Acid Gas Injection E-Book

• Herausgeber: John Wiley & Sons
• Kategorie: Fachliteratur
• Sprache: Englisch

Seitenzahl: 597

Veröffentlichungsjahr: 2025

Beschreibung

This ninth and final volume in the series, Advances in Natural Gas Engineering, covers gas injection into geological formations, one of the hottest topics in the industry, with contributions from some of the most well-known and respected engineers in the world.

This timely book focuses on gas injection into geological formations and other related topics, which are very important areas of natural gas engineering and build on previous volumes. It includes information for both upstream and downstream operations, including chapters detailing the most cutting-edge techniques in acid gas injection, such as acid gas disposal, modeling, and much more.

Written by some of the most well-known and respected chemical and process engineers working with natural gas today, the chapters in this important volume represent the most state-of-the-art processes and operations used in the field. Not available anywhere else, this volume is a must-have for any chemical engineer, chemist, or process engineer in the industry. Advances in Natural Gas Engineering is a series of books meant to form the basis for the working library of any engineer working with natural gas today.

Leseprobe

Table of Contents

Cover

Table of Contents

Series Page

Title Page

Copyright Page

Preface

1 Acid Gas Injection from Startup to Stability—A Recap of 3 Years of Operation and Troubleshooting

1.1 Introduction

1.2 Startup: Ideal vs. Actual

1.3 Pump Diaphragm Failures

1.4 Corrosion

1.5 Acid Gas Sampling

1.6 Acid Gas Simulation

1.7 Acid Gas Compression Modeling

1.8 Summary

2 Acid Gas Disposal—A View from the Trenches

2.1 Introduction

2.2 Plant Process

2.3 Acid Gas Compressor

2.4 Injection Wells

2.5 Operational Learnings

2.6 Key Design Considerations

2.7 Summary

3 Pipestone Acid Gas Injection System

3.1 Acid Gas System Description

3.2 Acid Gas Pipelines

3.3 Pipeline Leak Detection

3.4 Acid Gas Injection Pump Design

3.5 Relief System Design

3.6 Relief Valve Selection for AGI Pump Discharge Piping Protection

3.7 AGI Pumps and Injection Well Control

3.8 Process Hazard Analysis and SIL-Rated System Considerations

3.9 Conclusion

Acknowledgment

4 Acid Gas Injection Case Study for the Iraqi Region of Kurdistan

4.1 Introduction

4.2 Methodology

4.3 Results

4.4 Acknowledgments

4.5 Nomenclature

References

5 The Success Story of Acid Gas Injection (AGI) in WCSB: The Past, The Present, The Future

5.1 Introduction

5.2 Geology

5.3 Wellbore Design Consideration

5.4 Screening, Ranking, and Storage Potential Estimation

5.5 AGI Outlook

5.6 Application Evolution

5.7 Conclusions

References

6 Hydrates of Carbon Dioxide—A Review of Experimental Data

6.1 Introduction

6.2 Reviewed Literature

6.3 Experimental Techniques

6.4 Description of the Research Work

6.5 Experimental Data Comparison and Analysis

6.6 Conclusions

References

7 Comparison of Models to Data for Phase Equilibria and Properties of CO

2

+ Contaminant Systems

7.1 Introduction

7.2 Previous Review Work

7.3 Property and Vapor–Liquid Equilibria Comparison Results

7.4 Property and VLE Prediction Conclusions

7.5 Implication to Process Design

7.6 Conclusions and Recommendations

References

8 Numerical Investigation and Prediction of Critical Points of CO

2

Binary Mixtures Using GERG-2008

8.1 Introduction

8.2 GERG and Critical Loci

8.3 Key Results, Observations, and Discussion

8.4 Summary

References

9 Alkanolamines—What is Next?

9.1 Introduction

9.2 New Amine Components for Acid Gas Treating

9.3 Operating Experience

9.4 Conclusion

References

10 Anhydrous Triethanolamine as a Solvent for Gases

10.1 Introduction

10.2 Results and Discussion

10.3 Conclusions

Acknowledgment

References

11 CCUS via CO

2

Compression with Reciprocating Compressors

11.1 Introduction

11.2 What is a Reciprocating Compressor?

11.3 Material Selection

11.4 Gas Properties

11.5 Equipment Selection

11.6 Conclusion

12 Process and Design Aspects of Diaphragm Pumps

Nomenclature

12.1 Characteristics of Diaphragm Pumps

12.2 CO

2

and Acid Gas Injection with Diaphragm Pumps

12.3 Blow-Down a Critical Process Step

12.4 Conclusions

References

13 Well Construction and Monitoring Considerations for AGI and CCS Wells

13.1 Methods and Process

13.2 Conclusion

Acknowledgment

14 Downhole Pressure and Temperature Observations at a CO

2

Injector Under Differing Injection Conditions

14.1 Introduction

14.2 Observations

14.3 Summary

References

15 Case Study for the Application of CCUS to a Waste-to-Energy Italian Plant

15.1 Introduction

15.2 CO

2

Capture

15.3 CO

2

Utilization

15.4 Utilities Consumption and Economic Evaluation

15.5 Conclusions

References

16 Key Results of Tomakomai CCS Demonstration Project

16.1 Introduction

16.2 Overview of the Tomakomai Project

16.3 Key Results of Tomakomai Project

16.4 Public Outreach

16.5 Experience of Major Earthquake

16.6 Research, Development, and Demonstration of CO

2

Ship Transportation

16.7 Conclusion

Acknowledgment

References

17 Some Results of ERTF Carbon Capture Pilot Plant

17.1 Introduction

17.2 ERTF Pilot Plant Process Description and Configuration

17.3 Offline and Online Analysis Methods and Measurements

17.4 Test Campaigns

17.5 Model Validation Against Pilot Plant Data and Results (Run #107 Capacity Target)

17.6 Model Validation Against Pilot Plant Data and Results (Run #108 Energy Target)

17.7 Model Validation Against Pilot Plant Data and Results (Run #109 Energy Target)

17.8 Conclusions and Recommendations

Acknowledgment

18 Evaluation of CO

2

Storage Potential in the Deep Mannville Coals of Alberta: Vertical Well Injection Testing

18.1 Introduction

18.2 Methodology

18.3 Results and Discussion

18.4 Conclusion

Acknowledgments

References

19 Dynamic Miscibility of H

2

S/CO

2

with Reservoir Oil in a Middle Eastern Triassic Reservoir

19.1 Introduction

19.2 Description of Reservoir Simulations

19.3 Results and Discussion

19.4 Conclusions

References

20 Quantitative Evaluation of Dynamic Solubility of Acid Gases in Deep Brine Aquifers

20.1 Introduction

20.2 Technical Approach and Analysis

20.3 Description of Reservoir Simulations

20.4 Results and Discussion

20.5 Summary and Conclusions

Acknowledgment

References

21 Highlights of the Northeast BC Carbon Capture and Storage Atlas

21.1 Study Workflow and Deliverables

21.2 Project Outcomes

21.3 Acknowledgments

References

22 A Novel Method for Calculating Average Formation Pressure of Gas-Reservoir-Type Underground Natural Gas Storage

22.1 Introduction

22.2 Methodology

22.3 Numerical Validation

22.4 Field Application

22.5 Conclusions

22.6 Acknowledgments

References

Appendix A—Dimensionless Variable

23 Simulation of Multi-Zone Coupling Flow with Phase Change in Fractured Low Permeability Condensate Gas Reservoir

23.1 Introduction

23.2 Methodology

23.3 Results and Discussion

23.4 Conclusions

Acknowledgments

References

Index

Also of Interest

End User License Agreement

List of Tables

Chapter 1

Table 1.1 Design and current conditions.

Chapter 2

Table 2.1 Summary of productions from ARC’s Dawson Field.

Chapter 4

Table 4.1 Extraction of the key geological indicators for storage site suitabi...

Table 4.2 Well model calculations and results for a reduced list of injection ...

Chapter 5

Table 5.1 Screening matrix for sequestration in saline aquifer.

Table 5.2 Two-level ranking tool.

Chapter 6

Table 6.1 Data gathered during 19 experiments to determine the CO

2

hydrate com...

Table 6.2 Solubility of CO

2

in water.

Table 6.3 Partial pressure and hydrate dissociation pressure of three atmosphe...

Table 6.4 Correlation parameters for Equation 6.12 and average relative errors...

Table 6.5 Summary of the reviewed research papers on CO2 hydrates in the CO

2

-H

Table 6.6 Data point distribution between various equilibrium curves.

Table 6.7 Lower quadruple point Q

1

(I–L

A

–H–V) from various researchers.

Table 6.8 Upper quadruple point Q

2

(L

A

–H–V–L

C

) from various researchers.

Chapter 7

Table 7.1 Pure CO

2

predicted density comparison.

Table 7.2 CO

2

+ H

2

predicted density comparison.

Table 7.3 CO

2

+ CH

4

predicted density comparison near critical (297 K, 7.9 MPa...

Table 7.4 Pure CO

2

predicted heat capacity comparison.

Table 7.5 CO

2

+ H

2

predicted specific heat capacity comparison.

Table 7.6 CO

2

+ N

2

predicted specific heat capacity comparison.

Table 7.7 Pure CO

2

predicted viscosity comparison.

Table 7.8 Nazeri

et al.

[9] viscosity data mixtures.

Table 7.9 CO

2

mixture predicted viscosity comparison.

Table 7.10 Pure CO

2

predicted thermal conductivity comparison.

Table 7.11 CO

2

+ N

2

predicted thermal conductivity comparison.

Table 7.12 CO

2

+ CH

4

predicted thermal conductivity comparison.

Chapter 8

Table 8.1 Comparison of experimental and estimated critical points of (CO

2

+ H

Chapter 9

Table 9.1 Comparison of CO

2

and H

2

S solubility at different acid gas partial p...

Table 9.2 Corrosion rates for MDEA/PZ and a TAA-derivative.

Table 9.3 Calculated capacity increase for train 2 based on measured plant dat...

Table 9.4 Feed gas and sweet gas composition and operating parameters for trai...

Chapter 15

Table 15.1 Flue gas characteristics.

Table 15.2 Electric power requirements for the CO

2

capture section (Figure 15....

Table 15.3 Thermal power requirements for the CO

2

capture section (Figure 15.1...

Table 15.4 Size and main characteristics of the columns for the CO

2

capture se...

Table 15.5 Composition (on a molar basis) of the CO

2

exiting the capture secti...

Table 15.6 Utilities consumption of the CO

2

capture section and of the CO

2

uti...

Table 15.7 Description of material and energy streams in Figure 15.4.

Chapter 16

Table 16.1 Reboiler duty.

Table 16.2 Monitoring items.

Chapter 17

Table 17.1 ERTF scheduled chemical analysis and frequency during the test camp...

Chapter 19

Table 19.1 Description of the cases.

Table 19.2 Composition of the injection acid gas.

Chapter 20

Table 20.1 Reservoir and fluid data.

Table 20.2 Comparison of the results of solubility cases.

Table 20.3 Comparison of the injected and produced H

2

S/CO

2

.

Table 20.4 Comparison of aqueous, oil, and gas components H

2

S/CO

2

.

Table 20.5 Comparison of the Glen Rose Formation cases.

Table 20.6 Summary of the solubility results.

Chapter 22

Table 22.1 Number of UGSs and their gas capacity in different regions of the w...

Table 22.2 Comparison of the model in this paper and the numerical simulation ...

Chapter 23

Table 23.1 Parameters used in calculation.

List of Illustrations

Chapter 1

Figure 1.1 Schematic of acid gas injection train.

Figure 1.2 Design vs. current compression stages.

Figure 1.3 Potential water content crossover at unstable operating conditions.

Figure 1.4 Model layout.

Figure 1.5 Acid gas water content (Y-axis, unit: lb/MMSCF) variation with pres...

Figure 1.6 Case A temperature and water content variation for inlet of stages ...

Figure 1.7 Case B temperature and water content variation for inlet of stages ...

Figure 1.8 Inlet water content, pressure, and water saturation mass flow varia...

Figure 1.9 Inlet feed-specific acid gas water content (Y-axis, unit: lb/MMSCF)...

Chapter 2

Figure 2.1 ARC operations in the Montney Region in Alberta and Northeast Briti...

Figure 2.2 Aerial view of ARC’s Dawson facility with the location of the acid ...

Figure 2.3 Process and instrumentation diagram for the gas sweetening process ...

Figure 2.4 Process and instrumentation diagram for the acid gas compressor at ...

Figure 2.5 Photograph of the acid gas injection well at A13-07-80-14W6.

Figure 2.6 Schematic diagram of the wellhead assembly at the A13-07-80-14W6 in...

Figure 2.7 Cooler tubes showing plugging with calcium carbonate.

Figure 2.8 The failed packing gland on the 5-35 wellhead.

Figure 2.9 The black powder inside the wellhead valves.

Figure 2.10 Results of test on the annular fluid for pH and bicarbonate (HCO

3

-

Chapter 3

Figure 3.1 Block flow diagram of pipestone AGI system.

Figure 3.2 Abnormal strain parameter: vehicle traffic on roadway above buried ...

Figure 3.3 HIFI leak detection system interface.

Figure 3.4 Acid gas/fuel gas transition zone.

Figure 3.5 Profile of acid gas temperature and hydrate formation.

Figure 3.6 Acid gas and fuel gas concentration profile.

Figure 3.7 AGI pump PFD.

Figure 3.8 Acid gas thermal expansion curve.

Figure 3.9 External body cavity thermal relief.

Figure 3.10 Ball valve cavity pressure relief design.

Figure 3.11 Sketch HMI snapshot of discharge header control elements.

Figure 3.12 FKOD and flare stack HMI snapshot.

Chapter 4

Figure 4.1 Notional scheme of acid gas injection (AGI) in the field of study.

Figure 4.2 Comparison of reservoir candidates in the field, pro(s), and con(s)...

Figure 4.3 Cross-section based on seismic image showing the main seal formatio...

Figure 4.4 Graphic results (sensitivity case X, 70%H

2

S, 30%CO

2

): acid gas inje...

Figure 4.5 Results: acid gas injection has been assessed as feasible in the st...

Figure 4.6 Final estimated standard volumes of H

2

S and CO

2

to be stored after ...

Figure 4.7 Risk reduction. Drilling of appraisal wells in the field, data acqu...

Figure 4.8 Main identified risks at reservoir/caprock/wellbore level and their...

Figure 4.9 Storage complex modeling (overburden/reservoir/sealing floor). Inte...

Chapter 5

Figure 5.1 Location, status, and target formation of AGI operations in the WCS...

Figure 5.2 Cumulative mass of CO

2

and H

2

S sequestered in deep saline aquifers ...

Figure 5.3 Spatial distribution of the top targeted formations for AGI operati...

Figure 5.4 Top seven formations being the target of 75% of the AGI operations ...

Figure 5.5 Stratigraphic chart for southern and central areas of the Alberta B...

Figure 5.6 Pass/fail parametric screening flow chart.

Figure 5.7 Step-by-step workflow for AG plume modeling.

Chapter 6

Figure 6.1 Zygmunt Wróblewski around 1884 (www.europhysicsnews.org).

Figure 6.2 Determination of hydrate dissociation point using the isochoric met...

Figure 6.3 p–T phase diagram for the system carbon dioxide–water.

Figure 6.4 Conditions at which the formation of CO

2

hydrate was noticed.

Figure 6.5 CO

2

hydrate dissociation pressure data obtained by Villard.

Figure 6.6 Dissociation pressure of CO

2

⋅6H

2

O obtained using the Hempel and Sei...

Figure 6.7 L

A

–H–V equilibrium curve for carbon dioxide.

Figure 6.8 Hydrate formation with carbon dioxide–water mixtures.

Figure 6.9 Phase equilibria in the carbon dioxide–water system.

Figure 6.10 Dissociation pressure curve of the hydrate CO

2

⋅5¾ H

2

O.

Figure 6.11 Dissociation pressures of carbon dioxide hydrate at Martian condit...

Figure 6.12 Initial hydrate formation for the system carbon dioxide–water.

Figure 6.13 Carbon dioxide hydrate curve data obtained by Vlahakis

et al

.

Figure 6.14 Ice–hydrate–CO

2

vapor (I–H–V) equilibrium curve based on data from...

Figure 6.15 Hydrate-forming conditions for carbon dioxide in the presence of p...

Figure 6.16 Hydrate equilibrium temperature and pressure for carbon dioxide.

Figure 6.17 Three-phase coexistence (T-cycle method) for the pure water system...

Figure 6.18 Three-phase coexistence (first freezing point method) for the pure...

Figure 6.19 Incipient equilibrium data on CO

2

hydrate formation in pure water.

Figure 6.20 Three-phase coexisting curve for the CO

2

hydrate system.

Figure 6.21 Phase equilibrium curve for three phase coexistence of CO

2

hydrate...

Figure 6.22 Hydrate formation conditions in the carbon dioxide–water system ob...

Figure 6.23 Three- and four-phase equilibria in the system carbon dioxide–wate...

Figure 6.24 Hydrate-forming conditions in the system CO

2

–H

2

O. Supplemental dat...

Figure 6.25 P–T diagram with experimental data for the hydrate equilibrium for...

Figure 6.26 CO

2

hydrate formation for three concentrations of CO

2

in water.

Figure 6.27 L

A

–H–V equilibrium data for the CO

2

–H

2

O system.

Figure 6.28 Three-phase equilibrium p–T conditions in a carbon dioxide–water s...

Figure 6.29 Decomposition temperatures of the CO

2

gas hydrate of carbon dioxid...

Figure 6.30 Equilibrium conditions of CO

2

hydrate in the presence of pure wate...

Figure 6.31 Experimental data for L

A

–H–V equilibrium line for (CO

2

+H

2

O) system...

Figure 6.32 Experimental hydrate stability of CO

2

in the presence of distilled...

Figure 6.33 Experimental dissociation points for carbon dioxide hydrates forme...

Figure 6.34 Phase equilibria conditions of CO

2

in pure water.

Figure 6.35 Carbon dioxide hydrate phase equilibrium conditions in pure water.

Figure 6.36 Three-phase equilibrium conditions in carbon dioxide hydrate-formi...

Figure 6.37 Dissociation conditions for CO

2

hydrates in the presence of liquid...

Figure 6.38 Dissociation data of CO

2

hydrates by HP-μDSC.

Figure 6.39 Experimental data for equilibrium points of CO

2

hydrates with fres...

Figure 6.40 Phase equilibrium (hydrate–liquid–vapor) of CO

2

hydrate in pure wa...

Figure 6.41 Experimental data for L

A

–H–L

C

equilibrium curve obtained by the au...

Figure 6.42 Experimental data for the L

A

–H–L

C

equilibrium curve obtained by th...

Figure 6.43 Experimental data for the L

A

–H–L

C

equilibrium curve obtained by th...

Figure 6.44 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.45 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.46 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.47 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.48 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.49 Experimental data for L

A

–H–V equilibrium curve obtained by the aut...

Figure 6.50 Experimental data for L

C

–H–V equilibrium curve obtained by the aut...

Figure 6.51 Experimental data for L

A

–V–L

C

equilibrium curve obtained by the au...

Figure 6.52 Experimental data for I–H–V equilibrium curve obtained by the auth...

Figure 6.53 Experimental data for L

SC

–H–V equilibrium curve obtained by the au...

Chapter 7

Figure 7.1 Specific heat (Cp) vs. temperature at various pressures for carbon ...

Figure 7.2 Pressure–temperature phase diagram for 96% CO

2

+ 4% N

2

binary syste...

Figure 7.3 Pressure–temperature phase diagram for 95% CO

2

+ 5% N

2

binary syste...

Chapter 8

Figure 8.1 Critical curve for binary (CO

2

+ H

2

) estimated with GERG-2008 (Mult...

Figure 8.2 Critical temperature of (CO

2

+ H

2

) as a function of H

2

content esti...

Figure 8.3 Critical curves of (CO

2

+ H

2

) estimated with GERG-2008 (Multiflash ...

Chapter 9

Figure 9.1 TAA-based amine structure with alpha-amino group in the ring and be...

Figure 9.2 Absorption isotherms for 40 wt.% MDEA/PZ (dark gray) and 40 wt.% CA...

Figure 9.3 Apparatus to investigate the oxidative stability of aqueous amine s...

Figure 9.4 Oxidative degradation test with different 40 wt.% amine solutions a...

Figure 9.5 Comparison of the formation of heat-stable salts in RNG plant.

Figure 9.6 Acid gas removal unit in West Texas (train 2).

Figure 9.7 L/G, liquid-to-gas ratio for the two absorbers in the test plant.

Figure 9.8 Sweet gas CO

2

content based on Draeger tube analysis (averaged for ...

Figure 9.9 Example for rich and lean loading with CAPLUS over time from Septem...

Figure 9.10 Rich and lean loading over the gas flow.

Figure 9.11 Iron concentration in the CAPLUS solution over time.

Figure 9.12 CAPLUS has a high pH at a rich acid gas load.

Figure 9.13 Testing apparatus to determine the impact of amines on mole sieves...

Figure 9.14 Reference water breakthrough curve for 4-Å molecular sieve materia...

Figure 9.15 Water breakthrough curves for amine-impregnated 4-Å molecular siev...

Chapter 10

Figure 10.1 Experimental data for the ethane + anhydrous triethanolamine syste...

Figure 10.2 Henry’s law constants of ethane in triethanolamine solutions. Dash...

Figure 10.3 Experimental data for the carbon dioxide + anhydrous triethanolami...

Figure 10.4 Comparison of the Henry’s law constants of ethane and carbon dioxi...

Chapter 11

Figure 11.1 Compressor cylinder.

Figure 11.2 Assembled four-throw reciprocating compressor.

Figure 11.3 Package components.

Figure 11.4 CO

2

phase envelope.

Figure 11.5 Supercritical phase envelope.

Chapter 12

Figure 12.1 Diaphragm pump head.

Figure 12.2 List of liquified gases.

Figure 12.3 Different compression schemes.

Figure 12.4 Phase diagram for CO

2

.

Figure 12.5 Pump-type LGB3.

Figure 12.6 Pump-type G3M.

Figure 12.7 Typical P&ID for an acid gas diaphragm pump.

Figure 12.8 Pressure vs. time graph during depressurization.

Figure 12.9 Temperature vs. time graph during depressurization.

Figure 12.10 Test setup of a diaphragm pump head.

Chapter 13

Figure 13.1 Common dissipation zone monitoring schematics.

Figure 13.2 Common VSP source designs.

Figure 13.3 VSP layout.

Figure 13.4 Modeled fluid replacement/velocity in the event of leak.

Figure 13.5 Forecast time-lapse assessment with leak.

Figure 13.6 Induced seismicity sensor array.

Figure 13.7 Example of DAS-induced seismicity waveform.

Chapter 14

Figure 14.1 Variation of various recorded and inferred downhole properties as ...

Figure 14.2 The temperature trend with depth during a period of warming in the...

Figure 14.3 The temperature trend with depth during a period of cooling in the...

Chapter 15

Figure 15.1 Scheme of the CO

2

capture process applied to the reference WtE pla...

Figure 15.2 (a) Steam consumption and (b) total cooling requirements for diffe...

Figure 15.3 BFD of the soda ash carbonation process for the utilization of the...

Figure 15.4 Schematic of the turbine in the reference WtE plant for a prelimin...

Chapter 16

Figure 16.1 CO

2

-EOR, CCS, storage site survey, and CO

2

ship transportation pro...

Figure 16.2 Image of the deployment of CCS in Japan.

Figure 16.3 Project schedule.

Figure 16.4 Project scheme.

Figure 16.5 Bird’s eye view of facilities.

Figure 16.6 Two-stage absorption process.

Figure 16.7 Geological section.

Figure 16.8 Schematic diagram of the monitoring system.

Figure 16.9 Layout of monitoring facilities.

Figure 16.10 CO

2

injection record of Moebetsu Formation.

Figure 16.11 Micro-seismic events detected.

Figure 16.12 3D seismic survey results.

Figure 16.13 pCO

2

values of seawater.

Figure 16.14 Forum for local residents.

Figure 16.15 Panel exhibition.

Figure 16.16 Exhibit at environmental conference.

Figure 16.17 Site tours.

Figure 16.18 Experiment classes for schoolchildren.

Figure 16.19 Information disclosure system in the city hall of Tomakomai.

Figure 16.20 Location of the 2018 Hokkaido Eastern Iburi earthquake.

Figure 16.21 Change in the pressure and temperature of the Moebetsu Formation ...

Figure 16.22 Necessity of LCO

2

ship transportation in Japan.

Figure 16.23 Schedule and scope of project.

Figure 16.24 R & D for large-scale ship transportation.

Figure 16.25 Geographical locations of Maizuru and Tomakomai.

Figure 16.26 Image of the demonstration ship.

Chapter 17

Figure 17.1 Delta Thermal Kinetics Optimization

®

process flow diagram (...

Figure 17.2 Absorber temperature profiles for the steady-state period 6:00 to ...

Figure 17.3 Maximum temperature and standard deviation for test 107 absorber p...

Figure 17.4 Stripper temperature profiles for the steady-state period 6:00 to ...

Figure 17.5 Maximum temperature and standard deviation for test 107 stripper p...

Figure 17.6 Measured and predicted temperature profiles along the absorber col...

Figure 17.7 Measured and predicted temperature profiles along the stripper col...

Figure 17.8 Absorber temperature profiles for the steady-state period 4:48 to ...

Figure 17.9 Absorber temperature profiles for the steady-state period 2:30 to ...

Figure 17.10 Maximum temperature and standard deviation for test 108 absorber ...

Figure 17.11 Stripper temperature profiles for the steady-state period 4:48 to...

Figure 17.12 Maximum temperature and standard deviation for test 108 stripper ...

Figure 17.13 Measured and predicted absorber temperature profiles, run 108.

Figure 17.14 Measured and predicted temperature profiles along the stripper co...

Figure 17.15 Absorber temperature profiles for the steady-state period 16:10 t...

Figure 17.16 Maximum temperature and standard deviation for test 109 absorber ...

Figure 17.17 Stripper temperature profiles for the steady-state period 16:10 t...

Figure 17.18 Maximum temperature and standard deviation for test 109 stripper ...

Figure 17.19 Measured and predicted temperature profiles along the absorber co...

Figure 17.20 Measured and predicted temperature profiles along the stripper co...

Chapter 18

Figure 18.1 Conceptual model for field pilot used to evaluate the feasibility ...

Figure 18.2 Reservoir layers represented in the simulation model used to simul...

Figure 18.3 Simulation model forecast of CO

2

injection at the two-well field p...

Figure 18.4 Simulation of CO

2

distribution in the inter-well area during pre- ...

Figure 18.5 (Left) Numerical model history-match of pressure data at the injec...

Chapter 19

Figure 19.1 Injection and production performance of acid gas for case 1.

Figure 19.2 Production performance of the oil production for case 1.

Figure 19.3 Injection and production performance of acid gas for case 2.

Figure 19.4 Production performance of the oil production for case 2.

Figure 19.5 Comparison of the results of oil production for case 1 and case 2.

Figure 19.6 Dynamic miscibility for acid gas with reservoir oil system.

Figure 19.7 Simulation-based miscibility profiles for acid gas reservoir syste...

Figure 19.8 Dynamic miscibility of acid gas with reservoir oil over a period o...

Figure 19.9 Dynamic miscibility of acid gas with reservoir oil over a period o...

Chapter 20

Figure 20.1 AGI rate and solubility profiles for Ellenburger Formation case E-...

Figure 20.2 AGI rate and H2S/CO2 solubility profiles for Ellenburger Formation...

Figure 20.3 AGI rate and H

2

S/CO

2

solubility profiles for Ellenburger Formation...

Figure 20.4 Comparison of the cases E-1, E-2, and E-3 for Ellenburger Formatio...

Figure 20.5 AGI and oil production performance for Kurra Chine Formation case ...

Figure 20.6 Moles and mole fraction of H

2

S/CO

2

during oil production period fo...

Figure 20.7 Moles and the percent of H2S/CO2 during oil production period for ...

Figure 20.8 AGI and oil production performance for Kurra Chine Formation case ...

Figure 20.9 Component moles and mole fraction of H

2

S/CO

2

during oil production...

Figure 20.10 Component moles and the percent of H

2

S/CO

2

during oil production ...

Figure 20.11 Component moles and the percent of H

2

S/CO

2

of AGI in Cherry Canyo...

Figure 20.12 Component moles and the percent of H

2

S/CO

2

of AGI in Cherry Canyo...

Figure 20.13 Component moles and the percent of H

2

S/CO

2

of Wilcox Formation.

Figure 20.14 Component moles and the percent of H

2

S/CO

2

for Glen Rose Formatio...

Figure 20.15 Component moles and the percent of H

2

S/CO

2

of Glen Rose Formation...

Figure 20.16 Component moles and the percent of H

2

S/CO

2

of Glen Rose Formation...

Chapter 21

Figure 21.1 Study area with emitters and infrastructure.

Figure 21.2 Depleted pool storage potential per formation.

Figure 21.3 Estimated P10, P50, and P90 storage potential in the mapped aquife...

Figure 21.4 Depleted pools with greater than 5 Mt of storage potential.

Figure 21.5 Total estimated P50 effective CO

2

storage potential combined (stac...

Chapter 22

Figure 22.1 The effective gas storage capacity of various type of UGS

Figure 22.2 Physical model of UGS: (a) Schematic diagram of UGS; (b) The verti...

Figure 22.3 Schematic diagram of the pressure superposition principle.

Figure 22.4 Comparison of the model in this paper and the numerical simulation...

Figure 22.5 AFP variation trend in Xiangguosi UGS during nine injection-withdr...

Figure 22.6 The change of inventory parameters.

Chapter 23

Figure 23.1 Diagram of physical model. The gray entity and black lines represe...

Figure 23.2 TPG and SS data and fitting results (Solid lines are fitting curve...

Figure 23.3 Comparation of model validation data.

Figure 23.4 Pressure drop funnel.

Figure 23.5 Cumulative gas production with various time.

Figure 23.6 Pressure contour on the 600th day.

Figure 23.7 TPG distribution at different times.

Guide

Cover Page

Table of Contents

Series Page

Title Page

Copyright Page

Preface

Begin Reading

Index

Also of Interest

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Scrivener Publishing100 Cummings Center, Suite 541JBeverly, MA 01915-6106

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

Acid Gas Injection

Field, Data, Simulation

Edited by

John J. Carroll

Ying (Alice) Wu

Mingqiang Hao

and

Weiyao Zhu

This edition first published 2025 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© 2025 Scrivener Publishing LLCFor more information about Scrivener publications please visit www.scrivenerpublishing.com.

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Library of Congress Cataloging-in-Publication Data

ISBN 9781394356263

Front cover images supplied by Adobe FireflyCover design by Russell Richardson

Preface

This volume compiles the papers presented at the 9th International Acid Gas Injection Symposium (AGIS IX), which was held in Calgary, Canada in May 2023. The Symposium focused on three related technologies: acid gas injection (AGI), carbon capture and storage (CCS), and CO2 injection for enhanced oil recovery (EOR). Virtually all topics related to these technologies were discussed.

Among the key highlights are the first three chapters, which provide data from plants that actively inject acid gas. These papers where the cornerstones of the Symposium and explore both the successes and challenges associated with AGI, giving a balanced view of its implementation and results.

Additionally, the volume features contributions from companies that manufacture pumps and compressors, detailing their application in acid gas injection and related processes. These papers provide insights into the technical equipment used in AGI, CCS, and EOR, contributing to a comprehensive understanding of these technologies.

This volume also includes several papers that delve into the wells and subsurface aspects of these technologies. These papers focus on topics such as reservoir simulation, offering a deeper understanding of how these technologies interact with subsurface formations.

Finally, the volume contains papers addressing auxiliary topics that are integral to the successful application of these technologies. These include discussions on solvents for acid gas removal and solvents for carbon capture, which are critical for improving the efficiency and effectiveness of both AGI and CCS processes.

JJC, YW, MH, & WZ

June 2023

1Acid Gas Injection from Startup to Stability—A Recap of 3 Years of Operation and Troubleshooting

Loni van der Lee1, Jordan Watson1, Laura Creanga2 and James van der Lee3

1Tidewater Midstream, Grande Prairie, AB, Canada

2SLB, Calgary, AB, Canada

3DexPro, Calgary, AB, Canada

Abstract

The following work summarizes operational challenges encountered at the Tidewater Pipestone facility during startup and first years of operation, specific to AGI. Challenges commonly associated with facility startups were experienced at PSGP (Pipestone Sour Gas Plant) and this was also true for acid gas treatment and handling units. Some of the challenges we encountered in the first few years of operation include maintaining amine unit stability, compressor control/loading, temperature control, well tubing failure, diaphragm failures in acid gas pumps, management of acid gas compression/injection during maintenance and unplanned outages, and development of site-specific maintenance and operational best practices. A combination of operational experience, modeling, fluid analysis, equipment failure analysis, and engineering expertise from multi-disciplinary teams was utilized to mitigate and resolve operational challenges including adaptations to the operational procedures utilized at PSGP to minimize process upsets and equipment downtime based on operational history and experience, engagement with third party vendors and strategies developed for improved unit performance, and use of process simulation as a tool to predict the potential impact of deviant operating conditions and their possible contribution to areas of challenge.

1.1 Introduction

The Tidewater Midstream Pipestone Sour Gas Plant (PSGP) is located approximately 20 km west of Wembley, Alberta. Startup commenced in September 2019 of the facility that was designed to process 100 MMSCFD of sour gas from Montney shale production and its associated liquids.

The amine unit was designed to utilize DGA® (Huntsman) for sweetening gas at 5% H2S and 0.3% CO2, with a resulting target composition of the processed dry acid gas of 95% H2S and 5% CO2. As such, acid gas dehydration occurs via two five-stage compression and cooling trains. After the last stage of compression, diaphragm pumps are utilized to raise the fluid to injection pressures of approximately 20 MPa. Dense phase fluid is then injected into two acid gas wells, both in the Stoddart formation (carbonate aquifer) at ∼3,000-m depth, with a reservoir pressure of 28 MPa, with an approximate permeability of 10 mD. Power is generated onsite by two gas turbines.

Table 1.1 Design and current conditions.

Design

Current

Acid gas flow rate

160 E3m3/day5.66 MMSCFD

Composition

H

2

S

90 mol%

80–85 mol%

CO

2

5 mol%

9–13 mol%

H

2

O

5 mol%

6 mol%

Water content after 4th stage

3.4 g/Sm

3

214 lb/MMSCF

4.3–4.8 g/Sm

3

275–305 lb/MMSCF

1st stage suction temperature

43.3°C

40–45°C

1st stage suction pressure

34.5 kPa [g]

42–45 kPa [g]

5th stage discharge pressure

6,895 kPa [g]

5,250–5,600 kPa [g]

Injection temperature

60°C

40°C

Injection pressure

23 MPa [g](max pump SD)

15–20 MPa [g]

The original design and current operating range for the acid gas compression/injection train are as shown in Table 1.1.

Figure 1.1 Schematic of acid gas injection train.

Figure 1.2 Design vs. current compression stages.

The acid gas injection train is comprised of three sections/skids—acid gas compression (2X50%), acid gas pump (2X50%), and acid gas injection. Figure 1.1 shows the major pieces of equipment and points of control.

Given the high H2S concentration expected in the acid gas processed at PSGP dehydration was expected to be reasonably achieved via compression and cooling even if CO2 concentration should increase, as can occur in area production. In 2019 acid gas H2S content was ∼90 mol% (dry basis) but since late 2022 this has dropped to 85 mol% (dry basis) as CO2 concentration has increased. Figure 1.2 shows the design and a potential current operating curve, along with two operational phase envelopes and the hydrate curve at compressor suction. The difference in 5th stage discharge pressure is a function of both composition and temperature exiting the cooler upstream of the accumulator on the pump skid.

1.2 Startup: Ideal vs. Actual

The startup of a new facility, let alone a sour gas plant, is always going to be an enlightening experience. Operation is not steady, not typical and not tuned. Every design “assumption” is simultaneously tested under circumstances where even the best design can be challenged at times. It is also an opportunity for the more mundane best practices around valving and isolation to standout as commissioning, startup activities and frequent process trips will direct flow at conditions that are far from ideal and modifications to better align actual and ideal will be frequent and require immediate attention and alteration. An isolation philosophy that considers timely repairs and maintenance will be invaluable. This includes isolation on flare, drain, and utility connections as these are sometimes less considered but can add substantial downtime to repairs and maintenance if no isolation is available to allow for safe work. Also, it is vital that compressor drains on acid gas package be protected with check valves so there is no potential back flow into the compressor/pump skid. The cost of clean-up alone is far greater than that of a few check valves let alone the associated downtime.

During the initial facility startup interactions between the startup sequence and permissives of the separate compressor-pump-injection skids caused some challenges. When operating an acid gas injection system similar to that at PSGP, where each of the three segments are designed as individual packages, it would be helpful for design teams to carefully review the startup and shutdown sequences with the operations team, with vendor and programming support on hand. As one example, a minimum accumulator level will be required to start the acid gas pumps. Once that permissive is met the pumps need to start before the accumulator hits high-level shutdown. The default timer setting for the pump to complete its startup may be calculation based, but what is experienced in a facility processing inconsistent volumes at variable conditions can be quite different than these calculated rates and startup timings or shutdown ranges may need to be adjusted.

The amine unit has a significant impact on the stability of an AGI unit at a gas processing facility. If this unit has a design optimized strictly to design conditions the supply of and condition of acid gas entering the AGI train can be problematic during the startup period as flows may be low and quality poor. Even once amine operation is stabilized adequately, appropriately placed telemetry and control devices on the amine reflux condenser is critical to maintaining acid gas quality. Something as simple as ensuring temperature transmitters are placed as close to the cooler outlet as possible or adding positioners to control valves assemblies can make a significant difference to acid gas feed stability. Once volumes at PSGP were sufficient to operate both acid gas compression trains it became quite apparent that modifications to the original compressor loading philosophy were required to avoid significant operator intervention to manage loading oscillation. This prevented smooth transition anytime units were taken down or started before/after maintenance, leading to additional downtime and flaring. This was resolved at PSGP with the addition of a common suction line pressure transmitter and a Master PID loop and some logic for load sharing/unit selective control.

For sites like PSGP that produce their own power there is an additional startup complication of power stability. After 3 years in operation problems with power stability are infrequent to the point of non-existent, but at startup gas turbines are another piece of equipment that adds to the complexity of startup as there are operational and programming systems to streamline and troubleshoot. In our experience most of these challenges centered around communications between power generation and waste heat recovery, but whatever the cause, loss of power can have serious implications to an acid gas injection train and strategies around unplanned downtime for any reason, including loss of main power should be considered. Will any blowdowns be triggered in the AGI train? Is it possible that any area of the system could drop to temperatures where the acid gas is now over saturated? Is mitigation required if this does occur and what is the mitigation? Is there adequate redundancy/protection via back up power, line insulation? How much time offline is acceptable before blowdown is initiated?

1.3 Pump Diaphragm Failures

After a few months of more stable operation pump diaphragms began to fail with a high frequency. Diaphragm failures even included a double failure where hydraulic oil was contaminated with acid gas. This prompted a series of reviews involving operations and both the skid and pump vendors. Initial assessments focused on the potential for hydrate formation and cavitation. However, after a thorough review of operating data both were determined to be unlikely based on available information. Double diaphragm failures were thought to potentially be attributed to the replacement of failed solenoid valves on the leak detection system with needle valves, but double failures continued to occur (albeit infrequently) even after replacement parts were installed and confirmation that leak detection was functioning as intended. Alarm actions and maintenance/repair procedures were also reviewed and changes implemented as required. A pump teardown did also not lead to any significant indication of root cause.

We did note that failures would often be associated with maintenance events (i.e., failure of a diaphragm post repair of a different diaphragm) so one area of focus was blowdown and startup procedures for the pumps. This failure pattern indicated that the blowdown and/or startup procedures were contributing to diaphragm losses and after a review of our own blowdown/startup procedures it was noted there was a potential for high velocities/flow rates across the diaphragm face which could contribute to accelerated wear. After a review of previous blowdown/startup related issues in similar systems Tidewater opted to modify the acid gas pump skids to accommodate a low impact blowdown and startup. This was approached in stages as time was required to design and construct some portions of the modifications. The first stage was to modify the methanol injection system to delivery to the suction of either acid gas pump in order to deliver batch volumes of methanol during the manual unit blowdown. Batch rates will not exceed the normal fluid rate of the pumps. In conjunction the pump skid is prepped for maintenance by completing sectional blowdowns—accumulator/suction bottle/discharge bottle to avoid high velocities across the pump heads/diaphragms during the blowdown process. The second stage of modifications was the addition of controlled fuel gas flow. A simple system with a regulator, rotameter and throttling valve was tested first, but results were inconsistent. A more automated system with a flow controller was then installed on each pump skid to ensure consistent flow and blowdown time for every event. Since implementing these changes diaphragm replacements have decreased by nearly 70%. The associated saved downtime for repairs is approximately 250 h a year for average repair times or 500 E3m3 equivalent potential flared AG volume.

1.4 Corrosion

After about 2 years in operation both acid gas injection wells had new tubing installed as the original coated carbon steel tubing failed due to corrosion. An assessment was completed of the failed tubing to determine likely root cause and based on the observed type of corrosion it was determined that the presence of a water phase must have occurred. Some coating defects were also identified, which could have contributed to accelerating corrosion as water could be trapped between the coating and tubing wall. The failed tubing was replaced with uncoated L80 carbon steel tubing.

There are limited sources of water—either flowback from the aquifer (unlikely) or from the process. Given the H2S composition it should be unlikely that the fluid is entering the well at risk of being over-saturated as long as design conditions are satisfied. However, as discussed earlier, the acid gas injection train has not always been able to operate at “design conditions”. It is these deviations that the acid gas is not undersaturated for a part of the process, allowing a water phase to form. Figure 1.3 demonstrates this with some typical water content curves at operating conditions that could be common during amine process instability, particularly in the winter months. Ideal dehydration point is the lowest point in the 55°C water content curve (90% H2S). A typical operating pressure after 4th stage compression is circled and to the left of the “ideal” dehydration point. This is equivalent to a calculated water content of about 280 lb/MM. The water content curves for 65 and 70°C are representative of short term high temperatures measured on fourth stage compression during an upset. If temperatures remain high through the remainder of the acid gas injection train and into the well the formation of a water phase is perhaps unlikely. However, this is not what occurs. And, particularly through winter months, it is quite likely to see temperatures of 25°C or lower through the latter part of the acid gas injection train. Example cooling events could include:

Over cooling in pump subcooler at low winter ambient

Cooler injection line temperatures

Times of low/no flow in injection line

Outages

Loss of heat trace/gaps in insulation

Figure 1.3 Potential water content crossover at unstable operating conditions.

Events that can concur with high 4th stage cooler outlet temperatures:

Amine reflux condenser outlet temperatures are severely elevated

Transitions from recycling to flowthrough on acid gas compression

Temperature swings on 3rd and 4th stage compression

As we have been focused on continuously improving reliability and operability at PSGP many of these issues are gone or significantly reduced:

Additional measurement and automation for better reflux condenser control

Acid gas compressor loading control

Acid gas cooler freeze protection modifications

Additional heat tracing and insulation on AG injection lines

Frequent checks of EHT panels by on instrumentation and operator rounds

Improved plant stability and less frequent shutdowns/trips

Amine unit improvements to stabilize its operation

Inlet volume control

Additional strategies that we have contemplated:

Determine if measured water content is in line with expectations

Integration of a water content/phase envelope module to inform board operators of degree of deviance/act as control variable in control loop.

1.5 Acid Gas Sampling

ASRL (Alberta Sulfur Research Limited) has developed an analytical procedure for measuring water content in pressurized acid gas samples. In order to determine if the water content of the acid gas was within thermodynamic expectations two samples were taken at available points on each injection line. Samples were collected in 150 mL stainless cylinders rated to 5,000 psig. These cylinders were prepped by a local lab for testing to remove trace amounts of air and water before sampling. A laboratory sampling technician also worked with our operations staff to develop an appropriate sampling procedure and review the connections that were in place would provide a means to purge and collect a representative sample. They then returned to site on the day of testing, collected the samples and ensured their delivery in an insulated vessel to ASRL. At the time of sampling one compressor train was fully loaded and operating at stable, typical conditions while the second train had was recycling some flow (due to an upstream problem that required a partial throughput reduction to the plant). The third and fourth stage cooler outlets were oscillating about 5°C–10°C but otherwise operating conditions were reasonably consistent between the two trains. Both samples were tested and the results were 225 lb/MM in one cylinder and 221 lb/MM (∼3.5 g/m3) in the second sample, proving that under typical operating conditions (even with a bit of recycling) that the expected water content is reasonable.

1.6 Acid Gas Simulation

A dynamic model of the acid gas compression system representative of the PSGP was created using the Symmetry Platform modeling tool. The model was used to analyze plant behavior and obtain more insight into plant operations. A few different scenarios were studied, particularly the impact of inter-stage temperature variations and inlet flow deviations on important product parameters, such as water content due to the importance of this parameter.

The modeling effort is focused on the acid gas compression system only. At this stage in the process, the acid gas is being compressed from ∼45 kPa to ∼5,200 kPa before being cooled and sent to the acid gas pump to attain a discharge pressure of ∼16,900 kPa and transport the gas through a pipeline to the acid gas injection well.

The model is set up to be representative of the PSGP acid gas compression and injection process. The compression system consists of five stages of compression. Each compression stage includes an inlet scrubber, compressor, and an inter-stage air cooler. First compression stage compressor contains two cylinders, and the other four stages have one cylinder. In addition, the system contains a recycle to ensure stable first stage compression inlet pressure.

An important step in the compression process is removal of water via cooling the compressed gas after each compression stage. Water is then collected in the suction scrubber of the next compression stage. The accumulated water is then sent to the produced water storage via the liquid outlet piping of the inlet scrubber. Each inlet scrubber has a level control incorporated into the model to ensure a certain level % is kept inside of each stage’s inlet scrubbers. In addition, the vapor outlet is connected to a relief device to represent connection to the flare system.

In order to maintain a certain outlet temperature after each cooling stage each inter-stage air cooler has a temperature control incorporated into the model. Additionally, there are multiple pressure and temperature indicators between compression stages, to track these important parameters and provide with additional flexibility if setting up a controller is required.

The inlet stream has dry gas composition specified, as obtained from the lab analyses. At the inlet to the first stage compression inlet scrubber, the model contains a saturator in order to saturate the acid gas with water at the inlet pressure and temperature, which will depict the real case scenario. The model process flow diagram as seen in the modeling tool is presented in Figure 1.4.

Information from the plant operations and engineering documents was utilized to model the acid gas compression system. The first step in modeling the system was to input all the equipment data. For the compressors’ information, data such as the cylinder bore diameters and cylinder stroke distance was specified, as well as the compressor design speed and clearances, where known.

Figure 1.4 Model layout.

The volumes for the following vessels were considered and specified to represent the system, based on the plant documentation:

Suction scrubbers

Intercoolers

Suction and discharge bottles

Operating parameters were specified where necessary, and calculated results were checked versus real plant performance to ensure accuracy.

1.7 Acid Gas Compression Modeling

One of the most important acid gas properties is the water content. Water presence in acid gas can cause multiple issues especially if condensation of the present water occurs, which can lead to increased pressure drop in the pipeline and corrosion problems. Thus, water content is an important design consideration, and a certain limit must be maintained regarding acid gas water content.

It is important to discuss phase equilibria of H2S + CO2 + water systems and their behavior. In addition, presence of methane can influence the behavior of the system further, even in small quantities. There are many methods that exist to calculate water content of acid gas and a few various thermodynamic models can be used to characterize the system. For the purposes of this modeling exercise, the symmetry thermodynamic model Advanced Peng Robinson (APR) for Natural Gas 2 was utilized, which contains extensive validation with experimental data for various phase equilibria systems.

Figure 1.5 Acid gas water content (Y-axis, unit: lb/MMSCF) variation with pressure (X-axis, unit: psia) at different temperatures (unit: °C).

For reference, a water content map was created which depicts the water content variation with pressure and temperature for the acid gas composition of the PSGP. The water content graph is presented in Figure 1.5.

PSGP has previously had operational issues surrounding water content. The model was utilized to gain further understanding of the impact of certain operational disturbances on acid gas water content.

There were several scenarios that were run using the model:

Third stage temperature controller upset which causes a variation of around 10°C–15°C every 3 min.

Inlet feed variation +/-5% to represent frequent amine reflux separator outlet stream variation.

Prior to discussing each of the analyzed scenarios, an interesting observation is worth noting, which has been identified during the model results vs plant data validation phase. When analyzing water content between stages, it was noted that the final stage water content was calculated to be higher than the previous stage. Normally, an equal or lower final water content would be expected, due to more water being removed in the last stage scrubber.

Most simulation modeling is performed under the assumption that the stream content is at thermodynamic equilibrium. In the real world, this might not be the case because of low interfacial mass transfer. One way to model this is using the concept of efficiencies. Holdup efficiencies model the movement towards equilibrium of the material already in the holdup (phases already present in the separator). There are several efficiency types that can be specified for the holdup in symmetry, which will influence the movement towards equilibrium between the holdup and the inlet.

In this case, it was observed that the separation efficiency was set to “equilibrium” which means that all phases are in 100% contact with each other, and are considered to be completely mixed. This assumption led to the acid gas being saturated with water from the liquid phase, which leads to higher final water content. Similarly, if the efficiency was set to “zero” which means no mass transfer occurs between phases, the final water content was the same as previous stages. It is hard to establish which behavior is closer to reality due to lack of experimental data; however, it is an aspect worth considering when studying these systems.

a. Third stage temperature controller upset which causes a variation of around 10°C–15°C every 3 min.

This scenario was set-up to analyze the impact of third stage temperature variation 10°C–15°C every 3 min on acid gas water content at the in suction of fourth and fifth stages as well as the discharge of fifth stage.

Two models were run, considering a stage three, four and five scrubber separation efficiency of (A) zero and (B) equilibrium.

Both models show an overall tendency for water content to increase significantly when the first temperature variation happens, and as the variation continues, the general trend is down from the original first peak. The water content difference is ∼50 lb/MMSCF more than original number in case A and ∼10 lb/MMSCF in case B equilibrium case. The resulting trends for both cases are presented in Figures 1.6 and 1.7.