 1. The boundaries of an area on the P-T diagram for the material which encloses the region where both vapor and liquid coexist. 2. Phase diagram or phase envelope is a relation between temperature and pressure that shows the condition of equilibria between the different phases of chemical compounds, mixture of compounds, and solutions. Phase diagram is an important issue in chemical thermodynamics and hydrocarbon reservoir. It is very useful for process simulation, hydrocarbon reactor design, and petroleum engineering studies. It is constructed from the bubble line, dew line, and critical point. Bubble line and dew line are composed of bubble points and dew points, respectively. Bubble point is the first point at which the gas is formed when a liquid is heated. Meanwhile, dew point is the first point where the liquid is formed when the gas is cooled. Critical point is the point where all of the properties of gases and liquids are equal, such as temperature, pressure, amount of substance, and others. Critical point is very useful in fuel processing and dissolution of certain chemicals According to thermodynamic definition of phase diagram (phase envelope) is a graph showing the pressure at which transition of different phases from a compound with respect to temperature. Bubble point which forms bubble line is a point separating the liquid phase and the two phases region, namely the liquid phase and the gaseous phase. The dew point which forms the dew line is a point separating the gaseous phase and two phase region, namely the liquid and gaseous phase. At the dew point, the following conditions must be satisfied (See Figure 20). Physical Solvent: A liquid capable of absorbing selected gas components by solubility alone without associated chemical reactions. Pig: 1. A cylindrical device that is inserted into a pipeline to clean the pipeline wall or monitor the internal condition of the pipeline. 2. Device for cleaning a pipeline or separating two liquids being removed down the pipeline. (Intelligent pig – fitted with sensors to check for corrosion or defects in pipelines.).

Glossary of Petroleum and Technical Terminology  893

Hot utility target

Shift hot streams

Co ld

+

co m po sit e

−

Ho tc

−

Temperature

+

om po sit e

T

Temperature

QHmin

T

Shift cold streams Excess energy flow QCmin Cold utility target

Enthalpy

Enthalpy

H

(a) The plus-minus principle.

H

(b) Shifting streams through the pinch in the right direction enacts the plus-minus principle.

Figure 21 The plus-minus principle guides process design to reduce utility consumption (Source: Smith, R. and Linnhoff, B., Trans. IChemE ChERD, 66, 195, 1988).

3. A flow line clearing device, pumped through the line with normal flow. 4. Refers to a poly pig that is a bulletshaped device made of hard rubber or similar material. This device is used to clean pipes. It is inserted in one end of a pipe, moves through the pipe under pressure, and is removed from the other end of the pipe.

diameter but is usually 20–36 in (508–914 mm). It is often composed of 40 ft. (12 m) lengths, but lengths may be as long as 60 or 80 ft. (18–24 m). The pipe is wrapped and coated for protection against corrosion, especially since it runs underground. About half of all gases and oils are moved by pipeline.

Pinch analysis: Bodo Linnhoff at the University of Leeds in 1977 developed a technique for minimizing energy usage in a process. It is based on calculating the minimum energy consumption by optimizing the heat recovery, energy supply and process operating conditions. It uses process data represented as energy flows or streams as a function of heat load against temperature. These data are combined for all the hot and cold streams requiring heat. The point of closest approach between the hot and cold composite curves is called the pinch point and corresponds to the point where the design is most constrained. Using this point, the energy targets can be achieved using heat exchange to recover heat between the hot and cold streams in two separate systems, with one temperature above the pinch temperature and one for the temperature below the pinch temperatures. Figure 21 shows the point in a pinch analysis that corresponds to the point where the hot and cold streams in an integrated process are most constrained.

Pipe still: A heater or furnace containing tubes through which oil is pumped while being heated or vaporized. Pipe stills are fired with waste gas, natural gas or heavy oils, and by providing for rapid heating under conditions of high pressure and temperature, are useful for thermal cracking as well as distillation operations.

Pipelines: Tubular arrangement for the transportation of crude oil, refined products and natural gas from the well head, refinery and storage facility to the consumer. Pipeline measures 14–42 in. (356–1067 mm) in

Pipe size: Process piping comes in particular nominal sizes: 0.75 in. 1 in. 2 in. 2.5 in. 3 in, 4 in, 6 in. 8 in. 10 in.

25 mm 50 mm 80 mm 100 mm 150 mm 200 mm 250 mm

The nominal size does not refer either to the outside or the inside diameter of the pipe. Pipe thickness affects the ID.

894  Petroleum Refining Design and Application Handbook Volume 2 Flare PC 16

A Condenser E12

12 T1 16

CW 13

Distillation tower

BV002

1

Feed

T1 11

FC 11

Fuel gas PSV 18

FC 12

LC Rollux 18 drum

V11

A1 13 Vol % methanol

BV005

T1 12

11

B RV005

RV002

A1 14

T1 17

P11A

Vol % water

HS BV006 11A BV001

8

P01 12

P11B

9 RV001 A1 11 Vol % methanol A1 12 Vol % water

TC 13

T1 14

Rellux and tap product pumps

FC 13

17 LC 15

HS 11B

F1 18

14

BV003

Top product RV003

A1 Vol % methanol 15 A1 16

C11 LP steam E11

BV007

Reboiler T1 15

HS 12A

P12A

BV004

15

Vol % water

F1 15 Bottom product

RV004

BV008 P12A

HS 12B Bottom product pumps

Distill-binary EnVision Systems Inc, Rev2.3 May 03 Page 1 of 1

Figure 22 Piping and instrumentation diagram.

Piping and instrumentation diagram (P &ID): A schematic representation of the interconnecting pipelines and control systems for a process or part of a process (see Figure 22). Using a standard set of symbols for process equipment and controllers. It includes the layout of branches, reducers, valves, equipment, instrumentation and control interlocks. They also include process equipment names, numbers; process piping including sizes and identification; valves and their identification; flow directions, instrumentation, and designations; vents, drains, sampling lines, and flush lines. P & IDs are used to operate the process system, operators’ trainings as well as being used in plant maintenance and process modifications. At the design stage, they are useful in carrying out safety and

operations investigations such as Hazop. List of P & ID items are: • Instrumentation and designations • Mechanical equipment with names and numbers • All valves and their identifications • Process piping, sizes and identification • Miscellanea – vents, drains, special fittings, sampling lines, reducers, enlargers, and swagers • Permanent start-up and flush lines • Flow directions. • Interconnections references • Control inputs and outputs, interlocks • Interfaces for class changes

Glossary of Petroleum and Technical Terminology  895 • Computer control systems • Identification of components and subsystems. Polymerization: A reaction in which like molecules are joined together to form dimer and trimer compounds, etc., of the reactant(s). This most often occurs with olefinic compounds in oil refineries. The objective of a polymerization unit is to combine or polymerize the light olefins propylene and butylenes into molecules two or three times their original molecular weight. The feed to this process consists of light gaseous hydrocarbons (C3 and C4) produced by catalytic cracking, which are highly unsaturated. The polymer gasoline produced has octane numbers above 90. PONA Analysis: Analysis for paraffins (P), olefins (O), naphthenes (N), and aromatics (A). Method used is ASTM D 1319. Pour Point: 1. Is a measure of how easy or difficult to pump the crude oil, especially in cold weather. Specifically, the pour point is the lowest temperature at which a crude oil will flow or pour when it is chilled without disturbance at a controlled rate. The pour point of the whole crude or oil fractions boiling above 450°F (232°C) is determined by the standard test ASTM D97. Both pour and cloud points are important properties of the product streams as far as heavier products are concerned. For heavier products, they are specified in a desired range and this is achieved by blending appropriate amounts of lighter intermediate products. 2. The temperature at which oil starts to solidify and no longer flows freely. Pour point usually occurs 40 to 42°F (4.5 to 5.5°C) below the cloud points. A sample tube of petroleum oil is chilled in the pour point test. The pour point is defined as the temperature at which the sample will still pour (move) when the sample tube is tipped. The pour temperature is typically about 5°F (2.8°C) lower than the cloud point. Power Stroke: Is the downward motion of a piston that occurs after ignition as the fuel combusts and expands. ppmv: A volume concentration of a species in a bulk. Prandtl number (Pr): A dimensionless number, Pr representing the ratio of the momentum of diffusivity to thermal diffusivity in fluid convection.

Pr =

cpµ k

where cp is the specific heat, µ is the viscosity, and k is the thermal conduction.

Pre-Ignition: Describes the event when the air/fuel mixture in the cylinder ignites before the spark plug fires. Pre-ignition is initiated by an ignition source other than the spark, such as hot spots in the combustion chamber, a spark plug that runs too hot for the application, or carbonaceous deposits in the combustion chamber heated to incandescence by previous engine combustion events. It is a technically different phenomenon from engine knocking. The phenomenon is also referred to as ‘after-run’, or ‘run-on’ or sometimes dieseling, when it causes the engine to carry on running after the ignition is shut off. This effect is more readily achieved on carbureted gasoline engines, because the fuel supply to the carburetor is typically regulated by a passive mechanical float valve and fuel delivery can feasibly continue until fuel line pressure has been relieved, provided the fuel can be somehow drawn past the throttle plate. Pre-ignition and engine knock both sharply increase combustion chamber temperatures. Consequently, either effect increases the likelihood of the other effect occurring and both can produce similar effects from the operator’s perspective, such as rough engine operation or loss of performance due to operational intervention by a computer. See Knocking. Pre-Startup Safety Review (PSSR): Audit check performed prior to equipment operation to ensure adequate process safety management (PSM) activities have been performed. The check should verify (1) Construction and equipment is satisfactory, (2) Procedures are available and adequate, (3) A process hazard analysis (PHA) has been undertaken and recommendations resolved, (4) The employees are trained. Precursor: Compounds which are suitable or susceptible to specific conversion to another compound. e.g., methyl cyclopentane is a good precursor for making benzene in a catalytic reformer. Preheat, Preheat Train: Heat exchanger or network of heat exchangers in which the feed to a process (usually a distillation column) is heated by recovering heat from products being cooled. Pressure, Absolute: 1. The force applied over a given area. Instrument gauges used to measure the pressure of fluids are either expressed as absolute pressure, which is measured above a vacuum. 2. Gauge pressure plus barometric or atmospheric pressure. Absolute pressure can be zero only in a perfect vacuum. 3. The pressure

896  Petroleum Refining Design and Application Handbook Volume 2 2

due to the weight of the atmosphere (air and water vapor) on the Earth’s surface. The average atmospheric pressure at sea level has been defined as 14.69 lbf/in2 absolute.

where j g and jL2 are the pressure drop multipliers for the liquid and gas phases in which the parameters X2 is defined as:

Pressure, Atmospheric: 1. The pressure due to the weight of the atmosphere (air and water vapor) on the Earth’s surface. The average atmospheric pressure at sea level is 14.696 lbf/in2. absolute. 2. The pressure exerted by the atmosphere on a given point. It decreases as the elevation above sea level increases.

    dpL   2 0. 5   dz  L   j g  X=   = 2 dp   g   jL       dz   g  

Pressuring Agent: The hydrocarbon, usually butane used to bring gasoline blends up to an acceptable vapor pressure. Pressure drop: 1. The decrease in pressure between two points in a system caused by frictional losses of a moving fluid in a pipe or duct, or by some other resistance such as across a packed bed, a filter or catalyst, or due to the effects of hydrostatic head such as across the liquid on the tray of a distillation column. 2. Change in pressure with depth. Pressure drop multiplier (φ2): A parameter used in two-phase gas-liquid frictional pressure drop calculations where the overall pressure drop along a length of pipe is due to combination from the flowing gas and liquid. This is expressed by:

dp f

 dp g   dp  = jL2  L  = j2g    dz  L dz  dz  g

0.10

Parameter, Φ

0.01

ΦLtt ΦLvt ΦLtv ΦLvv

10

1 0.01

ΦGtv

ΦGtt ΦGvt ΦGvv

0.10 1.00 10.0 Martinelli parameter χ

Figure 23 Lockhart-Martinelli two-phase multiplier.

Pressure Integrity Test: A pressure test of a vessel formed by the entire well or part of a well. It usually measures the ability of a pressure vessel to hold pressure without leaking at a given pressure. Pressure, Negative: atmospheric.

A

pressure

less

than

Pressure Reducing Valve: Valve used to reduce a high supply pressure to a usable level.

Primary Absorber: The first absorber in a FCC gas plant.

100

Void fraction

εm

100

Pressure, Hydrostatic: The pressure, volume per unit area, exerted by a body of water at rest.

Pressure Relief Valve: A mechanical valve that opens at a preset pressure to relieve pressure in a vessel (See Figure 24). 1.00

1 - εm

Correlations have been developed to determine relationships for the multipliers for combinations of laminar and turbulent gas and liquid phases (See Figure 23).

Pretreatment: Group of processes that natural gas is subjected to prior to its liquefaction. Its purpose is to remove mainstream contaminants or compounds that may cause operational problems in the liquefaction unit. Pretreatment Facility: Industrial wastewater treatment plant consisting of one or more treatment devices designed to remove sufficient pollutants from wastewaters to allow an industry to comply with effluent limits established by the US EPA General and Categorical Pretreatment Regulations or locally derived prohibited discharge requirements and local effluent limits. Preventative Maintenance: Maintenance carried out prior to unit or system failure.

Glossary of Petroleum and Technical Terminology  897 Cap Spindle nut Adj. bolt bearing Forked lever Adjusting bolt Adj. bolt nut Lever

Cap Pressure screw Pressure screw nut Set screw

Spring washer Spring Spindle Bonnet

Spring washer Bonnet Spring

Guide Guide bearing Disc nut Disc holder Disc insert

Spring washer Spindle Wing valve

Guide (adj) ring Guide ring set screw

Body

Flow

Nozzle ring set screw Nozzle ring Nozzle Body

Figure 24 Relief valve Safety valve.

Preventive Maintenance: Regularly scheduled servicing of machinery or other equipment using appropriate tools, tests and lubricants. This type of maintenance can prolong the useful life of equipment and machinery and increase its efficiency by detecting and correcting problems before they cause a breakdown of the equipment. Probability: The likelihood that the impact or event will occur. Impact (or consequence) is the effect on conditions or people if the hazard is realized (occurs) in practice, and probability is the likelihood that the impact will occur. Risk is a function of probability and impact (consequence). With this discrete data, it is determined by taking the number of occurrences for the particular type of event being considered and dividing that by the total number of outcomes for the event. Expressed as a deterministic value (quantitative single value or high, medium, low, etc.) or as a range of values – that is, uncertainty – that is represented by a probability distribution. Probability Distribution (Risk): A mathematical relationship between the values and the associated probabilities for a variable across the entire range of possible values for that variable. Typically, probability distributions are displayed as frequency or cumulative frequency plots.

Probability Distillation: The characteristic shape of laboratory distillation boiling curves tends to follow the shape of a normal distribution function, especially the TBP method. Probability distillation paper is constructed with a probability scale for the boiling point scale and laboratory distillation curves may be plotted as straight lines on this paper. This provides a reasonable way to extrapolate partial laboratory distillation data. Process: Any activity or operation leading to a particular event. Process Flow Diagram (PFD): A schematic representation of a process or part of a process that converts raw materials to products through the various units operations (Figure 25). It typically uses a symbolic representation for the major items of equipment such as storage vessels, reactors, separators, process piping to and from the equipment, as well as bypass and recirculation lines, and the principal flow routes. Key temperatures and pressures corresponding to normal operation are included, as well as equipment ratings, minimum and maximum operational values. Material flows and compositions are included. It may also include important aspects of control and pumping, as well as any interaction with other process equipment or flows. The design duties or sizes of all the major equipment are also featured, which can collectively provide

898  Petroleum Refining Design and Application Handbook Volume 2

Figure 25 Process flow diagram (Feed and fuel desulfurization section).

a comprehensive representation of the process. PFDs generally do not include the following: • Pipe classes or piping line numbers • Process control instrumentation (sensors and final elements). • Minor bypass lines • Isolation and shutoff valves. • Maintenance vents and drains • Relief and safety valves • Flanges. Programmable Logic Controller (PLC): A digital electronic controller that uses computer based programmable memory for implementing operating instructions through digital or analog inputs and outputs. Process Hazard Analysis (PHA): An organized formal review to identify and evaluate hazards with industrial facilities and operations to enable their safe management. The review normally employs a qualitative technique to identify and access the importance of hazards as a result of identified consequences and

risks. Conclusions and recommendations are provided for risks that are deemed at a level not acceptable to the organization. Quantitative methods may be also employed to embellish the understanding of the consequences and risks that have been identified. Process Risk: Risk arising from the process conditions caused by abnormal events (including basic process control system (BPCS) malfunction. Note: The risk in this context is that associated with the specific hazardous event in which Safety Instrument Systems (SIS) are to be used to provide the necessary risk reduction (i.e., the risk associated with functional safety). Process Safety Management (PSM): Comprehensive set of plans, policies, procedures, practices, administrative, engineering and operating controls designed to ensure that barriers to major incidents are in place, in use and are effective. Processing Gain: The volumetric amount by which total output is greater than input for a given period of time. This difference is due to the processing of crude

Glossary of Petroleum and Technical Terminology  899 Detailed analysis

Preliminary scoping activities

Conceptual phase

Process design phase

• •

Interact with client Input

Clarify client requirements

Start

• • • •

Turndown Flexibility Site Other

• • •

Interact with client and project team

Technical proposal* Proposal guarantees Project design data Third-party proposals Project execution strategy

• • • • • •

Process Systems Analytical Control systems Plant layout Operations

Pinch specialist review interaction

Finalize process flow alignment

Interact with project team

Basic inputs • • • • •

Network designs Utility loads and levels

Update and finalize pinch analysis

Preliminary targets Unit interactions Conceptual utility systems

Conceptual pinch studies to set design basis

Detailed engineering phase

• • • • •

Process design activities • • • • • •

Flow diagrams Material balances Finalize heat balances Equipment loads Control strategy Utility balances

Detailed engineering activities • • • • • •

Stop

P & ID development Utility flow diagrams Plot plan development Hazard reviews Control system design Operating philosophy

Process Systems Plant layout Operations Cost services

* Includes base heat and material balance

Figure 26 This new process design work process implements process integration effectively. (Source: Stephen W. Morgan, “Use Process Integration to Improve Process Designs and the Design Process”, Chemical Engineering Process, p 62, September 1992 [5]).

oil into products which in total have a lower specific gravity than the crude oil being processed. Processing Loss: The volumetric amount by which total refinery output is less than input for a given period of time. This difference is due to the process of crude oil into products which in total have a higher specific gravity than the crude oil being processed. Production Capacity: The maximum amount of product that can be produced from processing facilities. Products Supplied: 1. Crude Oil: Crude oil burned on leases and by pipelines as fuel. 2. Approximately represents consumption of petroleum products because it measures the disappearance of these products from primary sources, i.e., refineries, natural gas processing plants, blending plants, pipelines, and bulk terminals. In general, product supplied of each product in any given period is computed as follows: field production, plus refinery production, plus imports, plus unaccounted for crude oil (plus net receipts when calculated on a PAD District basis), minus stock change, minus crude oil losses, minus refinery inputs, minus exports. Propane (C3H8): A hydrocarbon gas that is a principal constituent of the heating fuel. LPG. Propane is

Process ? Feed streams

Product streams

Figure 27 Process integration starts with the synthesis of a process to convert raw materials into desired products.

used extensively for domestic heating and as a feed to ethylene plants. Propylene (C3H6): A hydrocarbon in the olefin series resulting from olefin plant operations and refinery cracking processes and used as alkyl plant feed or chemical feedstock. Propylene (C3H6) (nonfuel use): Propylene that is intended for use in nonfuel applications such as petrochemical manufacturing. Nonfuel use propylene includes chemical-grade propylene, polymer-grade propylene, and trace amounts of propane. Nonfuel use propylene also includes the propylene component of

900  Petroleum Refining Design and Application Handbook Volume 2 propane/propylene mixes where the propylene will be separated from the mix in a propane/propylene splitting process. Excluded is the propylene component of propane/propylene mixes where the propylene component of the mix is intended for sale into the fuel market. Process design: The design of industrial process that uses physical, chemical or bio-chemical transformations for the production of useful products. It is used for the design of new processes, plant modifications, and revamps (Figure 26). It starts with conceptual and feasibility studies, and includes detailed material and energy balances, the production of block flow diagrams (BFDs), process flow diagrams (PFDs), engineering line diagrams (ELDs), and piping and instrumentation diagrams (P & IDs). It also includes the production of reports and document for plant construction, commissioning, start-up, operation and shut-down. The reports and documents are used by vendors, regulatory bodies, operators and other engineering disciplines. Process economics: An evaluation of a process in terms of all the costs that are involved. It considers the cost of raw materials and how they are processed, as well as the costs associated with waste processing such as recycling or disposal. It also includes the optimization of a process to best utilize materials and energy. The fixed costs of a process are not dependent on the rate of production, but the variable costs are and must be met by the revenue generated by sales. Taxes are deducted resulting in the net profit. Process engineer: He or she uses the principles of heat and material balances, hydraulics, vapor-liquid equilibrium, and chemistry to solve plant operating problems and optimize operating variables. Process integration: 1. A holistic approach used in process design that considers the process as a whole with the interactions between unit operations in comparison with the optimization of unit operations separately and independently. It is known as process synthesis (See Figure 27). 2. A technique used to minimize the energy consumption and heat recovery in a process. It is also known as process heat integration and pinch analysis (See Energy Management). Process intensification: An approach to engineering design, manufacture, and operation of processes that aims to substantially improve process performance through energy efficiency, cost effectiveness, reduction in waste, improvement in purification steps, reduction

of equipment size, increase in safety and operational simplicity. It involves a wide range of innovative reactor, mixing and separation technologies that can result in dramatic improvements in process performance. It involves an integrative approach that considers overall process objectives rather than the separate performance of individual unit operations; process intensification can enable a process to achieve its maximal performance leading to the development of cheaper, smaller, cleaner, safer, and sustainable technologies. Process plant: A collective name for an industrial facility used to convert raw materials into useful products. It includes all the process equipment such as reactors, mixers and separating units, all the associated pipework and pumps, heat exchangers, and utilities such as steam, and cooling water. Process safety: A comprehensive management system that focuses on the management and control of potential major hazards that arise from process operations. It aims at reducing risk to a level that is as low as is reasonably practicable by the prevention of fires, explosions, and accidental or unintended chemical releases that can cause harm to human life and to the environment. It includes the prevention of leaks, spills, equipment failure, over and under-pressurization, over-temperatures, corrosion, and metal fatigue. It covers a range of tools and techniques required to ensure safe operation of plant and machinery to ensure the safety of personnel, the environment, and others through detailed design and engineering facilities, maintenance of equipment, use of effective alarms and control points, procedures, and training. It also includes risk assessment, layers of protection analysis and the use of permit to work authorizations. Process simulation: The use of computers to model and predict the operational and thermodynamic behavior of a process. Commercial software packages are used to simulate and model batch, continuous, steady-state and transient processes. They require combined material and energy balances, the properties of the materials being processed, and sometimes combine the use of experimental data with mathematical descriptions of the process being simulated. Most software packages feature optimization capabilities involving the use of complex cost models and detailed process equipment size models. Some commercial software products are shown in the table below:

Glossary of Petroleum and Technical Terminology  901 5

3 77A 7

17

14 15

76

25

Section A-A 29

77B

56

77

10 13 10K18

3 5 7 9 10 10K 13 14 15

Impeller Casing Back head cradle Bearing housing foot Shaft sleeve Shaft sleeve key Stuffing box gland Stuffing box gland stud Stuffing box gland stud Nut 17 Seal cage 18 Splash collar 25 Shaft bearing—radial 25A Shaft bearing—thrust

80

55

26 28 29 55 56 75 76 76A 77 77A 77B 80 105 105A

26 25A 76A 105

9

75 28 105A

Bearing housing Bearing end cover Pump shaft Oil disc. (flinger) Casing foot Retaining ring Oil seal—front Oil seal—rear Gasket—casing Gasket—sleeve Gasket—drain plug Oil vent Shaft adjusting sleeve Sleeve lock nut

Figure 28 General service centrifugal pump. Software

Developer

Applications

Website

Aspen Plus/ Aspen Process www.aspentech. Aspen Technology simulation and com Hysys optimization CHEMCAD Chemstations Software suite for process simulation

www.chem stations.com

Design II for WinSim Inc. Windows

Process simulation

www.winsim. com

gPOMS

PSE Ltd.

Advanced process www. simulation and psenterprise. Modeling com

PRO II

SimSci

Process simulation

www.software. schneiderelectric.com/ simsci

ProSim Plus ProSim

Process www.prosim. simulation and net optimization

UniSim

Process www.honeywell simulation and process.com optimization

Honeywell

Process synthesis: The conceptual design of a process that identifies the best process flowsheet structure, such as the conversion of raw materials into a product(s). This requires the consideration of many alternative designs. The complex structure of most processes is such that the flowsheet is split into smaller parts and each is reviewed in turn. Then choices and decisions are made. Many techniques are used in arriving at the best flowsheet such as those based on total cost, which needs to be minimized. Use is made of graphical methods, heuristics, and various other forms of minimization such as the use of process integration. Process upset: A sudden, gradual or unintended change in the operational behavior of a process. It may be due to process equipment failure or malfunction, operator intervention, a surge or fall in pressure, flow, level, concentration, etc. Process variable: A dynamic feature of a process or system that is required to be controlled to ensure that it operates according to design requirements and does not deviate as to be unsafe or result in undesirable consequences. The commonly measured process variables include temperature, pressure, flow, level and concentration. Pseudo-component: For engineering calculation purposes, a component that represents a specified portion of the TBP distillation curve for a petroleum mixture. The pseudo-component is assigned a normal boiling point and gravity corresponding to the average for the boiling point range. Molecular weight and other properties are derived from the boiling point and gravity using literature correlations for hydrocarbons. Pump: A mechanical device used to transport a fluid from one place or level to another by imparting energy to the fluid. The three bonds groupings are centrifugal, reciprocating and rotary type pumps. The most commonly used is the centrifugal type, which has a rotating impeller used to increase the velocity of the fluid and where part of the energy is converted to pressure energy. Rotary and reciprocating pumps are positive displacement pumps in which portions of fluid are moved in the pump between the teeth of gears, and by the action of a piston in a cylinder. There are many variations of these types and each has a particular application and suitability for a fluid in terms of its properties, required flow rate and delivery pressure (See Figure 28).

902  Petroleum Refining Design and Application Handbook Volume 2 Pumparound: A liquid side-draw from a distillation/fractionating column that is pumped cooled and returned to a higher location in the column. Pumparounds recover useable heat that would be lost at the condenser. They also lower the vapor flow in a column and reduce the required column diameter for vapor loaded columns such as crude and vacuum columns. Pumpdown: A liquid side draw that is pumped down to a tray below the draw tray, usually the next tray lower. Pumpdowns are sometimes cooled prior to returning to the column. Pump priming: Used for the start-up and successful operation of centrifugal pumps in which the casing housing the “impeller” is first filled or primed with liquid before operation begins. Since the density of a liquid is many times greater than that of a gas, vapor, or air, the suction pressure is otherwise insufficient to draw in more liquid. Depending on the type of pump, priming can be achieved either manually or by drawing liquid in using a vacuum pump. Valves can be used to prevent drainage, and ensure that the  pump does not require priming once the pump stops. Purge: A stream that is removed from a recycle process to prevent buildup of one or more components in the process streams. Pyrolysis: 1. Heating a feedstock to high temperature to promote cracking as in an ethylene plant. 2. Destructive distillation that involves decomposition of coal, woody materials, petroleum, and so on, by heating in the absence of air. Pyrolysis Gasoline: The gasoline created in an ethylene plant cracking gas oil or naphtha feed stocks. Sometimes called pygas, it has high content of aromatics and olefins and some diolefins. Pyrophoric Iron Sulfide: A substance typically formed inside tanks and processing units by the corrosive interaction of sulfur compounds in the hydrocarbons and the iron and steel in the equipment. On exposure to air (oxygen), it ignites spontaneously. Quality: The weight fraction of vapor in a vaporliquid mixture. Quench: Hitting a very hot stream coming out of a reactor with a cooler stream to stop immediately the reaction runaway.

Quench Crack: A crack in steel resulting from stresses produced during transformation from austenite to martensite. Quench Hardening: Heat treating requiring austenitization followed by cooling, under conditions that austenite turns into martensite. Quenching Oil: An oil introduced into hightemperature process streams during refining to cool them. Quench Stream: A cooled stream that is used to cool another stream by direct contact. For example, hydrogen quench streams are used to quench the hot effluents from hydrocracker reactors. Quench Zone: A section of a distillation column where a hot stream, usually vapor is cooled by direct contact with a stream that has been cooled, usually a liquid. Radiant Heat Transfer: Heat transfer without convection or conduction. Sunshine is radiant heat. Radiation: Transmission of energy by means of electromagnetic waves emitted due to temperature. Radical: A group of atoms that separate themselves from a compound momentarily and are highly reactive. For example, two methyl radicals *CH3 can come from cracking an ethane compound, but they will rapidly attach themselves to some other atom or compound. Raffinate: 1. The leftover from a solvent extraction process. 2. In solvent refining, that portion of the oil that remains undissolved and is not removed by the selective solvent. Rating Calculations: Calculations in which a unit operation such as a column, heat exchanger, pump, and so on, is checked for capacity restrictions. Ratio of Specific Heats: 1. Thermodynamic comparison (k = Cp/Cv) of the ratio of a specific heat (k) at a constant pressure (Cp) to a specific heat at a constant volume (Cv). The ratio range for most gases is 1.2–1.4. 2. For gases, it is the ratio of the specific heat at constant pressure to the specific heat at constant volume. The ratio is important in thermodynamic equations as compressor horsepower calculations, and is given the symbol k, where k = Cp/Cv. The ratio lies between 1.2 and 1.4 for most gases. Reactor: The vessel in which chemical reactions takes place.

Glossary of Petroleum and Technical Terminology  903 Removable steam chest cover, permitting quick access to steam valves D type slide valves most simple and reliable

Drop forged steel valve-motion parts

Rigid cast iron cradle of semicircular section, assuring strenght and alignment

Stuffing boxes extra deep

Hammered iron piston rings self-adjusting assuring brightness and reducing friction

Box type steam pistons

Dise type valve srvice

Piston rods divided at crossheads

Removabl liners held in place by cylinder heads

Twin liquid cylinders machined in duplex boring milf assuring correct centers

Soft packing or hammered iron piston rings

Liquid pistons removable follower type

Figure 29 General service duplex steam-driven piston pump.

Reactive Distillation: A distillation column in which there is a section designed for chemical reaction, usually containing a catalyst bed. Some MTBE and TAME processes use a reactive distillation column in place of a second reactor prior to the product separation column. Reactor Effluent: The outlet stream from a reactor. Reboiler: 1. A heat exchanger used towards the bottom of a fractionator to reheat or oven vaporize a liquid and introduce it several trays higher to help purify the incoming stream or get more heat into the column. 2. An auxiliary unit of a fractionating tower designed to supply additional heat to the lower portion of the tower. Reciprocating Pump: 1. A piston pump. 2. A pump with an up-and-down stroke or motion (See Figure 29). Recovery: Usually refers to the fraction expressed as a percentage of a component or group of components in the feed to a distillation column that are recovered in a given product stream.

Rectification Zone: The portion of a distillation column in which heavy components are washed down the column by contact with a liquid reflux stream. In conventional distillation columns, this is the portion of the column from the tray above the feed tray to the top tray. Recycle: A process stream that is returned to an upstream operation. Recycled Feeds: Streams that have been processed and are fed back to the reactors for additional processing. Reduced Crude: A residual product remaining after the removal by distillation of an appreciable quantity of the more volatile components of crude oil. Reduced Pressure: The ratio of the absolute pressure to the critical pressure. Reduced Temperature: The ratio of the absolute temperature to the critical temperature. Reducing Agent: Any substance, such as base metal (iron) or the sulfide ion, that will readily donate (give up) electrons. The opposite is an oxidizing agent.

904  Petroleum Refining Design and Application Handbook Volume 2 Reduction: The addition of hydrogen, removal of oxygen, or the addition of electrons to an element or compound. Under anaerobic conditions (no dissolved oxygen present), sulfur compounds are reduced to odorproducing hydrogen sulfide (H2S) and other compounds. Redwood Viscometer: Standard British viscometer. The number of seconds required for 50 ml of oil to flow out of a standard Redwood viscometer at a definite temperature is the Redwood viscosity. Refinery Grade Butane (C4H10): A refinery produced stream that is composed predominantly of normal butane and/or isobutane and may also contain propane and/or natural gasoline. These streams may also contain significant levels of olefins and/or fluorides contamination. Refinery Input, Crude Oil: Total crude oil (domestic plus foreign) input to crude oil distillation units and other refinery processing units (cokers, etc.). Refined Products: The various hydrocarbons obtained as a result of refining process separation from crude oil. Typical refined products are LPG, naphtha, gasoline, kerosene, jet fuel, home heating oil, diesel fuel, residual fuel oil, lubricants and petroleum coke. Refiner: A company involved in upgrading hydrocarbons to saleable products. Refinery: 1. An installation that manufactures finished petroleum products from crude oil, unfinished oils, natural gas liquids, other hydrocarbons and oxygenates. 2. A plant used to separate the various components present in crude oil and convert them into usable fuel products or feedstock for other processes. 3. A large plant composed of many different processing units that are used to convert crude oil into finished or refined products. These processes include heating, fractionating, reforming, cracking and hydrotreating. Refinery Gas: A non-condensable gas collected in petroleum refineries. Refinery Input (Crude Oil): Total crude oil (domestic plus foreign) input to crude oil distillation units and other refinery processing units (cokers). Refinery Input (Total): The raw materials and intermediate materials processed at refineries to produce finished petroleum products. They include crude oil, products of natural gas processing plants, unfinished oils, other hydrocarbons and oxygenates, motor gasoline and aviation gasoline blending components and finished petroleum products.

Refinery Margins: The difference in value between the products produced by a refinery and the value of the crude oil used to produce them. Refining margins will thus vary from refinery to refinery and depend on the price and characteristics of the crude used. Refinery Production: Petroleum products produced at a refinery or blending plant. Published production of these products equals refinery production minus refinery input. Negative production occurs when the amount of a product produced during the month is less than the amount of that same product that is reprocessed (input) or reclassified to become another product during the same month. Refinery production of unfinished oils and motor and aviation gasoline blending components appear on a net basis under refinery input. Refinery Yield: Represents the percentage of finished product produced from input of crude oil and net input of unfinished oils (expressed as a percentage). It is calculated by dividing the sum of crude oil and net unfinished input into the individual net production of finished products. Before calculating the yield of finished motor gasoline, the input of natural gas liquids, other hydrocarbons and oxygenates, and net input of motor gasoline blending components must be subtracted from the net production of finished motor gasoline. Before calculating the yield of finished aviation gasoline, input of aviation gasoline blending components must be subtracted from the net production of finished aviation gasoline. Reflux: 1. Condensed liquid that is returned to the top tray of a distillation column. Reflux helps rectify the mixture being distilled by washing heavy components down the column. 2. The portion of the distillate returned to the fractionating column to assist in attaining better separation into desired fractions. Reflux drum: A drum that receives the outlet from the overhead condenser from a distillation column. The liquid and vapor portions are separated in the reflux drum. Reformate: An upgraded naphtha resulting from catalytic or thermal reforming. Reforming: 1. The mild thermal cracking of naphthas to obtain more volatile products such as olefins, of higher octane values or catalytic conversion of naphthas components to produce higher octane aromatic compounds. 2. A refining process used to change the molecular structure of a naphtha feed derived from

Glossary of Petroleum and Technical Terminology  905 crude oil by distillation. 3. The gasoline produced in a catalytic reforming operation. Reformulated Fuels: Gasoline, diesel or other fuels that have been modified to reflect environmental concerns, performance standards, government regulations, customer preferences, or new technologies. Reformed Gasoline: Gasoline made by a reformate process. Reformulated Gasoline (RFG): 1. A gasoline whose composition has been changed (from that of gasolines sold in 1990) to (a) include oxygenates, (b) reduce the content of olefins and aromatics and volatile components, and (c) reduce the content of heavy hydrocarbons to meet performance specifications for ozone-forming tendency and for release of toxic substances (benzene, formaldehyde, acetaldehyde, 1,3-butadiene, and polycyclic organic matter) into the air from both evaporation and tailpipe emissions. 2. Is a cleaner-burning gasoline that reduces smog and other air pollution. Federal law mandates the sale of reformulated gasoline in metropolitan areas with the worst ozone smog. 3. Finished motor gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under Section 211 (k) of the Clean Air Act. NB: This category includes oxygenated fuels program reformulated gasoline (OPRG), but excludes reformulated gasoline blendstock for oxygenate blending (RBOB). (4) Gasoline that meets the requirements imposed by the Clean Air Act Amendment, passed by the United States Congress on November 15, 1990. Restrictions were placed on volatile organic compounds, nitrous oxides (NOx) from combustion, and toxins primarily related to benzene (C6H6) and its derivatives. Reformulated Gasoline Blendstock for Oxygenate Blending: A motor gasoline blending component that, when blended with a specified type and percentage of oxygenate, meets the definition of reformulated gasoline. Refrigerant: 1. In a refrigerating system, the medium of heat transfer that picks up heat by evaporating at a low temperature and pressure and gives up heat on condensing at a higher temperature and pressure. 2. It is the fluid that performs an inverse thermodynamic cycle, generating the low temperature required for natural gas cooling and liquefaction.

Refrigerant Compressor: A component of a refrigerating system that increases the pressure of a compressible refrigerant fluid and simultaneously reduces its volume while moving the fluid through the device. Refrigerating System: A system that, in operation between a heat source (evaporator) and a heat sink (condenser), at two different temperatures, is able to absorb heat from the heat source at the lower temperature and reject heat to the heat sink at the higher temperature. Refrigeration (or Cooling Cycle): 1. The process used to remove the natural gas liquids by cooling or refrigerating the natural gas until the liquids are condensed out. The plants use Freon or propane to cool the gas. 2. Inverse thermodynamic cycle whose purpose is to transfer heat from a medium at low temperature to a medium at higher temperature. Regasification: The process by which LNG is heated, converting it into its gaseous state. Regasification Plant: A plant that accepts deliveries of LNG and vaporizes it back to gaseous form by applying heat so that the gas can be delivered into a pipeline system. Regenerator: The vessel in a catalytic process where a spent catalyst is cleaned up before being recycled back to the process. An example is the catalytic cracker regenerator where coke deposited on the catalyst is burned off. Regeneration: 1. The process of burning off coke deposits on catalyst with an oxygen containing gas under carefully controlled conditions. 2. In a catalytic process the reactivation of the catalyst, sometimes done by burning off the coke deposits under carefully controlled conditions of temperature and oxygen content of the regeneration gas stream. Reid Vapor Pressure (RVP): An ASTM test method to determine the vapor pressure of a light petroleum stream. The Reid vapor pressure is very nearly equal to the true vapor pressure for gasoline streams. There is also a Reid vapor pressure test for crude oil (See Figure 30 and Table 2). Relative volatility (α): The ratio of the vapor pressure of one liquid component to another in a heterogeneous mixture and is a measure of their separability. For a binary mixture, the relative volatility can be expressed in terms of the mole fraction of the more

906  Petroleum Refining Design and Application Handbook Volume 2 Reid vapor test gauge Type 1150H 4½” Lower connect (only) 37/16(87)

ASTM D6378 curve measurements 1000

B

5/16(8) D/A

13/16(20.5)

800 Vapor pressure (kPa)

3 11/16 (93.5)

A

C

G I

4½ (a)

A

B

C

4 31/32 2 1/8 (127) (54)

600

400

200

¼ NPT Dial size inches

Pentane measurement Pentane - reference data NIST (National Institute of Standards and Technology) Gasoline measurement

D

D

G

I

15/16 3 13/16 5/8 4 7/8 (124) (24) (97) (16)

0

Wght (lbs)

–20

40 60 Temperature (°C)

80

100

120

30

R

18

20

22

26

40

14

10

12

8

10

6

), p

si

7

8

4

P RV e( e r su lin es so pr ga r r po to va Mo id

Re

5

6

2

1

0

20

40

60

80 100 120 Temperature, °F

140

160

180

200

(d)

0.50 0.60 0.70 0.80 0.90 1.00 1.50 2.00 2.50 3.00 3.50 4.00 5.00 6.00 7.00 8.00 9.00 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0 21.0

110 100 90 80 70 60 50 40 30 20

Stock tempeerature, F (degree fahrenheat)

e ), p in P ol (RV s ga re al su ur res t Na or p p va eid

60

Stock true vapor pressure, P (pounds per square inch absolute)

si

34

80

True, vapor pressure, psia

20

Dimensions in inches (mm)

100

(c)

0

(b)

1.7 .8kg

10 0

Figure 30 (a) Reid vapor test gauge (b) Vapor pressure vs. temperature (c) Reid vapor pressure vs. Temperature.

volatile component in the liquid and vapor phases, x and y as:

a=

y (1 − x )

x (1 − y )

The greater the value of the relative volatility, the greater the degree of separation. If y =x, then no separation is possible.

Reliability: The probability that a component or system will perform its defined logic functions under the stated conditions for a defined period of time. Research Octane Number (RON): One of two standards tests of gasoline knock, this one simulates less severe operating conditions like cruising. It is determined in a special laboratory test engine under mild “engine-severity” conditions, giving a measure of the

Glossary of Petroleum and Technical Terminology  907 Table 2 RVP blending values. RVP blending values

Vol% (aromatics)

rvp (pure HC)

0

10

20

30

40

50

Ethane

730.0

474.0

474.0

474.0

474.0

474.0

474.0

Propene

226.0

216.0

216.0

216.0

216.0

216.0

216.0

Propane

190.0

173.0

173.0

173.0

173.0

173.0

173.0

Isobutane

72.2

62.0

73.9

85.4

96.6

107.6

118.8

Isobutene

63.4

76.5

78.9

81.3

83.7

86.2

88.9

Butene-1

63.0

76.1

78.4

80.8

82.7

85.1

87.4

n-Butane

51.6

52.9

55.6

58.3

60.9

63.5

66.2

trans-2-Butene

49.8

62.1

64.0

66.0

68.0

70.0

72.0

cis-2-Butene

45.5

58.6

60.5

62.3

64.2

66.1

69.0

Isopentane

20.4

21.9

22.2

22.5

22.9

23.3

23.7

C5 olefins*

16.5

17.9

18.1

18.4

18.6

18.8

19.0

n-Pentane

15.6

16.9

17.2

17.4

17.8

18.0

18.2

*C5 olefins in FCC proportion.

low-speed knock properties of a gasoline. Contrast with Motor Octane Number.

laminar flow, or stream line. For Reynolds number above 4,000 the flow is turbulent (See Figure 7).

Residence time: 1. The amount of time a hydrocarbon spends in a vessel where a reaction occurs. 2. The period of time in which a process stream will be contained within a certain volume or piece of equipment, seconds.

Rich oil: The absorption oil leaving the bottom tray of an absorption column. The rich oil contains the absorbed light components.

Residual Fuel: heavy fuel oil made from long, short or cracked residue plus whatever cutter stock is necessary to meet market specifications. Residue: The bottoms from a crude oil distilling unit, vacuum flasher, thermal cracker or visbreaker. See long residue and short residue. Residuum: Residue from crude oil after distilling off all but the heaviest components with a boiling range greater than 1000°F (538°C). Reynolds Number (Re): A dimensionless number, Re, expressing the ratio of inertial to viscous forces in a flowing fluid, and can be used to determine the flow regime. For a fluid in a pipe of circular cross section:

Re =

rvd m

where ρ is the density, v is the mean velocity, d is the diameter of a pipe, and µ is the viscosity. Where the value for critical pipes falls below 2,000 the flow is

Ring Compounds: Hydrocarbon molecules in which the carbon atoms form at least one closed ring  such as naphthenes or aromatics. Also called cyclic. Ring Structure: A compound in which some of the carbon atoms are linked with other carbon atoms to form a continuum. Carbon atoms attached to the ring carbon atoms are said to be “side chains”. Riser: 1. A pipe through which a fluid travels upwards. 2. Steel or flexible pipe, which transfers well fluids from the seabed to the surface. Risk: 1. Is defined as a measure of economic loss, human injury, or environmental damage in terms of both the incident likelihood and the magnitude of the loss, injury or damage. 2. The probability of an event happening times the impact of its occurrence on operations. (Impact is the effect on conditions or people if the hazard is realized (occurs) in practice and potentials are the likelihood that the impact will occur.

908  Petroleum Refining Design and Application Handbook Volume 2 Likelihood

Catastrophic

Critical

Marginal

Negligible

Certain

Class I

Class I

Class I

Class II

Possible

Class I

Class I

Class II

Class III

Occasional

Class I

Class II

Class III

Class IV

Remote

Class II

Class III

Class III

Class IV

Improbable

Class III

Class III

Class IV

Class IV

Inconceivable

Class IV

Class IV

Class IV

Class IV

Risk Analysis: A decision-making tool that allows examination of the level and significance of work place risk for humans, equipment, weather, operations or other conditions. Determines the probability of risk occurring, the impact the risk will have, and how to mitigate the risk. See Hazard Analysis. Risk Assessment: The process of identifying and evaluating the technical and nontechnical risks associated with a project. It includes the amount or degree of potential danger perceived (by an assessor) when determining a course of action to accomplish a given task. Risk assessment may be qualitative or quantitative. Risk Matrix: Is the common approach to risk assessment and hazard analysis. Its underlying idea is that acceptability of risk is a product of how likely a thing is to happen, and how bad it would be if it happened. This is shown in the following tables. Category

Definition

Certain

Many times in system >10–3 lifetime

Probable

Several times in system lifetime

10-3 to 10-4

Occasional

Once in system lifetime

10-4 to 10-5

Remote

Unlikely in system lifetime

10-5 to 10-6

Improbable

Very unlikely to occur

10 to 10

Inconceivable

Cannot believe that it could occur

< 10-7

Risk matrix consequences

categorization

Range (failures per year)

-6

of

Definition

Catastrophic

Multiple loss of life

Critical

Loss of a single life

Marginal

Major injuries to one or more person

Negligible

Minor injuries to one or more person

Risk matrix Consequence Key: Class I: Unacceptable Class II: Undesirable Class III: Tolerable Class IV: Acceptable Road Oil: Any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades from 0, the most liquid to 5, the most viscous. Rule of Thumb: Axioms based on practical experience and/or methods to approximate calculated results using simple formulae. Runback: The liquid returning to the flash zone of a distillation column. Safety: A general term denoting an acceptable level of risk of, relative freedom from and low probability of harm. Safeguard: A precautionary measure of stipulation. Usually equipment and/or procedures designed to interfere with incident propagation and/or prevent or reduce incident consequences.

-7

severity

Category

of

Safety Integrity Level (SIL): 1. Is defined as a relative level of risk reduction provided by a safety function, or to specify a target level of risk reduction. SIL is a measure of performance required for a

Glossary of Petroleum and Technical Terminology  909 safety instrumented function (SIF). 2. The degree of redundancy and independence from the effects of inherent and operational failures and external conditions that may affect system performance. The requirements for a given SIL are not consistent among all of the functional safety standards. In the European functional safety standards based on the IEC 61508 standard, four SILs are defined, with SIL 4 the most dependable and SIL 1 the least. A SIL is determined based on a number of quantitative factors in combination with qualitative factors such as development process and safety life cycle management. Assignment of SIL is an exercise in risk analysis where the risk associated with a specific hazard, that is intended to be protected against by a SIF, is calculated without the beneficial risk reduction effect of the SIF. That “unmitigated” risk is then compared against a tolerable risk target. The difference between the “unmitigated” risk and the tolerable risk, if the “unmitigated” risk is higher than tolerable, must be addressed through risk reduction of the SIF. This amount of required risk reduction is correlated with the SIL target. In essence, each order of magnitude of risk reduction that is required correlates with an increase in one of the required SIL numbers. There are several methods used to assign a SIL. These are normally used in combination, and may include: • Risk matrices • Risk graphs • Layers Of Protection Analysis (LOPA) Of the methods presented above, LOPA is by far the most commonly used by large industrial facilities. The assignment may be tested using both pragmatic and controllability approaches, applying guidance on SIL assignment published by the UK HSE. SIL assignment processes that use the HSE guidance to ratify assignments developed from Risk Matrices have been certified to meet IEC EN 61508. Safety Instrumented Function (SIF): Safety function with a specific safety integrity level which is necessary to achieve functional safety and which can be either a safety instrumented protection function or a safety instrumented control function. Salt Content: Crude oil usually contains salts in solution in water that is emulsified with the crude. The salt content is expressed as the solution of sodium chloride (NaCl) equivalent in pounds per thousand barrels (PTB) of crude oil. Typical values range from

1 to 20 PTB. Although there is no simple conversion from PTB to parts per million by weight (ppm), 1 PTB is roughly equivalent to 3 ppm. Saturated Compounds: Hydrocarbons in which there are no double bonds between carbon atoms. Saturated compounds contain the maximum number of hydrogen atoms that are possible. Screwed Fittings: These are used to assemble screwed connections and field instruments on pipes. They are: • Pipe thread fittings • Instrument or tubing fittings • Metric fittings None of these will screw together. Scrub: Removal of components (gas, liquids, or solids) from the methane achieved by surface equipment (scrubbers). Scrubber: 1. A reactor that removes various components from produced gas. 2. Equipment that causes the separation of liquid and gaseous phases in a fluid system. The separation is usually based on density, differences of the two phases and can take place using gravity force, induced centrifugal force, and so on. 3. System to reduce noxious substances from a flowing stream of air, usually filled with plates or packing, through which scrubbing fluid flows countercurrent or cross-current to the path of the contaminated air. Scrubbing: Purification of a gas or liquid by washing it in a tower. Secondary Absorber: The second absorber in a FCC gas plant. It is usually the last unit operation in the gas recovery plant and is also known as the sponge absorber. Selectivity: The difference between the research octane number and the motor octane number of a given gasoline. Alkylate is an excellent low-sensitivity and reformate a high-sensitivity gasoline component. It is an indication of the sensitivity of the fuel to driving conditions (city vs. highway). Selective Treating: Preferential removal of one acid gas component, leaving at least some of the other acid gas components in the treated stream. Sensitivity: The difference in the research octane (F -1) and the motor octane (F -2) for a gasoline stream.

910  Petroleum Refining Design and Application Handbook Volume 2 Since research octane is always larger, sensitivity is always a positive number. Separation zone: A section of a distillation column in which a separation between two products occurs. Components which are found in both products are said to be distributed components.

quantities of oil and gas. 3. Rock formed from clay. 4. Gas reserves found in unusually nonporous rock, requiring special drilling and completion techniques. Shale Gas: Methane (CH4) gas stored in shale. May be in the pore space, adsorbed to the mineral or rock surfaces, or as free gas in the natural fractures.

Separator: Usually refers to a drum, in which the residence time is provided for a mixture of the liquid and vapor to separate into liquid and vapor streams. Also called a flash drum. The liquid and vapor leaving the separator are in phase equilibrium.

Shale Oil: 1. Can be either an immature oil phase, often called kerogen, or actual oil in the cracks or pores of shale. 2. The liquid obtained from the destructive distillation of oil shale. Further processing is required to convert it into products similar to petroleum oils.

Severity: The degree of intensity of the operating conditions of a process unit. Severity may be indicated by clear research octane number of the product (reformer), percentage disappearance of the feed (catalytic cracking), or operating conditions alone (usually the temperature; the higher the temperature, the greater the severity).

Shear force: An applied force to a material that acts in a direction that is parallel to a plane rather than perpendicular. A material such as a solid or fluid is deformed by the application of a shear force over a surface known as the shear stress. The shear strain is the extent of the deformation defined as the ratio of the deformed distance with length. The shear modulus is the ratio of the shear stress to the shear strain.

Shale: 1. A common sedimentary rock with porosity but little matrix permeability. Shales are one of the petroleum source rocks. Shales usually consist of particles finer than sand grade (less than 0.0625 mm) and include both silt and clay grade material. 2. A very finegrained sedimentary rock formed by the consolidation and compression of clay, silt or mud. It has a finely laminated or layered structure. Shale breaks easily into thin parallel layers; a thinly laminated siltstone, mudstone, or claystone. Shale is soft but sufficiently hard packed (indurated), so as not to disintegrate upon becoming wet. Some shales absorb water and swell considerably causing problems in well drilling. Most shales are compacted and consequently do not contain commercial

Shear rate (γ): The deformation of a fluid under the influence of an applied shear force presented as the change in velocity of the fluid perpendicular to flow.

g=

dv dz

where, dv/dz is referred to as the velocity gradient. The S.I. unit is s-1. Shear stress (τ): The shear force applied to a fluid that is applied over a surface. When the shear stress is proportional to the shear rate, the fluid exhibits

U-tube heat exchanger Shell-side fluid in Baffle

Shell

Tube sheet

Outlet plenum

Out In Tube-side fluid Shell side Tube bundle with U-tubes

Baffle Shell-side fluid out

Inlet plenum

Figure 31 A shell and tube heat exchanger showing the direction of flow of fluids in the shell and tube sides.

Glossary of Petroleum and Technical Terminology  911 Newtonian behavior and the viscosity is constant. The S.I. units are Nm-2.

t= m

dv dz

where µ is the viscosity. Shell and Tube Heat Exchanger: A device used to transfer heat from one medium to another. It consists of a shell that contains tubes. One medium is contained within the shell and the other within the tubes, and heat is transferred from one to the other across the tubes. There are many designs commonly used and the simplest is a single-phase type exchanger in which a cold liquid to be heated flows through the tubes from one side of the exchanger to the other. Steam is used as the heating medium and enters as vapor and leaves as condensate from the bottom. A kettle reboiler type is a type of shell and tube heat exchanger in which steam is admitted through the tubes. The choice of hot or cold fluid in the tubes or shell depends on the application and nature of the fluids, such as their susceptibility to fouling (See Figure 31). Shell side: The space between the outside of the tubes and the inside of the casing or shell of a shell and tube heat exchanger. Sherwood number (Sh): A dimensionless number that represents the relationship between mass diffusivity and molecular diffusivity.

Sh =

kL DAB

Where k is the mass transfer coefficient, L is the characteristic dimension, and D is the diffusivity of the solute A in the solvent B. It corresponds to the Nusselt number used in heat transfer. Shock wave: A pressure wave of very high pressure intensity and high temperature that is formed when a fluid flows supersonically or in which a projectile moves supersonically through a stationary fluid. It can be formed by a violent event such as a bomb blast or an explosion. A shock-wave compression is the non-isentropic adiabatic compression in waves that is traveling above the speed of sound. Short Residue: Flasher bottoms or residue from the vacuum tower bottoms. Short-Term Exposure Limit (STEL): The timeweighted average concentration of a substance over a 15 min. period thought not to be injurious to health. Shutdown: 1. The status of a process that is not currently in operation due to schedule or unscheduled maintenance, cleaning or failure. 2. A systematic sequence of action that is needed to stop a process safely. Side draw: See Draw Side Heater (reboiler): A heat input to a distillation column that is located above the bottom tray of the column. Side reaction: A chemical reaction that takes place at the same time as a main reaction and produces unwanted products and therefore reduces the yield of the desired product. E.g., in the high temperature cracking

Liquid Tray Vapour Normal operation

Liquid Tray Weeping

Figure 32 A sieve plate.

Vapour Weeping Low vapour flow condition

912  Petroleum Refining Design and Application Handbook Volume 2 reaction of propane (C3H8) to produce propylene (C3H6), C 3 H8 → C 3 H6 + H2 , some of the hydrogen can react with the propane to produce methane and ethane as side reactions, C 3 H8 + H2 → CH 4 + C 2 H6 . The conditions for the reaction must therefore be controlled to reduce this unwanted reaction. Side stream: The continuous removal of a liquid or a vapor from a process such as a distillation column that is not the main process flow. For example, drawing off vapor or liquid mid way up the column can have economic advantage in terms of the physical size of the column and the amount of boil-up energy required. Side Stripper: A small auxiliary column that receives a liquid draw product from a main distillation column for stripping of light components. Light components are stripped by stripping steam or reboiling and returned to the main column. Liquid products are sometimes stripped in side strippers to raise the flash point. Sieve plate column: 1. A type of distillation column that uses a stack of perforated plates to enhance the distribution and intimate contact between vapor and liquid. The plates allow vapor to pass up and bubble through the liquid on the plates. The rate of flow of vapor is sufficient to prevent the liquid from draining down the sieve plates. Instead, the liquid flows over a weir and down a downcomer to the sieve plate below. 2. Sieve trays are metal plates with holes; vapor passes straight through the liquid on the plate. The arrangement, number and size of the holes are design parameters (See Figure 32). Simulated distillation (Simdist): A relatively new laboratory technique in which a petroleum stream is separated into fractions with gas phase chromatography. Carbon disulfide (C2S) is used as the carrying agent to dissolve the petroleum stream. The component fractions elute from the chromatographic column in a time sequence, related to their boiling temperatures. Temperatures are assigned to the fractions based on the chromatographic separation of a normal paraffin standard mixture. The simulated distillation approaches a true boiling point distillation, and is reported on a mass basis for streams heavier than gasoline. Aromatic compounds elute from the column faster than paraffin of similar boiling points. Therefore, simulated distillations must be corrected for aromatic content when stocks contain significant quantities of aromatic components.

Slack Wax: Wax produced in the dewaxing of lube oil base stocks. This wax still contains some oil and must be oiled to produce finished wax product. Slop Wax: The over flash from a vacuum column. The slop wax is usually withdrawn from the column and combined with the fresh charge to the vacuum furnace. Slurry: The bottom stream from FCC main fractionators. It is termed slurry because it contains suspended catalyst particles. Slurry Oil: The oil, from the bottoms of the FCC unit fractionating tower, containing FCC catalyst particles carried over by the vapor from the reactor cyclones. The remainder of the FCC bottoms is the decanted oil. Smoke: The gaseous products of the burning of carbonaceous materials made visible by the presence of small particles of carbon; the small particles that are of liquid and solid consistencies are produced as a byproduct of insufficient air supplies to a combustion process. Smoke Point: 1. Refers to the height of a smokeless flame of fuel in millimeters beyond which smoking takes place. It reflects the burning quality of kerosene and jet fuels. 2. A test measuring the burning quality of jet fuels, kerosene and illuminating oils. It is defined as the height of the flame in millimeters  beyond which smoking takes place; ASTM D 1322. Soaker, Soaking Drum: A soaker is a device that allows cracking time (soaking time) for heated oil in a thermal cracking operation. Furnace coils and/or drums are used for this purpose. Since some coke is deposited in the soaking device it must be periodically taken off line and cleaned. Furnace coils are much easier to clean than drums. Soave-Redlich-Kwong (SRK) equation of state: An equation of state widely used to predict the vapor-liquid equilbria of substances. It is a development of the “Redlich-Kwong” equation of state that correlated the vapor pressure of normal fluids.

p=

a a (T ) RT − v − b V (V + b )

where a and b are constants and obtained from critical point data. It also involves a function that was

Glossary of Petroleum and Technical Terminology  913 developed to fit vapor pressure data using reduced temperature, Tr:

(

)(

)

a = 1 + 0.480 + 1.574w − 0.176w 2 1 − Tr0.5   

2

where ω is the acentric factor. Solvent Extraction: A separation process based on selective solubility, where a liquid solvent is introduced at the top of a column. As it passes the feed, which enters near the bottom as a vapor, it selectively dissolves a target constituent. The solvent is then removed via the bottom of the column and put through an easy solvent/extract fractionation. From the top of the column comes a raffinate stream, the feed stripped out of the extract. Butadienes and aromatics are some products recovered by solvent extraction. Sour Crude Oils: Crudes that contain sulfur in amounts greater than 0.5 to 1.0 wt %, or that contain 0.05 ft3 or more hydrogen sulfide (H2S) per 100 gal. Such oils are dangerously toxic. Even 0.05 ft3 per 100 gal can be present before severe corrosion tends to occur. Arabian crudes are high-sulfur crudes that are not always considered sour because they do not contain highly active sulfur compounds. Original definition was for any crude oil that smelled like rotten eggs. Sour Gas: 1. A light gas stream that contains acid gases, in particular sulfur compounds, ammonia compounds, and carbon dioxide. 2. Gas rich in hydrogen sulfide (H2S). 3. Natural gas that contains significant amount of hydrogen sulfide (usually greater than 16 ppm) and possibly other objectionable sulfur compounds (mercaptans, carbonyl sulfide). Also called “acid gas.” 4. Natural or associated gas with high sulfur content. 5. Natural gas containing chemical impurities, a notable hydrogen sulfide (H2S) or other sulfur compounds that make it extremely harmful to breathe even small amounts; a gas with disagreeable odor resembling that of rotten eggs. 6. A gas containing sulfur-bearing compounds such as hydrogen sulfide and mercaptans and usually corrosive. 7. Raw natural gas to be processed, that is, gas received at the liquefaction plant before being subjected to any pretreatment. Space Velocity: A unit generally used for expressing the relationship between feed rate and reactor volume in a flow process. It is defined as the volume or weight of feed per unit time per unit volume of reactor or per unit weight of catalyst. Space velocity is normally expressed on a volume basis (LHSV: liquid hourly space velocity)

or a weight basis (WHSV: weight hourly space velocity). LHSV and WHSV are determined as follows: LHSV =

total volumetric feed flow rate to the reactor

WHSV =

total catalyst volume total mass feed flow rate to the reactor total catalyst weight

[= ]h −1

[= ]h −1

LHSV and WHSV are related by the equation

WHSV =

roil LHSV rcat

where oil and cat are the densities of the hydrocarbon feed and the catalyst respectively Specific gravity: By definition is the ratio of gas density (at the temperature and pressure of the gas) to the density of dry air (at the air temperature and pressure). Spent Catalyst: Catalyst that has been through a reaction and is no longer as active because of substances or other contaminants deposited on it (in the case of solid) or mixed with it (in the case of liquid). Spillback: A spillback allows fluid to recycle from the discharge back to the suction of a machine. It’s one way to stop a centrifugal compressor from surging. Splitter: A distillation column that separates a feed into light and heavy products. Sponge Absorber: See Secondary absorber. Sponge Oil: The liquid used in an absorption plant to soak up the constituent to be extracted. Stability: Is the ability of a catalyst to maintain its activity and selectivity over a reasonable period. A catalyst with good stability has a long cycle life between regeneration in a commercial unit. Stabilization: A process for separating the gaseous and more volatile liquid hydrocarbons from crude petroleum or gasoline and leaving a stable (less-volatile) liquid so that it can be handled or stored with less change in composition. Stabilizer: A distillation column that removes light components from a liquid product. This terminology is often used to describe debutanizer columns that remove C4 hydrocarbons from gasoline to control the vapor pressure. Standard cubic feet (scf): The volume of gas expressed as standard cubic feet. Standard conditions in petroleum and natural gas usage refer to a pressure

914  Petroleum Refining Design and Application Handbook Volume 2 base of 14.696 psia (101.5 kPa) and a temperature base of 60°F (15°C). Static head: The potential energy of a liquid expressed in head form:

h=

p rg

where p is the pressure, ρ is the density and g is the acceleration due to gravity. It is used directly in the Bernoulli equation for which the other two head forms are velocity head and pressure head (See Figure 3).

vaporization. When distilled, the components operate independently of one another, with each being in equilibrium with its own vapor. Steam distillation is used in the primary separation of crude distillation in a fractionating column. Steam injection: The use of live steam fed directly into a process to provide water and heat and to C

C

Steady State: Describes a process in which the mass and energy flowing both into and out the process are in perfect balance. Steam: The gaseous form of water formed when water boils. At atmospheric pressure, steam is produced at 212°F (100°C) by boiling water. It is widely used in the chemical and process industries as a utility for heating processes such as a kettle type reboiler for distillation columns. It is also used in power generation when steam is produced or raised from a thermal process and expanded through turbines. Other uses of steam at destroying harmful pathogens and is a harmless substance once cooled. Wet steam is water vapor that contains water droplets. With further heating, the water evaporates. The dryness fraction of steam is the ratio of the amount of water in steam to the total amount of water vapor. Superheated steam is produced by heating the steam above the boiling point of water. The thermodynamic properties of steam are presented in published literature as the steam tables. Steam (Purchased): Steam, purchased for use by a refinery that was not generated from within the refinery complex. Steam Cracking: 1. The high temperature reduction in length or cracking of long-chain hydrocarbons in the presence of steam to produce shorter-chain products such as ethylene (C2H4), propylene (C3H6) and other small-chain alkenes (CnH2n). 2. The same as catalytic cracking, but specifically referring to the steam injected with the catalyst and feed to give the mixture lift up the riser. Steam distillation: The separation of immiscible organic liquids by distillation using steam. In involves the injection of live steam into the bottom of the distillation column and into the heated mixture for separation. The steam reduces the partial pressure of the mixture and reduces the temperature required for

A

A B

B

Trap in open position The Invert bucket steam trap

Trap in closed position

H A D

B E Float-type steam trap with auxiliary vent D H

C B

Float-type steam trap

F

C D E

G

A

F D E G Plant view of the seat

Thermodynamic trap

A D C

B

Thermostatic steam trap

Figure 33

Glossary of Petroleum and Technical Terminology  915 enhance either reaction or extraction. It is commonly used as an enhanced oil recovery method to recover oil from depleted reservoirs or from oil sands in which viscous heavy oil is recovered using steam injection to reduce the viscosity of the oil, and aid transport and recovery. Steam is also directly used in the separation of crude oil and fed to the bottom of the fractionating/ distillation column. This is the primary separation of crude oil into fractions that have different boiling points. Steam cracking uses steam for thermal cracking and reforming of hydrocarbons. Steam jet ejector: A type of fixed operating pump that uses high-pressure steam passed through a constriction to create a low pressure due to the venture effect, and to which the equipment to be evacuated is connected such as a distillation column condenser. In spite of requiring high-pressure steam, the device has no moving parts and therefore has low maintenance costs. It can handle corrosive vapors. Steam Methane Reformer: A primary source of hydrogen in a refinery, this operating unit converts methane (CH4) and steam (H2O) to hydrogen (H2) with by-products of carbon monoxide (CO) and carbon dioxide (CO2). Steam point: The temperature that corresponds to the maximum vapor pressure of water at standard atmospheric pressure (1.01325 bar). This corresponds to a temperature of 100°C. Steam reforming: The conversion of methane (CH4) from natural gas into hydrogen (H2). It is used in production of ammonia (NH3) in which the methane is first produced from desulfurized and scrubbed natural gas, mixed with steam and passed over nickel catalyst packed in tubes at a high temperature of round 1652 °F (990 °C)

CH 4 +H2O → CO+3H2 CH 4 +2H2O → CO2 +4H2 The reactions are endothermic (i.e., absorbing heat). Steam tables: Published tables that present thermodynamic data for enthalpy, entropy and specific volume of steam at various temperatures and pressure. Steam is a commonly encountered material in chemical processes and its properties have been extensively tabulated. Steam tracing: An internal pipe or tube used in process vessels and pipelines carrying steam to provide

adequate heating to a fluid to keep it at a controlled temperature. The amount of steam or heat supplied is sufficient to overcome losses. Steam tracing is typically used in pipelines carrying molten bitumen and other fluids prone to solidification on cooling, to ensure that they remain in a liquid state. Steam trap: A device used to automatically drain and remove condensate from steam lines to protect the steam main from condensate build-up. Various types of steam traps are used and generally consists of a valve that can be operated by a float, spring or bellows arrangement. Discharge of the hot condensate may be either to the environment or into a collection pipe and returned to the boiler for reuse (See Figure 33). Still Gas (Refinery gas): Any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane (CH4), ethane (C2H6), ethylene (C2H4), normal butane (nC4H10), butylenes (C4H8), propane (C3H8), propylene (C3H6), and so on. Still gas is used as a refinery fuel and a petrochemical feedstock. The conversion factor is 6 million Btu per fuel oil equivalent barrel. Stoichiometric: Applied to reactors in which the reactants and products are defined in terms of the molar quantities reacting. E.g., in the reaction: 3H2 + 2NH3, the stoichiometric coefficients are -3.0, 2H2 -2.0 and 2.0 for the H2, N2 and NH3 respectively. Straight Run Distillate or Natural Gasoline: 1. A fraction obtained on simple distillation of crude oil without cracking. Its octane number is usually low and thus requires upgrading by catalytic reforming. 2. A product that has been distilled from crude oil but has not been through a process in which the composition has been chemically altered. 3. Gasoline produced by the primary distillation of crude oil. It contains no cracked, polymerized, alkylated, reformed, or visbroken stock. Stress Relief: Coded vessels typically have a metal stamp attached that states “Do not weld, stress relieved”. That means the vessel has been postweld heat treated to remove stresses in the vessel wall created by welding during fabrication. Stripper Column: A loose designation applied to a distillation column in which light components are stripped from a heavier liquid product.

916  Petroleum Refining Design and Application Handbook Volume 2 Stripping: The removal (by steam-induced vaporization or flash evaporation) of the more volatile components from a cut or fraction. Stripping Steam: Steam that is injected into the bottom of a side stripping column or used to strip oil from catalyst in a FCC operation. Stripping Zone: The section of the column in which light components are stripped from a heavier liquid product. In conventional distillation columns, this is the portion of the column from the reboiler to the feed tray. Sulfolane (CH2)4SO2: A chemical used as a solvent in extraction and extractive distillation processes. Sulfur: A yellowish nonmetallic element, sometimes known as “brimstone.” It is present at various levels of concentration in many fossil fuels whose combustion releases sulfur compounds that are considered harmful to the environment. Some of the most commonly used fossil fuels are categorized according to their sulfur content, with lower sulfur fuels usually selling at a higher price. Note: No. 2 Distillate fuel is currently reported as having either a 0.05% or lower sulfur level for on-highway vehicle use or a greater than 0.05% sulfur level for off-highway use, home heating oil, and commercial and industrial uses. This also includes Ultra Low Sulfur Diesel (< 15 ppm sulfur). Residual fuel, regardless of use, is classified as having either no more than 1% sulfur or greater than 1% sulfur. Coal is also classified as being low-sulfur at concentration of 1% or less or high-sulfur at concentrations greater than 1%. Sulfuric acid treating: A refining process in which unfinished petroleum products such as gasoline, kerosene, and lubricating oil stocks are treated with sulfuric acid to improve their color, odor, and other characteristics. Sulfurization: Combining sulfur compounds with petroleum lubricants. Sulfur content: Is expressed as a percentage of sulfur by weight, and varies from less than 0.1% to greater than 5%. Crude oils with less than 1 wt% sulfur are called low-sulfur content or sweet crude, and those with more than 1 wt% sulfur are called high-sulfur or sour crude. Sulfur-containing constituents of the crude oil include simple mercaptans (also known as thiols), sulfides and polycyclic sulfides. Mercaptan sulfur is simply an alkyl chain (R-) with SH group attached to

it at the end. The simplest form of R – SH is methyl mercaptan, CH3SH. Surface Area: The total area that a solid catalyst exposes to the feeds in a reaction. Surface area is enhanced in some catalysts like zeolytes by extensive microscopic pores. Supply: The components of petroleum supply are field production, refinery production, imports, and net receipts when calculated on a PADD basis. Surge: This a terrifying sound that centrifugal compressors make when they malfunction either due to low flow or excessive discharge pressure or low molecular weight gas. Sweet Crude: 1. Crude oil containing very little sulfur and having a good odor. 2. Crude petroleum containing little sulfur with no offensive odor. 3. Gets its name due to a pleasant and “sweet” smell. Sweet crude has sulfur content less than 1%. It is more valuable than sour crude because it costs less to process the crude into finished products. 4. Oil containing little or no sulfur, especially little or no hydrogen sulfide. Original definition was for any crude oil that did not have bad odor. Sweetening: 1. The removal or conversion to innocuous substances of sulfur compounds in a petroleum product by any of a number of processes (doctor treating, caustic and water washing, etc.). 2. Processes that either remove obnoxious sulfur compounds (primarily hydrogen sulfide, mercaptans, and thiophens) from petroleum fractions or streams, or convert them, as in the case of mercaptans, to odorless disulfides to improve odor, color, and oxidation stability. Sweet Gas: 1. Gas sweetened. Gas processed in the acid gas removal unit that no longer contains these gaseous pollutants. 2. Natural gas that contains small amounts of hydrogen sulfide (and other sulfur compounds), and carbon dioxide that it can be transported or used without purifying with no deleterious effect on piping and equipment. 3. A gas stream from which the sulfur compounds have been removed. 4. A gas containing no corrosive components such as hydrogen sulfide and mercaptans. Symbols of chemical apparatus and equipment: Below are listed some symbols of chemical apparatus and equipment normally used in a P&ID, according to ISO 10628 and ISO 14617 (See Figure 34).

Glossary of Petroleum and Technical Terminology  917 Pipe

Thermally insulated pipe

Jacketed pipe

Cooled or heated pipe

Jacketed mixing vessel (autoclave)

Half pipe mixing vessel

Pressurized horizontal vessel

Pressurized vertical vessel

Pump

Vacuum pump or compressor

Bag

Gas bottle

Fan

Axial fan, ,MK,,,

Radial fan

Dryer

Packed column

Tray column

Furnace

Cooling tower

Heat exchanger

Heat exchanger

Cooler

Plate & frame heat exchanger

Double pipe heat exchanger

Fixed straight tubes heat exchanger

U shaped tubes heat exchanger

Spiral heat exchanger

Covered gas vent

Curved gas vent

(Air) filter

Funnel

Steam trap

Viewing glass

Pressure reducing valve

Flexible pipe

Valve

Control valve

Manual valve

Back draft damper

Needle valve

Butterfly valve

Diaphragm valve

Figure 34 Symbols of chemical apparatus and equipment.

Figure 35 The Onion model (LOC = Loss of containment).

Synthetic Crude: Wide boiling range product of catalytic cracking, coking, hydrocracking, or some other chemical structure change operation. Synthesis Gas: The product of a reforming operation in which a hydrocarbon usually methane and water are chemically rearranged to produce carbon monoxide, carbon dioxide and hydrogen. The composition of the product stream can be varied to fit the needs of hydrogen and carbon monoxide at refineries or chemical plant. Also known as syn gas. Tail Ends: Small amounts of hydrocarbon in a cut that vaporizes slightly outside the effective initial boiling point and the effective end point. Tail Gas: Light gases C1 to C3 and H2 produced as by-products of refinery processing. TAN: Total acid number. Tank Farm: An installation used by gathering and trunk pipeline companies, crude oil producers and terminal operators (except refineries) to store crude oil. Tanker and Barge: Vessels that transport crude oil or petroleum products. Data are reported for movements between PAD Districts; from a PAD District to the Panama Canal; or from the Panama Canal to a PAD District. Tar: Complex, large molecules of predominantly carbon with some hydrogen and miscellaneous other

918  Petroleum Refining Design and Application Handbook Volume 2 elements that generally deteriorate the quality of processes and the apparatus. TBP distillation: See fifteen-five distillation. Tertiary Amyl Methyl Ether (CH3)2(C2H5)COCH3 (TAME): A high-octane oxygenate blending stock produced by reacting isoamylene (isopentylene) produced in FCC processes with methanol. Used to enhance the octane of a motor gasoline pool. Tertiary Butyl Alcohol – (CH3)3COH (TBA): An alcohol primarily used as a chemical feedstock, a solvent or feedstock for isobutylene production for MTBE; produced as a co-product of propylene oxide production or by direct hydration of isobutylene. Tetra Ethyl Lead (TEL): A compound added to gasoline to increase the octane. TEL has been superseded by other octane enhancers and is no longer used by refiners for motor gasoline. Test run: A time period during which operating data and stream samples are collected for a process. During test runs, the operation of the processing unit is held as steady as possible. For good test runs, the average conditions and streams flows approximate at steady-state operation. The diesel engine: The diesel engine is a reciprocating internal combustion engine. It is different from the petrol engine in that the air intake in the engine cylinder is unthrottled and not premixed with the fuel. Here, the ignition takes place spontaneously without the help of a spark plug. The air taken into the cylinder at atmospheric pressure is compressed to a volume ratio somewhere near to 1:16. At the end of the compression, fuel is injected into the cylinder. The quantity injected depends on the power of the engine, and the heat of compression heats the mass of the air compressed.

The Onion Model: The onion model depicts hazards, barriers and recovery measures. It reflects the layers of protection and shows how the various measures fit together when viewed from the perspective of the hazard. The first layer is the basic containment of our feedstock, processes and products (See Figure 35). The Saybolt Universal Viscometer: Measures the time in seconds that would be required for the total flow of 60cc of oil from a container tube at a given constant temperature through a calibrated orifice placed at the bottom of the tube. Lubricant viscosities are usually measured in Saybolt Universal seconds at 100°F (37.8°C), 130°F (54.4°C) or 210°F (98.9 °C). E.g., the symbol SSU 100 represents the time in seconds that a fluid at 100°F (37.8°C) will take to flow through a given orifice of the Saybolt viscometer. Kinematic viscosity can be converted to Saybolt viscosity SSU by the formula: Kinematic viscosity, v =

149.7 m = 0.219t − r t

where µ = viscosity of fluid in centipoises, cP ρ = density of fluid, g/cc t = Saybolt Universal viscosity, sec.

Theoretical Plate: 1. A theoretical contacting unit useful in distillation, absorption, and extraction calculations. Vapor and liquid leaving any such unit are required to be in equilibrium under the conditions of temperature and pressure that apply. An actual fractionator tray or plate is generally less effective than a theoretical plate. The ratio of a number of theoretical plates required to perform a given distillation separation to the number of actual plates used given the overall tray efficiency of the fractionator. 2. Refers to vapor/liquid contact device (e.g., distillation column) in which the liquid and vapor leaving the device are in perfect vapor/liquid phase equilibrium. There are also

Crude oil Crude oil Loss of containment

Excessive pressure Threat

Figure 36 A threat.

Release of the hazard

Figure 37 Top event.

Glossary of Petroleum and Technical Terminology  919 perfect energy and mass balances for a theoretical tray (See Figure 5). Thermal Cracking: 1. A refining process in which heat and pressure are used to break down, rearrange, or combine hydrocarbon molecules. Thermal cracking includes gas oil, visbreaking, fluid coking, delayed coking and other thermal cracking processes (e.g., Flexicoking). 2. The first cracking process, in which the oil was cracked by heating only. Thermal cracking produces lower octane gasoline than catalytic processes. Thermal Cracked Distillate: Is formed when a distillate heavier than gasoline is heated under pressure in order to break the heavy molecules into lighter ones that boil in the gasoline range. This is superseded by catalytic cracking which gives better distillate. Thermal Conductivity: The ability of a material to let heat pass. Metals, water and materials that are good conductors of electricity have a high thermal conductivity. Air, rubber, and materials that are bad conductors of electricity have a low thermal conductivity. High viscosity hydrocarbons are bad conductors of heat. Thermal expansion: Railroad tracks grow longer in the heat of the sun. The hot tubes in an exchanger grow more than the cold shell. Hence, we have a floating head in the tube bundle to accommodate differential rates of thermal expansion between the tube bundle and the shell. Threat: A threat is something that can cause the release of a hazard and lead to a top event (See Figure 36). Three phase: A mixture consisting of one vapor in equilibrium with two mutually insoluble liquid phases. Threshold Limit Value: The amount of a contaminant to which a person can have repeated exposure for an eight-hour day without adverse effects. Tolerable: Minimum requirements/criteria that have to be met for managing a risk. Toluene (C6H5CH3): 1. Colorless liquid of the aromatic group of petroleum hydrocarbons, made by the catalytic reforming of petroleum naphthas containing methyl cyclohexane (CH3C6H11). A high- octane gasoline blending agent, solvent and chemical intermediate, base for TNT. 2. One of the aromatic compounds used as a chemical feedstock most notoriously for the manufacture of TNT, trinitrotoluene.

Top Event: A top event is the ‘release’ of the hazard, i.e., the first consequence, typically a loss of containment, a loss of control, or an exposure to something that may cause harm, such as the release of hydrocarbons, toxic substances or energy (See Figure 37). Top Product: For columns with condensers, the liquid and/or vapor streams from the reflux drum that exit the process. Topping: Removal by distillation of the light products and transportation fuel products from crude oil, leaving in the still bottoms all of the components with boiling ranges greater than diesel fuel. Topped Crude Oil: 1. Crude that has been run through a distilling unit to remove the gas oil and lighter streams. The long residue is sold as residual fuel. 2. The bottom product from a crude distillation column. Toxic Compounds: NOx, VOCs and SOx are toxic compounds such as formaldehyde, oxides of nitrogen, volatile organic compounds such as pentene and oxides of sulfur. Tray: A liquid/vapor contact device in a distillation column (See Figure 5). Tray Efficiency: See overall tray efficiency Treat Gas: Light gases, usually high in hydrogen content, which are required for refinery hydrotreating processes such as hydrodesulfurization. The treat gas for hydrodesulfurization is usually the tail gas from catalytic reforming or the product from a hydrogen unit. Trip: 1. The fast shutdown of an item of chemical plant or process equipment such as a pump or compressor. The shutdown is the result of a process condition being exceeded such as an abnormal flow, pressure, temperature or concentration, etc. 2. This a safety device that automatically shuts down a piece of equipment. It’s a fail-safe mechanism often activated by unlatching a spring operated valve, which then closes. Troubleshooting: A form of problem-solving methodology used to identify, solve and eliminate problems within a process that has failed or has the potential to fail. It is a logical and systematic search for the source or cause of the problem and solutions presented to ensure that the process is restored back to its full operability. Troubleshooting is applied once a problem has occurred and the process stops functioning. It can take the form of a systematic checklist and

920  Petroleum Refining Design and Application Handbook Volume 2 requires critical thinking. Computer techniques are employed for more complex systems where a sequential approach is either too lengthy or not practical or where the interaction between the elements in the system is not obvious. True Boiling Point distillation (TBP): 1. Of a crude oil or petroleum fractions results from using the U.S. Bureau of Mines Hempel method and the ASTM D – 285 test procedure. Neither of these methods specifies the number of theoretical stages or the molar reflux ratio used in the distillation. Consequently, there is a trend toward applying a 15:5 distillation according to ASTM D2892, instead of the TBP. The 15:5 distillation uses 15 theoretical stages and a molar reflux ratio of 5. 2. A laboratory test in which petroleum oil is distilled in a column having at least 15 theoretical trays and a reflux ratio of 5.0. The distillate is continually removed and further analyzed. The separation corresponds somewhat to a component by component separation and is a good measure of the true composition for the sample being distilled. As the temperatures in the still increase, the pressure of the still is lowered to suppress thermal cracking of the sample. The minimum pressure for most TBP stills is about 38 mm Hg. This allows distillation of petroleum components boiling up to about 900–950°F (483– 510°C) at a pressure of one atmosphere. Surprisingly, the TBP test has never been standardized and several different apparatuses are used for the test. A key result from a distillation test is the boiling point curve, i.e., the boiling point of the oil fraction versus the fraction of oil vaporized. The initial boiling point (IBP) is defined as the temperature at which the first drop of liquid leaves the condenser tube of the distillation apparatus. The final boiling point or the end point (EP) is the highest temperature recorded in the test.

Open

Additionally, oil fractions tend to decompose or crack at a temperature of approximately 650°F (344°C) at one atmosphere. Thus, the pressure of TBP distillation is gradually reduced to as low as 40 mmHg, as this temperature is approached to avoid cracking the sample and distorting measurements of true components in the oil (See Figure 12). Tube bundle: Pipes in a shell and tube heat exchanger that are packed into an arrangement to ensure effective heat transfer from the outer surface and good transport for fluids through the tubes. The tubes in the tube bundle are spaced and typically set with a rectangular or triangular pitch, and held and sealed with a tube plate. Baffles also provide rigidity and encourage turbulent flow of fluids through the shell side. The tubes can be a straight single-pass or hairpin double-pass arrangement. The tube bundle can be removed from the shell for periodic cleaning. Lugs are welded to the baffles for lifting purposes (See Figure 31). Tube size: Tubing sizes are entirely different from pipe sizes. Tubing is often used in heat exchangers and fired equipment. Tube still: See pipe still. Turbine: 1. A machine used to generate electricity by the expansion of a gas or vapor at high pressure through a set of blades attached to a rotor. The blades rotate as the result of the expansion and conversion of energy. Gas turbines and steam turbines are commonly used to generate electricity. A nozzle is used to direct the high-speed gas or steam over a row of turbine blades. The fluid pushes the blades forwards causing them to rotate due to change in momentum. A row of stationary blades within the turbine redirects the fluid in the correct direction again before it passes through another set of nozzles and expands to a lower pressure. A steam turbine may have several pressure sections and

Throttling Diaphragm valve basics

Figure 38 A diaphragm valve.

Closed

Glossary of Petroleum and Technical Terminology  921 operate at high pressure, medium pressure, and as the steam expands, a low-pressure section all linked to the same shaft. The steam in the medium-pressure section may be returned to a boiler and reheated before doing further work to prevent the formation of water in the turbine. 2. A turbine uses steam pressure or burning gas to drive pumps and compressors at variable speeds. Motor drives are usually fixed-speed machines. Variable speed is an energy efficient way to control flows by eliminating the downstream control valve. Turbulent flow: A fluid flow regime characterized by the fluctuating motion and erratic paths of particles. In pipes of circular cross-section, this occurs at Reynolds number in excess of 4000. Turbulent flow occurs when inertial forces predominate resulting macroscopic mixing of the fluid. Turnaround: A planned complete shutdown of an entire process or section of a refinery, or of an entire refinery to perform major maintenance, overhaul, and repair operations and to inspect, test, and replace process materials and equipment. Two phase: A mixture consisting of one vapor in equilibrium with one homogeneous liquid phase. ULSD: Ultra-Low-sulfur diesel. Diesel fuel with < 15 ppm sulfur. Unaccounted for Crude Oil: Represents the arithmetic difference between the calculated supply and the calculated disposition of crude oil. The calculated supply is the sum of crude oil production plus imports

minus changes in crude oil stocks. The calculated disposition of crude oil is the sum of crude oil input to refineries, crude oil exports, crude oil burned as fuel, and crude oil losses. Undistributed Component: A component in a distillation column separation zone that is totally recovered in only one of the products. Unfinished Oils: All oils requiring further processing, except those requiring only mechanical blending. Unfinished oils are produced by partial refining of crude oil and include naphthas and lighter oils, kerosene and light gas oils, heavy gas oils, and residuum. Unfractionated Streams: Mixtures of unsegregated natural gas liquid components excluding, those plant condensate. This product is extracted from natural gas. Unsaturated Compounds: Hydrocarbon compounds in which some of the carbon atoms have multiple bonds with other carbon atoms because of the lack of hydrogen atoms to satisfy the carbon atoms valences. Upper Explosive Limit (UEL): The maximum concentration of vapor in air above which the propagation of flame will not occur in the presence of an ignition source. Also referred to as the upper flammable limit or the upper explosion limit. Utilities: Most plants have some of the following utility systems connected to process units.

Stem Handwheel

Packing gland

Yoke

Bonnet Gate Body

Closed

Figure 39 A gate valve.

Opened

922  Petroleum Refining Design and Application Handbook Volume 2 E Identification disc

Handwheel nut Yoke nut

Handwheel

Gland bolting

Packing gland B (open) C (closed)

Packing

Stem

Yoke Bonnet bolting

Gasket Bonnet Body

Disc nut D

Disc

Internal stem A

Figure 40 A globe valve away section of a globe valve.

Figure 41 Plug valves Cutaway section of a plug valve.

Bonnet gasket

Valve plug stem Packing flange

Spiral wound gasket

Actuator yoke locknut Packing Packing box Bonnet

Cage gasket

Valve plug Cage

Seat ring W0999

Figure 42 A Control valve.

Seat ring gasket Valve body

Glossary of Petroleum and Technical Terminology  923

Figure 43 Relief valves.

Liquid Tray Normal vapour

Tray Low vapour

High vapour

Figure 44 A valve tray.

• • • • • • • • • • •

Natural gas Nitrogen Plant air Instrument air Steam of various pressures Cooling water Service water Boiler feed water Fire water Fuel gas City water

Your company safety policy does not permit you to cross-connect these systems. Connecting natural gas to plant air killed 17 workers at a Louisiana refinery. Vacuum Distillation: 1. Distillation under reduced pressure (less than atmospheric), which lowers the

boiling temperature of the liquid being distilled. This technique prevents cracking or decomposition of the charge stock which occurs above 1000°F (538°C). 2. A distillation column that operates at sub-atmospheric pressure. Vacuum distillation permits the further distillation of heavy feed stocks at reduced temperatures that minimize cracking reactions. Vacuum Gas Oil (VGO): A side stream from the vacuum distillation tower. Vacuum Residuum: The heaviest product from a vacuum distillation column. Valves: A valve is a device that regulates, directs or controls the flow of a fluid (gases, liquids, fluidized solids, or slurries) by opening, closing or partially obstructing various passageways.

924  Petroleum Refining Design and Application Handbook Volume 2 Diaphragm valve: A type of device in which a flexible membrane is used to restrict the rate of flow. The membrane is usually made from a flexible natural or synthetic rubber. Diaphragm valves are typically used for fluids that contain suspended solids (See Figure 38). Gate valve. This valve closes by sliding a plate or gate down between two grooves. Used to isolate different portions of the process equipment not used to control flow. The valve closes clockwise and takes about a dozen turns to close. Ninety percent of the valves used in process plants are gate valves (See Figure 39). Globe valve: A device that regulates the flow of a fluid in a pipe and consists of a flat disc that sits on a fixed ring seat. The disc is movable and allows flow through the valve (See Figure 40). Plug valve: This valve goes from 100% open to shut by turning a valve 90°. The natural gas supply to your house is shut off with a plug valve (See Figure 41). Control valve: This valve is used to alter flows remotely. Normally it is moved by air pressure. A gate valve is sometimes used to control flows locally, but this wears out the valve and is best avoided (See Figure 42). Relief valves: These valves open to relieve excess pressure to protect a vessel from failure. Also called safeties or pop valves (See Figure 43). Valve Trays: 1. Fractionator trays that have perforations covered by discs that operate as valves and allow the upward passage of vapor. 2. In valve trays, perforations are covered by lift-able caps. Vapor flows lift the caps, thus self-creating a flow area for the passage of vapor. The lifting caps direct the vapor to flow horizontally into the liquid, thus providing better mixing than is possible in sieve trays (See Figure 44). Vapor: The gaseous phase of a substance that is a liquid at normal temperature and pressure.

More volatile liquids such as LPG have a higher vapor pressure than less volatile diesel oil. 2. The pressure exerted by a volatile liquid as determined by ASTM D-323, Standard Method of Test for Vapor Pressure of Petroleum Products (Reid Method). 3. Is a measure of the surface pressure necessary to keep a liquid from vaporizing. The vaporizing tendency of gasoline is measured in terms of its vapor pressure. It is related to vapor lock and engine starting. Vapor lock arises due to the vaporization of the fuel in fuel lines, fuel pump, carburetor, etc, making bubbles of vapor, which prevent the normal flow of fuel. This occurs if the gasoline contains too high a percentage of low-boiling components as observed by a very high vapor pressure. Alternatively, if the gasoline contains only too few low boiling components as indicated by a low vapor pressure, then the fuel will not vaporize readily making it difficult in starting. (See Reid Vapor Pressure, RVP) Vapor Lock: Is the phenomenon of insufficient gasoline flow from a fuel pump due to its inability to pump the mixture that results from low pressure or high temperature, which has high volatility. Vapor Lock Index: A measure of the tendency of a gasoline to generate excessive vapors in the fuel line, thus causing displacement of a liquid fuel and subsequent interruption of normal engine operation. The vapor-lock index generally is related to RVP and percentage distilled at 158°F (70°C). Virgin Material, Gas Oil, etc: Virgin material is material distilled from crude oil but not subjected to processes that chemically alter its composition. Virgin Stocks: Petroleum oils that have not been cracked or otherwise subjected to any treatment that would produce appreciable chemical change in their components.

Vapor/Liquid Ratio (V/L): The vapor/liquid ratio (V/L) is the ratio of the volume of vapor formed at atmospheric pressure to the volume of gasoline in a standard test apparatus. The vapor-lock tendency of the gasoline sample can be measured more reliably in terms of its V/L ratio than in terms of its vapor pressure. The V/L ratio also increases with rise in temperature.

Visbreaking: 1. A thermal cracking process in which heavy atmospheric or vacuum-still bottoms are cracked at moderate temperatures to increase production of distillate products and reduce viscosity of the distillation residues. 2. A process in which heavy oil is thermally cracked just enough to lower or break the viscosity. A small quantity of gas oil and lighter products are formed in the process.

Vapor Pressure: 1. As a liquid is heated, the molecules in the liquid try to escape into the vapor phase. The hotter the liquid, the harder they try to escape. The pressure that the molecules of liquid create as they push out into the vapor space is the liquid vapor pressure.

Viscosity ASTM D445: Internal resistance to the flow of liquids is expressed as viscosity. The property of liquids under flow conditions that causes them to resist instantaneous change of shape or instantaneous rearrangement of their parts due to internal friction.

Glossary of Petroleum and Technical Terminology  925 Viscosity is generally measured in seconds, at a definite temperature, required for a standard quantity of oil to flow through a standard apparatus. Common viscosity scales in use are Saybolt Universal, Saybolt Furol, poises, kinematic [stokes, or centistokes (cSt)]. Usually, the viscosity measurements are carried out at 100°F (38°C) and 210°F (99°C). Viscosity is a very important property for the heavy products obtained from the crude oil. The viscosity acts as an important characterization property in the blending units associated to heavy products such as bunker fuel. Typically, the viscosity of these products is specified to be within a specified range and this is achieved by adjusting the viscosities of the streams entering the blending unit. Viscosity Index (VI): This index is a series of numbers ranging from 0 to 100 which indicate the rate of change of viscosity with temperature. A Viscosity Index of 100 indicates an oil that does not tend to become viscous at low temperatures or become thin at elevated temperatures. Typically paraffin-base lubricating oils exhibit a Viscosity Index of nearly 100, whereas naphthenes-base oils on the market show about 40 Viscosity Index, and some naphthenic oils have a Viscosity Index of zero or lower. Paraffin wax has a V.I. of about 200, and hence its removal reduces the V.I. of raw lube stocks. By solvent extraction processes, lubricating oils of Viscosity Index higher than 100 can be produced. Volatile: A hydrocarbon is volatile if it has a sufficient amount of butanes and higher material to noticeably give off vapors at atmospheric conditions. Volatile Organic Compounds (VOCs): Organic chemicals that have a high vapor pressure at ordinary room temperature. Their high vapor pressure results from a low boiling point, which causes large numbers of molecules to evaporate or sublimate from the liquid or solid form of the compound and enter the surrounding air. E.g., formaldehyde (HCHO), which evaporates from paint, has a boiling point of only -19°C (-2°F). One VOC that is a known human carcinogen is benzene, which is a chemical found in environmental tobacco smoke, stored fuels, and exhaust from cars. Benzene also has natural sources such as volcanoes and forest fires. It is frequently used to make other chemicals in the production of plastics, resins, and synthetic fibers. Benzene evaporates into the air quickly and the vapor of benzene is heavier than air allowing the compound to sink into low-lying areas. Benzene has also been known

to contaminate food and water and if digested can lead to vomiting, dizziness, sleepiness, rapid heartbeat, and at high levels, even death may occur. VOCs are many and varied, are dangerous to human health or cause harm to the environment. Harmful VOCs typically are not acutely toxic, but have compounding long-term health effects. Because the concentrations are usually low and the symptoms slow to develop, research into VOCs and their effects is difficult. Volatility: As measured by the distillation characteristics, helps to determine the relative proportion of the various hydrocarbons throughout the boiling range of a gasoline. It is the distillation characteristics along with vapor pressure and vapor/liquid ratio that help to control the performance of the fuel with respect to starting, warm-up, acceleration, vapor-lock, evaporation losses, crankcase dilution, fuel economy and carburetor icing. Volatility Factor: An empirical quantity that indicates good gasoline performance with respect to volatility. It involves actual automobile operating conditions and climatic factors. The volatility factor is generally defined as a function of RVP (Reid vapor pressure), percentage distilled at 158°F (70°C) and percentage distilled at 212°F (100°C). This factor is an attempt to predict the vapor-lock tendency of a gasoline. vppm: Parts per million by volume. VRC: Vacuum reduced crude; vacuum tower bottoms. WABP: Weight average boiling point: n

WABP = ∑ Xwi Tbi i =1

where Xwi = weight fraction of component i. Tbi = average boiling point of component i. Wash Zone: A section in a column where the column vapor is washed of entrained heavy materials by contact with a cooler injected liquid. A section of packed material is often used to promote good mixing of the liquid and vapor in the wash zone. All vacuum distillation columns have wash zones to remove heavy residual material that is carried up the column from the flash zone. If washing is inadequate, the heavy residual material forms petroleum coke and plugs the column above the flash zone.

926  Petroleum Refining Design and Application Handbook Volume 2 Water hammer: A violent and potentially damaging shock wave in a pipeline caused by the sudden change in flow rate, such as by the rapid closure of a valve. The effect is avoided by controlling the speed of valve closure, lowering the pressure of the fluid, or lowering the fluid flow rate.

WCR2 + WCR3), where WCR1, WCR2, WCR3 are the weights of catalysts in reactors 1, 2, 3 and R1IT, R2IT, R3IT are the inlet temperatures for reactors, 1, 2 and 3 respectively.

Water vapor: The gaseous state of water dispersed with air at a temperature below the boiling point of the water. The amount present in air is designated by the humidity. The “relative humidity” is the amount of water vapor in a mixture of dry air. A relative humidity of 100% corresponds to the partial pressure of water vapor being equal to the equilibrium vapor pressure and depends on the temperature and pressure.

Weighted average bed temperature (WABT): [WCR1 (R1IT + R1OT)/2 + WCR2 (R2IT + R2OT)/2 + WCR3 (R3IT + R3OT)/2]/total Weight of catalyst, where WCR1, WCR2, WCR3 are the weights of catalysts in reactors 1, 2, 3; R1IT, R2IT, R3IT are the inlet temperatures for reactors 1, 2, 3 and R1OT, R2OT, R3OT are the outlet temperatures for reactors 1, 2, and 3 respectively.

Watson Characterization Characterization factor

factor

(Kw):

see

Wax: A solid or semi-solid material consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight-chained paraffins series predominate. This includes all marketable wax, whether crude or refined, with a congealing point (ASTM D 938) between 100–200°F (37.8–93°C) and a maximum oil content (ASTM D 3235) of 50 weight percent. Weeping: A phenomenon that occurs in a distillation column in which liquid on a sieve plate passes down through the perforations intended for the vapor to pass up. Weeping occurs when the velocity of the upward vapor is too low. This may be caused by insufficient boil-up. Weir: A vertical obstruction across a channel carrying a liquid over which the liquid discharges. In a distillation column, a weir is used to retain an amount of liquid on a sieve tray or plate. While the vapor enriched with the more volatile component rises up through the perforations on the sieve tray or plate, the liquid cascades over the weir into the downcomer to the tray below. The weir crest is the top of the weir over which the liquid flows. Weighted average inlet temperature (WAIT): [Weight of catalyst in reactor 1 × inlet temperature in reactor 1 + weight of catalyst in reactor 2 × inlet temperature in reactor 2 + weight of catalyst in reactor 3 × inlet temperature in reactor 3]/total weight of catalyst, i.e. [WCR1 × R1IT + WCR2 × R2IT + WCR3 × R3IT]/(WCR1 +

Well: 1. A natural oil or gas reservoir that exists below a layer of sedimentary rock. 2. A hole bored or drilled into the earth for the purpose of obtaining water, oil, gas or other natural resources. West Texas Intermediate (WTI): A type of crude oil commonly used as a price benchmark. Wet Gas: 1. Natural gas that has not had the butane, C4 and natural gasoline removed. Also the equivalent refinery gas stream. 2. A term used to describe light hydrocarbon gas dissolved in heavier hydrocarbons. Wet gas is an important source of LPG. 3. Water that is present in natural gas in offshore platforms. It is necessary to remove the water from the gas for export through subsea pipelines. The pipeline is dosed with corrosion inhibitors to prevent hydrate formation. White Oil: Sometimes kerosene, sometimes treated kerosene used for pharmaceutical purposes, and in the food industry. WHSV: Weight hour space velocity; weight of feed per hour per weight of catalyst. Wick Char: A test used as an indication of the burning quality of a kerosene or illuminating oil. It is defined as the weight of deposits remaining on the wick after a specified amount of sample is burned. What-If Analysis (WIA): A safety review method, by which “What If ” investigative questions (i.e., brainstorming and/or checklist approach) are asked by an experienced and knowledgeable team of the system or component under review where there are concerns about possible undesired events. Recommendations

Glossary of Petroleum and Technical Terminology  927 for the mitigation of identified hazards are provided. (See Process Safety Management/Hazid/Hazop) wppm: Parts per million by weight. Xylene, C6H4(CH3)2: 1. Colorless liquid of the aromatic group of hydrocarbons made from the catalytic reforming of certain naphthenic petroleum fractions. Used as high-octane motor and aviation gasoline blending agents, solvents chemical intermediates. 2. One of the aromatic compounds. Xylene has a benzene ring and two methyl radicals attached and three isomers namely: ortho, para and metaxylene. Used as a gasoline blending compound or chemical feedstock for making phthalic acids and resins. Yield: Either the percent of a desired product or all the products resulting from a process involving chemical changes to the feed.

Zeolites: 1. Compounds used extensively as catalysts, made of silica or aluminum as well as sodium or calcium and other compounds. Zeolites come in a variety of forms – porous and sand like or celatinous and provide the platform for numerous catalysts. The solid zeolites have extensive pores that give very large surface areas. The precise control during fabrication of the pores sizes enables selected access to different size molecules during reactions. 2. A class of minerals that are hydrated aluminosilicates. An aluminosilicate is where some of the Si atoms in silica (SiO4) are replaced with aluminum giving an excess negative charge. Hydrated means that water is strongly associated with these materials by hydrogen bonding. A positively charged counter ion is required to balance the negative charge on the zeolite. Zeolites are extremely porous materials, with a regular internal structure of cavities of defined size and shape.

Appendix D D-1 Process Flow Diagrams Using VISIO 2002 Software Figure D-1. Process Flow diagram (Feed & Fuel Desulfurization Section). Figure D-2. Typical process flow diagram for the production of Methyl Tertiary Butyl Ether (MTBE). Figure D-3. Piping & Instrumentation diagram for Ammonia plant CO2 removal. Figure D-4. Piping & Instrumentation diagram (Ammonia synthesis and refrigeration unit).

D-2 Process Data Sheets 1. Air cooled heat exchanger process data sheet 2. Centrifugal pump schedule: driver 3. Centrifugal pump schedule: pump 4. Centrifugal pump summary 5. Column schedule 6. Construction Commissioning Start-up Checklist 7. Deaerator process data sheet: Deaerator water storage tank 8. Deaerator process data sheet: Deaerator head 9. Drum process data sheet 10. Effluent schedule 11. Equilibrium flash calculation 12. Fabricated equipment schedule 13. Fan/Compressor process duty specification 14. Fractionator calculation summary 15. General services and utilities checklist 16. Hazardous chemical and conditions schedule

17. Heat and mass balances 18. Heat exchanger rating sheet 19. Hydrocarbon dew point calculation 20. Line list schedule 21. Line schedule 22. Line schedule sheet 23. Line summary table 24. Mass balance 25. Mechanical equipment schedule 26. Pipe line list 27. Pipe list 28. Piping process conditions summary 29. Plate heat exchanger data sheet 30. Calculation of pressure drop in fixed catalyst beds 31. Process engineering job analysis summary 32. Pump calculation sheet 33. Pump schedule 34. Relief device philosophy sheet 35. Tank and vessel agitator data sheet 36. Tank process data sheet 37. Tank schedule 38. Tie – in – schedule 39. Tower process data sheet 40. Tray loading summary 41. Trip schedule 42. Utility summary sheet 43. Vessel and tank schedule 44. Vessel and tank summary: driver 45. Vessel schedule 46. Water analysis sheet

929

D

A-1163F [A-FB102] (163-F)

A-1162F [A-FB101] (162-F)

C

3

370 C

o

C

C

A-1160C [A-EA102] (160-C) 6.34(7.42) MMKCAL/HR

CAT. 24.1 M

A-1162J [A-GA102] (162-J)

A-1160L [A-FD102] (160-L)

o

49 C

36762 KG/HR 3 37.2 M /HR 0.991 S.C. 0.76 CPS

C.W.

165 C

o

A-1161C [A-EA103] (161-C) 2.97(3.47) MMKCAL/HR

o

54 C

o

20

1

46 C

o

46 C

C

C

D

C TD

C

C.W.

o

74 C

14.3 2 KG/CM G

A-1162C [A-EA104] (162-C) 0.98 (1.15) MMKCAL/HR

A-1161L [A-FD101] (161-L) 3 VOL. 0.5M

A-1163F [A-FB102] (163-F) MEA SUMP

A-1164J.JA [A-GA101A.B] (164-J.JA)

1.8 M /HR

3

36000 KG/HR 3 36.2 M /HR 0.996 S.C. 0.89 CPS

39

40.7 3 M /HR

A-1165C [A-EA107] (165-C) 1.46 (1.71) MMKCAL/HR

C

36000 KG/HR 37.8 M3/HR 0.951 S.C. 0.31 CPS

0.72 2 KG/CM G o 116 C

17

1

o

95 C

o

110 C 3311 KG/H

A-1163E [A-DA104] (163-E)

H 2S STRIPPER

A-1166C [A-EA108] (166-C) 1.34(1.57) MMKCAL/HR

COND.

C L.P. STM.

A-1163C [A-EA105] (163-C) 2.4(2.8) MMKCAL/HR o

C

C

A-4102J [A-GB101] (102-J) FEED GAS COMPRESSOR

M.P. STM.

CAUSTIC INJECTION

COND.

M.P. STM.

(INTERMITENT)

VAPORIZER

A-1164C [A-EA106] (164-C) (0.3) MMKCAL/HR

393 KG/HR MAKE-UP STRIPPED CONDENSATE

0.3 2 G KG/CM o 50 C

A-1160F [A-FA103] (160-F)

135 C

A-1163J.JA [A-GA103A.B] (163-J.JA)

C.W.

A-1132C [A-EA101] (132-C) (1.38) MMKCAL/HR

C.W.

Figure D-1.  Process Flow diagram (Feed & Fuel Desulfurization Section).

BLANKET N 2 GAS

NATURAL GAS FEEDSTOCK & FUEL

1

C

FUEL GAS TO FUEL SYSTEM

D D

D D

2

C

C

A-1165F [A-FA102] (165-F)

o

A-116OE [A-DA103] (163-E)

o

46 C

H 2S ABSORBER

CAT. 20M

D

A-1101D [A-DA101] (101-D) HYDROTREATER

D

CAT. 3 20M

NOTES:

3

399 C

o

161 C

o

293 C

o

o

371 C

TO A-1101B (A-EC201) (101-B) MIXED FEED HEATER

A-1101B [A-EC205](101-B) FEEDSTOCK HEATER

A-1101B [A-EC207](101-B) HYDROTREATER HEATER

ACID GAS TO A-D203 [A-BD101]

FROM A-4104F [A-FA501](104-F)

1. ITEM NO. IN [ ] PARENTHESIS REFERS TO TEC NUMBERING. 2. ITEM NO. IN ( ) PARENTHESIS REFERS TO MWK NUMBERING. 3. HEAT DUTY IN ( ) PARENTHESIS REFERS TO DESIGN FIGURE. 4. S.G. = SPECIFIC GRAVITY AT OPERATING CONDITIONS. 5. CPS = CENTI POISE AT OPERATING CONDITIONS.

VENT

C

C

810 KG/HR

VENT

3

D

H2 + CO 2

A-11O2DA.DB [A-DA102A.B] (102-DA.DB) DESULFURIZER

C C

C 46 C

C

D

C

A-1116F [A-FA101] (116-F)

930  Appendix D

Figure D-2.  Typical process flow diagram for the production of Methyl Tertiary Butyl Ether (MTBE).

Appendix D  931

Figure D-3.  Piping & Instrumentation diagram for Ammonia plant CO2 removal.

932  Appendix D

Figure D-4.  Piping & Instrumentation flow diagram (Ammonia synthesis and refrigeration unit).

Appendix D  933

934  Appendix D

Appendix D  935

936  Appendix D

Appendix D  937

938  Appendix D

Appendix D  939

Construction Commissioning Start-up Checklist

940  Appendix D

Appendix D  941

942  Appendix D

Appendix D  943

944  Appendix D

Appendix D  945

946  Appendix D

Appendix D  947

948  Appendix D

Appendix D  949

950  Appendix D

Appendix D  951

952  Appendix D

Appendix D  953

954  Appendix D

Appendix D  955

956  Appendix D

Appendix D  957

958  Appendix D

Appendix D  959

960  Appendix D

Appendix D  961

962  Appendix D

Appendix D  963

964  Appendix D

Appendix D  965

966  Appendix D

Appendix D  967

968  Appendix D

Appendix D  969

970  Appendix D

Appendix D  971

972  Appendix D

Appendix D  973

974  Appendix D

Appendix D  975

976  Appendix D

Appendix D  977

978  Appendix D

Appendix D  979

980  Appendix D

Appendix D  981

982  Appendix D

Appendix D  983

984  Appendix D

Appendix D  985

986  Appendix D

Appendix D  987

988  Appendix D

Appendix D  989

990  Appendix D

Appendix D  991

992  Appendix D

Appendix D  993

994  Appendix D

Appendix D  995

996  Appendix D

Trip Schedule.

Appendix D  997

Utility summary sheet.

998  Appendix D

Vessel and tank schedule.

Appendix D  999

Vessel and tank summary

1000  Appendix D

Appendix D  1001

1002  Appendix D

Appendix D  1003

Appendix E

1005

1006  Appendix E

Appendix E  1007

1008  Appendix E

Appendix E  1009

1010  Appendix E

Appendix E  1011

1012  Appendix E

Appendix E  1013

1014  Appendix E

Appendix E  1015

1016  Appendix E

Appendix E  1017

1018  Appendix E

Index

Abrasion, 349 Abrasiveness, 175 Absorber, 28 Absorption, 1, 4, 6 Accumulator, 159 Adiabatic, 73, 185, 200, 205, 207, 244 ADIP, 158 Adsorbent, 269 Aftercooler, 149–151, 154–156 AGA, 237 Alignment, 13 Alkylation, 99, 312–316, 478 Allowable, 348, 438 Altercooler, 153, 159 Annular, 240 ANSI, 76, 122, 322 API, 97–98, 126, 307, 310, 313, 320, 323 Axial, 173, 312, 332, 347, 390, 458 Backplate, 163 Bearing, 345–346, 489, 491 Bearings, 174, 189, 245 Bellows, 339 Below, 87 Bernoulli, 73, 140, 148, 201 Bhp, 419–420, 452

Block, 26, 34, 52 Blowdown, 45, 52 Blower, 42, 44, 51 Brake, 438 Breaker, 374–375, 379, 485 Bubble, 240 Bubbles, 368, 370–374 Bushing, 182 Cameron, 75, 120, 225, 295, 324, 327, 366, 381, 397, 495 CAPCOST, 1, 4, 6 Cavitating, 373–374, 407, 420, 468 Centifugal, 187 Centistokes, 100, 295, 422, 425–426 Centrifugal, 1, 42, 44, 58–59, 101, 157 Chattering, 326 Checklist, 61 Chen, 91–92, 94, 251, 284, 327 Chenoweth, 328 Choke, 200 Churchill, 91–92 Clearance, 136, 312 Code, 322–323 Codes, 23, 40, 43, 50, 52–53 Coker, 65–66, 243, 327–328 1019

1020  Index Colebrook, 87, 91, 107–109, 114, 130, 231, 327 Combustion, 495 Compressibility, 6, 31, 40–66, 68, 78, 87, 144, 146–147, 186, 226, 249, 280, 326, 337 Compression, 33, 79–84, 86–89, 298, 312 Compressor, 41–42, 44–45, 51, 295, 320–321 Compressors, 1, 4, 6, 86, 173, 244 Computer, 23–24, 38–39 Condensable, 6, 229, 298, 336 Control, 178, 197, 200, 281, 300, 317, 338–339 Conveyor, 1, 4, 6 Cooler, 121, 178, 259, 268 Cooling, 28, 76, 152, 158, 186, 329 Corrosion, 55–56, 75, 248, 300, 349, 416, 418, 473, 482 Corrosive, 6 Corrosiveness, 6, 175 Cracked, 309 Cracking, 101, 104, 196, 269 Crane, 130 Crankcase, 322 Crankshaft, 327 Crude, 27, 35 Cryogenic, 1, 338 Cyclone, 41 Cyclones, 1, 4, 6 Damping, 315 Darby, 435 Debottleneck, 269 Debutaniser, 473, 476 Debutanizer, 158–159 Desulfurization, 28 Desulphurization, 103 Dew, 151 Dewpoint, 315 Diesel, 99, 102–104 Discharge, 80, 146, 152, 157, 160, 216–217, 225, 324, 342, 416, 418, 450 Dispersed, 240–242, 246, 250, 258, 273 Distillation, 20, 23 Downflow, 258, 270, 276 Driver, 58–59 Drivers, 1, 4, 6, 30, 338 Drum, 1, 4, 6, 43, 51 Drying, 1, 315, 324, 329 Dukler, 261–263, 268, 290, 328 Economic, 19, 23, 25–26, 63 Efficiency, 416–418, 422, 440, 463–464, 493, 495 Ejector, 1, 4, 5, 6, 45, 51, 176

Ejectors, 278–281, 328 Embrittlement, 161 Emergency, 329 Enthalpy, 31–33, 39–40, 87, 108, 121, 123, 211–212, 214, 217–218, 220, 283, 290–291, 334 Entrainment, 309, 325, 328, 485 Entropy, 40, 215, 291, 337 Environmental, 490 Equipment, 19–21, 23–27, 36, 38, 41, 43, 47, 50–51, 53, 58, 63 Erosion, 310, 416, 418 Exchanger, 1, 4, 6 Exchangers, 27, 58 Exhaust, 151, 153–155 Expanders, 86 Explosion, 478 Factors, 72, 75, 117, 127, 171, 202, 219, 278, 327, 424, 427 Failure, 327, 329 Fan, 1, 4, 6 Fanning, 68, 72–73, 86, 94, 201, 253, 324 Fatalities, 303, 307, 317 Fatigue, 18–19, 26 Fenske, 1, 4, 6 Fittings, 54–55 Flammable, 16, 316, 479 Flashing, 284–286, 289, 329, 373–374, 485 Flixborough, 316–317 Flowsheet, 19, 21, 24–27, 36, 38–39, 43–44, 50–52, 56, 298, 459 Flowsheeting, 24–25, 64 Fluidization, 1, 4, 6 Fluorocarbon, 168–169 Fouling, 1, 4, 6 Friction, 280 Froth, 240, 274 Froude, 270, 273–276 Furnace, 293 Gas, 158 Gasoline, 96–97, 105–106, 109, 126, 303, 307, 309 Gear, 332, 449 Gearbox, 158, 320, 402, 405 Geometrically, 227, 278, 390, 406 Governor, 188, 283 Guidelines, 456 Hazard, 23, 63, 303, 310, 313–314, 318–321 Hazardous, 24, 36, 58, 480, 492 Hazards, 441, 480

Index  1021 HAZOP, 23, 40, 316 Heptane, 256, 462 Heuristics, 1, 167 Hexane, 69–71, 261, 461 Homogeneous, 265, 327 Hooper, 129–132, 136, 327 Horsepower, 347–348, 353, 402, 405, 407, 422, 428, 456 Horsepowers, 204, 288 Hydraulic, 212 Hydrocarbon, 40, 64 Hydrocarbonprocessing, 496 Hydrocracker, 26 Hydrocracking, 99, 101 Hydrofluoric, 478, 482 Hydrogenation, 13, 99 Hydroprocessing, 99 Hydrotreater, 28 Hydrotreating, 103–104 Impeller, 162, 173, 333, 391 Incidents, 487 Incompressible, 96, 140, 143, 148, 201, 203, 459 Index, 101, 248 Inherent, 171, 315, 320 Inherently, 102, 310, 318 Instrument, 27, 39–40, 42, 46, 52 Insulation, 23–24, 27, 58, 176, 249, 302 Integrity, 481 Intercooler, 75, 152 Intermittent, 261 Interstage, 76, 157–158, 162, 164, 191, 271 Isenthalpic, 290 Isentropic, 73, 86, 198, 200–201 Isentropically, 81 Isoamylene, 70 Isobaric, 31 Isobutane, , 63–64, 313–314, 316 Isolation, 478 Isometric, 168, 469 Isometrics, 22, 39 Isopentane, 249 Isothermal, 31–32, 75, 176, 183, 185, 196, 201, 205, 215, 328 Jacket, 312 Kinetics, 1, 4, 6 Knockout, 1 Labyrinth, 182, 216 Laminar, 72, 99, 120, 122

Lapple, 328 Leakage, 101, 182, 313, 321 Leaks, 300, 317, 322 Liquefied, 157, 323 Lockhart, 243–244, 246, 257, 260–261 Louvar, 319, 329 Lubricant, 489 Lubricants, 6, 99 Mach, 180, 182–183, 185, 187, 188, 190, 194–195, 197–198, 204, 227, 228–229, 275, 289, 308, 334 Machine, 178, 202, 244 Machinery, 480 Maintenance, 82, 249, 302–303, 307–308, 312, 316, 318–320, 349, 495–496 Malfunctions, 485 Manufacturers, 23, 52 Martinelli, 243–244, 246–248, 252, 257, 260–261, 328 Material, 19, 21, 23, 25–27, 40, 42, 47, 50, 61, 63 Materials, 303, 311 Mechanical, 19, 21–23, 26–27, 32, 36, 39–41, 50, 58, 87–89, 292, 333, 336, 340, 444–445, 456, 479, 481, 488–489, 495 Metallurgical, 304, 308 Misalignment, 488–489 Mixing, 2, 4, 6 Model, 68, 265, 297–298, 313 Modeling, 469 Modulus, 174, 244–248, 257–258, 260–261 Moisture, 154 Monograph, 231, 233–235, 237, 328 Moody, 70, 72–74, 85–87, 91–92, 94, 107–108, 112, 115, 117, 120, 127–128, 153, 156, 162, 165, 235–236, 251, 253, 284, 324, 327 Mpeller, 187 Multicomponent, 2, 248 Multiphase, 328 Naphtha, 26, 151–152, 303 Nelson, 181 Nitrobenzene, 168 NPSH, 2, 4, 6, 117 NPSHA, 80, 331, 345, 371–374, 376–388, 390, 394, 411, 438, 440, 456, 464, 468–469, 471, 473–475, 477, 485, 487–489, 492 NPSHr, 470–471 NPHSR, 371 Operations, 19, 21, 39–41 Optimization, 24–25 Organization, 19–21

1022  Index Orifice, 42, 44, 53, 432, 464 Orifices, 68, 142–145, 176, 201, 207, 210, 217, 221–226, 324, 326 OSHA, 40, 305, 485, 496 Overpressure, 302, 448 Packing, 15 Packings, 495 Panhandle, 73, 231, 235–237, 253 Patterns, 239–241, 257, 265, 270, 273, 285 Petrochemical, 331, 344, 359, 492 Petroleum, 2, 4, 6, 19–20, 22, 24, 26, 28, 30, 32, 34, 36, 38, 40, 42, 44, 46, 48, 50, 52, 54, 56, 58, 60, 62, 64, 96–103, 105–107, 138, 157, 300–301, 303, 320, 322–323 PFD, 63, 459, 462, 464 PHA, 320 Pigging, 297–298, 300 Pipeline, 184, 253, 298, 300–301, 321, 329, 417 Pipesys, 295, 297–299, 328, 464 Pipework, 65, 168, 316–318 Piping, 2, 4, 6, 21, 23–25, 27, 32, 34, 36, 38–39, 45, 47, 50, 52–56, 58 Plug, 121, 132, 134, 240–242, 244, 252, 258, 261, 265, 273, 313, 316 Plunger, 326, 332, 452, 454 Polyatomic, 57 Polymerization, 63, 92, 241, 308 Polytropic, 33, 175, 207, 244, 270, 291 Power, 416, 418 Pressure, 342, 383 Process, 19–23, 25–29, 31–33, 35, 37, 39–43, 45–51, 53, 55–64 Propane, 190, 195, 309, 311 Propeller, 2 PSHA, 488 Pulsating, 80, 273 Pulsation, 196, 303, 310, 485 Pump, 36, 51–52, 58–59, 158–159, 342, 416, 418, 455 Pumps, 2, 4, 6 Purge, 8, 28 Radial, 337, 458 Ratings, 350 Reaction, 36, 52 Reactor, 2, 4, 6 Reactors, 27, 104, 307, 316–318 Reboiler, 120, 242, 246 Reciprocating, 2, 4, 6, 454, 458 Refineries, 96, 303, 305, 309–310, 313–314, 320

Refining, 2, 19–20, 22, 24, 26, 28, 30, 32, 34, 36, 38, 40, 42, 44, 46, 48, 50, 52, 54, 56, 58, 60, 62, 64, 82, 307, 313 Reforming, 20, 191 Refrigeration, 191, 324 Regenerators, 2 Regime, 83, 240, 242–246, 248, 250, 260–262, 265, 270 Relief, 177–178, 239, 302, 317, 319–321, 323, 326, 329, 448, 450, 492 Retainer, 186 Retrofti, 339 Reynolds, 280, 334 Rotary, 2, 4, 6, 332, 383, 391–392, 424, 427, 448–449, 495 Rotating, 178, 338, 451, 488 Rotor, 449–451 Roughness, 72, 85–88, 327 Rupture, 175, 249, 304, 307, 321, 492 Ruskin, 289–290, 329 Safeguards, 479 Safer, 320, 329 Safety, 75, 80, 169, 177–178, 249, 257, 287, 300, 303, 307, 312, 318–321, 323, 341, 416, 418, 481–482, 485, 496 Sarco, 71, 287–288, 328 Saturated, 85, 118, 179, 217, 326 Saturation, 284 Saybolt, 100–101 Schedule, 122, 214–215, 254, 297 Schedules, 23, 50, 58, 61 Scope, 20–22, 26, 61 Sealing, 416, 418 Sealless, 332 Seals, 161–162, 175, 181, 189, 338 Segregated, 261 Separator, 120, 239 Separators, 23, 51 Sequence, 26, 32, 36, 47, 50, 63 Sequestration, 318 Serghides, 93 Shaft, 333, 342–343 Shutdowns, 489 Simulation, 24, 63, 459–462, 464 Size, 78, 218, 296–297 Slug, 240, 274 Slugging, 297–298 Slugs, 328 Sonic, 177, 181, 187, 194, 202, 228, 282, 326 Sour, 157, 416, 418

Index  1023 Specifications, 22–23, 27, 36, 50, 52–56, 58 Spirax, 288, 328 Stagnation, 198, 203–204 Standard, 34, 40, 54 Stationary, 186–187, 336, 339–341, 452 Stator, 4, 101, 293, 295 Steam, 5, 19, 30, 185, 187–188, 320 Stirrer, 2 Stonewall, 198, 272 Storage, 34, 41–42 Strain, 328 Strainer, 45, 51, 90, 415–418, 479 Stratified, 240–242, 245, 252, 258, 261 Streamlined, 277, 280 Strokes, 452, 456 Stuffing, 336, 339, 489 Subcooling, 372 Subsonic, 185 Suction, 80, 101, 117, 119–120, 151, 153, 157, 161–162, 165–166, 179, 245, 277, 284 Sulfidation, 304 Sulfuric, 118, 168 Superheatsteam, 218 Supersonic, 182 Surge, 198–199, 302 Surging, 197, 200 Sustainable, 101 Synthesis, 24–25 Tailpipes, 319 Technology 48–50, 58–62 Tesoro, 304 Texas, 307, 309 Thermodynamic, 72 Throat, 339 Throttle, 468 Throttling, 336, 376, 378, 419, 479 Thumb, 2, 4, 6 Toxic, 16, 299 Transmission, 107–109, 211, 231–232, 251–253, 321, 324

Traps, 249, 287–288, 319 Troubleshooting, 1, 19, 40, 290, 322, 328, 485, 488–489, 495 Turbine, 2, 320, 332, 334, 495 Turbocompressors, 338 Turbomachinery, 271 Turbulence, 446–447, 492 Underwood, 2 Upstream, 399, 478 Vacuum, 70–71, 75, 177, 181, 250, 277, 281–285, 310, 324–325, 380–382, 477 Valve, 90, 158, 177, 315 Vapor, 383 Vapors, 75, 118–119, 122, 137, 173, 175–177, 181, 220–223, 225 Vaporization, 325, 371 Vaporizing, 371 Vent, 170, 177, 185, 317, 319, 342 Vents, 32, 38 Venting, 177, 273, 276, 307, 317 Venturi, 44, 138, 140, 201 Vessel, 2, 4, 6, 379–381, 476 Vessels, 116, 123, 136, 260, 277, 319, 323 Vibration, 174, 182, 270, 275–276, 322–324, 489, 491 Vibrations, 227, 330 Visbreaker, 26 Viscosity, 342, 424, 427 Vortexing, 374, 446, 485 Washdown, 157 Washer, 333 Wastewater, 61 Water, 34, 43, 62, 64 Wave, 240–242, 245, 258 Wavy, 261 Workflow, 63 Worksheet, 32

About the Author A. Kayode Coker PhD, is Engineering Consultant for AKC Technology, an Honorary Research Fellow at the University of Wolverhampton, U.K., a former Engineering Coordinator at Saudi Aramco Shell Refinery Company (SASREF) and Chairman of the department of Chemical Engineering Technology at Jubail Industrial College, Saudi Arabia. He has been a chartered chemical engineer for more than 30 years. He is a Fellow of the Institution of Chemical Engineers, U.K. (C. Eng., FIChemE), and a senior member of the American Institute of Chemical Engineers (AIChE). He holds a B.Sc. honors degree in Chemical Engineering, a Master of Science degree in Process Analysis and Development and Ph.D. in Chemical Engineering, all from Aston University, Birmingham, U.K., and a

Teacher’s Certificate in Education at the University of London, U.K., He has directed and conducted short courses extremely throughout the world and has been a lecturer at the university level. His articles have been published in several international journals. He is an author of six books in chemical engineering, a contributor to the Encylopedia of Chemical Processing and Design, Vol. 61, and a certified train – the mentor trainer. A Technical Report Assessor and Interviewer for chartered chemical engineers (IChemE) in the U.K. He is a member of the International Biographical Centre in Cambridge, U.K. (IBC) as Leading Engineers of the World for 2008. Also, he is a member of International Who’s Who for ProfessionalsTM and Madison Who’s Who in the U.S.

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