Acid Gas Injection
Description
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.
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Persons
John J. Carroll, PhD, PEng, is the Director, Geostorage Process Engineering for Gas Liquids Engineering, Ltd. in Calgary, Canada. Dr. Carroll holds bachelor and doctoral degrees in chemical engineering from the University of Alberta, Edmonton, Canada, and is a registered professional engineer in the provinces of Alberta and New Brunswick in Canada. His fist book, Natural Gas Hydrates: A Guide for Engineers, is now in its second edition, and he is the author or co-author of 50 technical publications and about 40 technical presentations.
Ying (Alice) Wu is currently the President of Sphere Technology Connection Ltd. (STC) in Calgary, Canada. From 1983 to 1999 she was an Assistant Professor and Researcher at Southwest Petroleum Institute (now Southwest Petroleum University, SWPU) in Sichuan, China. She received her MSc in Petroleum Engineering from the SWPU and her BSc in Petroleum Engineering from Daqing Petroleum University in Heilongjiang, China.
Mingqiang Hao, PhD, is a senior engineer of reservoir engineering and the deputy chief engineer of Oilfield Development at the Research Institute of Petroleum Exploration &Development (RIPED), PetroChina. His current main research interests focus on CO2-EOR and horizontal well for low permeability reservoirs.
Weiyao Zhu is a Professor of Mechanics at the University of Science &Technology, Beijing, holding the Chair in the Department of Building Environment of Energy Engineering and the Institute of Applied Mechanics. He is also the director of Mechanical disciplines at the University of Science &Technology Beijing. He has served as an editor of some Chinese academic journals, and as an Associate Editor of the Journal of Natural Gas Engineering. He has published twelve books and over 330 research papers and has 17 patents and 26 software copyrights to his credit. He has also been recognized with many professional and academic awards.
Content
Preface xv
1 Acid Gas Injection from Startup to Stability- A Recap of 3 Years of Operation and Troubleshooting 1
Loni van der Lee, Jordan Watson, Laura Creanga and James van der Lee
1.1 Introduction 2
1.2 Startup: Ideal vs. Actual 4
1.3 Pump Diaphragm Failures 6
1.4 Corrosion 7
1.5 Acid Gas Sampling 9
1.6 Acid Gas Simulation 9
1.7 Acid Gas Compression Modeling 11
1.8 Summary 16
2 Acid Gas Disposal-A View from the Trenches 19
Kristopher Kruse
2.1 Introduction 20
2.2 Plant Process 21
2.3 Acid Gas Compressor 23
2.4 Injection Wells 25
2.5 Operational Learnings 26
2.5.1 Cooler Plugging 27
2.5.2 Wellhead Sealing 28
2.5.3 Wellhead Valve Stem Weeping 28
2.5.4 Elastomer Leak at Packer 29
2.5.5 Startup Issues 30
2.5.6 Amine Foaming 32
2.6 Key Design Considerations 32
2.6.1 Importance of Team 33
2.7 Summary 34
3 Pipestone Acid Gas Injection System 35
Rinat Yarmukhametov, James R. Maddocks, Tim Oldham and Dan Simons
3.1 Acid Gas System Description 36
3.2 Acid Gas Pipelines 37
3.2.1 Environmental and Social Impact Assessment of Pipelines 37
3.2.2 Acid Gas Pipeline Risk Mitigation Steps 37
3.2.3 Emergency Planning Zones (EPZ) 38
3.2.4 Acid Gas Pipeline De-Inventory and Filling Procedures 38
3.3 Pipeline Leak Detection 38
3.3.1 Operational and Emergency De-Inventory of Acid Gas Pipelines 40
3.4 Acid Gas Injection Pump Design 43
3.5 Relief System Design 44
3.5.1 Thermal Relief in Acid Gas Applications 44
3.5.2 Process Piping Criteria/Considerations for Determining Thermal Relief Needs 44
3.5.3 Thermal Relief Mitigation Strategies in Valves 45
3.5.4 External Body Cavity Thermal Relief System 46
3.5.5 Additional Thermal Relief Mitigation Strategies 48
3.6 Relief Valve Selection for AGI Pump Discharge Piping Protection 48
3.7 AGI Pumps and Injection Well Control 49
3.8 Process Hazard Analysis and SIL-Rated System Considerations 51
3.9 Conclusion 53
Acknowledgment 53
4 Acid Gas Injection Case Study for the Iraqi Region of Kurdistan 55
Mariana Alvis and Federico Games
4.1 Introduction 55
4.2 Methodology 57
4.2.1 Container Selection 57
4.2.2 Containment 59
4.2.3 Injectivity 61
4.2.4 Well and System Flow Modeling 62
4.2.5 Injector Well(s) 63
4.2.6 Surface Facilities Strategy 64
4.3 Results 65
4.4 Acknowledgments 69
4.5 Nomenclature 70
References 70
5 The Success Story of Acid Gas Injection (AGI) in WCSB: The Past, The Present, The Future 73
Mohammad Tavallali, Robyn Swanson, Norbert Alwast, Vadim Milovanov and Ashley Anderson
5.1 Introduction 74
5.2 Geology 76
5.2.1 Keg River Formation 76
5.2.2 Pardonet/Baldonnel Formation 79
5.2.3 Belloy Formation 79
5.2.4 Halfway Formation 80
5.2.5 Nisku Formation 80
5.2.6 Leduc Formation 81
5.3 Wellbore Design Consideration 81
5.3.1 Wellbore Damage Mechanisms Encountered During AGI 81
5.3.2 AGI Wellbore Damage Prevention and Control 82
5.3.3 Well Construction and Monitoring Considerations 83
5.4 Screening, Ranking, and Storage Potential Estimation 83
5.5 AGI Outlook 88
5.6 Application Evolution 88
5.6.1 Alberta 89
5.6.2 Saskatchewan 89
5.6.3 British Columbia 90
5.6.4 AGI Comparison Between Canada and USA 90
5.6.5 CCUS Comparison Between Canada and USA 91
5.7 Conclusions 91
References 93
6 Hydrates of Carbon Dioxide-A Review of Experimental Data 97
Bogdan Ambrozek and Eugene Grynia
6.1 Introduction 97
6.2 Reviewed Literature 98
6.3 Experimental Techniques 107
6.4 Description of the Research Work 109
6.5 Experimental Data Comparison and Analysis 168
6.6 Conclusions 179
References 184
7 Comparison of Models to Data for Phase Equilibria and Properties of CO 2 + Contaminant Systems 189
Wayne D. Monnery
7.1 Introduction 189
7.2 Previous Review Work 190
7.3 Property and Vapor-Liquid Equilibria Comparison Results 192
7.3.1 Density 192
7.3.2 Specific Heat Capacity 194
7.3.3 Viscosity 195
7.3.4 Thermal Conductivity 197
7.3.5 Vapor-Liquid Equilibria 198
7.4 Property and VLE Prediction Conclusions 199
7.5 Implication to Process Design 201
7.5.1 Liquid Chemical Absorption Process 201
7.5.2 Compression and Pumping 202
7.5.3 Heat Exchange 202
7.5.4 Pipelines 202
7.6 Conclusions and Recommendations 203
References 203
8 Numerical Investigation and Prediction of Critical Points of CO 2 Binary Mixtures Using GERG- 2008 205
Eduardo Luna-Ortiz
8.1 Introduction 205
8.2 GERG and Critical Loci 206
8.3 Key Results, Observations, and Discussion 207
8.4 Summary 210
References 211
9 Alkanolamines-What is Next? 213
Jörn Rolker and Joe Lally
9.1 Introduction 213
9.2 New Amine Components for Acid Gas Treating 215
9.3 Operating Experience 221
9.4 Conclusion 231
References 231
10 Anhydrous Triethanolamine as a Solvent for Gases 233
A.E. Mather, F.-Y. Jou and K.A.G. Schmidt
10.1 Introduction 233
10.2 Results and Discussion 234
10.3 Conclusions 237
Acknowledgment 237
References 237
11 CCUS via CO 2 Compression with Reciprocating Compressors 241
Patrick Campbell
11.1 Introduction 241
11.2 What is a Reciprocating Compressor? 242
11.3 Material Selection 243
11.4 Gas Properties 244
11.5 Equipment Selection 247
11.6 Conclusion 248
12 Process and Design Aspects of Diaphragm Pumps 249
Rüdiger Bullert
Nomenclature 250
12.1 Characteristics of Diaphragm Pumps 250
12.2 Co 2 and Acid Gas Injection with Diaphragm Pumps 252
12.3 Blow-Down a Critical Process Step 255
12.4 Conclusions 258
References 259
13 Well Construction and Monitoring Considerations for AGI and CCS Wells 261
Ryan Bartko, Ben Banack and Henry Bland
13.1 Methods and Process 261
13.1.1 Pressure Measurement in Dissipation Zones 262
13.1.2 Considerations for 2D/3D/VSP Source and Sensor Design 264
13.1.3 Induced Seismicity Monitoring 265
13.1.4 Sensor Considerations and Magnitude Quantification 266
13.2 Conclusion 269
Acknowledgment 270
14 Downhole Pressure and Temperature Observations at a CO 2 Injector Under Differing Injection Conditions 271
Stephen Talman, Alireza Rangriz Shokri, Nathan Deisman and Rick Chalaturnyk
14.1 Introduction 271
14.2 Observations 272
14.3 Summary 276
References 276
15 Case Study for the Application of CCUS to a Waste-to-Energy Italian Plant 279
Stefania Moioli, Giorgia De Guido, Laura A. Pellegrini, Elisabetta Fasola, Davide Alberti and Adriano Carrara
15.1 Introduction 280
15.2 Co 2 Capture 281
15.2.1 Methodology for Process Design 281
15.2.2 Selection of the Pilot Plant Characteristics 283
15.3 Co 2 Utilization 286
15.4 Utilities Consumption and Economic Evaluation 287
15.4.1 Estimate of Utilities Consumptions 287
15.4.2 Preliminary Economic Analysis 289
15.5 Conclusions 289
References 290
16 Key Results of Tomakomai CCS Demonstration Project 293
Yoshihiro Sawada, Jiro Tanaka, Daiji Tanase, Takashi Sasaki and Chiyoko Suzuki
16.1 Introduction 293
16.1.1 Current Efforts of the Japanese Government for CCS 294
16.1.2 Key Results of Tomakomai CCS Demonstration Project 296
16.2 Overview of the Tomakomai Project 297
16.3 Key Results of Tomakomai Project 298
16.3.1 Co 2 Capture 298
16.3.2 Co 2 Injection and Monitoring 300
16.4 Public Outreach 306
16.5 Experience of Major Earthquake 308
16.6 Research, Development, and Demonstration of CO 2 Ship Transportation 311
16.6.1 R&D to Establish Technology for Ship Transportation of Liquefied CO 2 at a Scale of 1 Million Tonnes per Year 312
16.6.2 Demonstration of CO 2 Ship Transportation by a Ship with 999 Gross Tonnage 313
16.7 Conclusion 315
Acknowledgment 315
References 315
17 Some Results of ERTF Carbon Capture Pilot Plant 317
Ahmed Aboudheir, Neil Rathva, Lin Li and Walid ElMoudir
17.1 Introduction 318
17.2 ERTF Pilot Plant Process Description and Configuration 319
17.3 Offline and Online Analysis Methods and Measurements 320
17.4 Test Campaigns 321
17.5 Model Validation Against Pilot Plant Data and Results (Run #107 Capacity Target) 323
17.6 Model Validation Against Pilot Plant Data and Results (Run #108 Energy Target) 327
17.7 Model Validation Against Pilot Plant Data and Results (Run #109 Energy Target) 331
17.8 Conclusions and Recommendations 334
Acknowledgment 335
18 Evaluation of CO 2 Storage Potential in the Deep Mannville Coals of Alberta: Vertical Well Injection Testing 337
Yun Yang, Christopher R. Clarkson and Michael S. Blinderman
18.1 Introduction 338
18.2 Methodology 339
18.2.1 Field Planning 339
18.2.2 Numerical Simulation 340
18.3 Results and Discussion 342
18.3.1 Pre-Pilot Investigation 342
18.3.2 Calibration of the Numerical Model Using Field Injection Data 344
18.4 Conclusion 345
Acknowledgments 346
References 346
19 Dynamic Miscibility of H 2 S/co 2 with Reservoir Oil in a Middle Eastern Triassic Reservoir 347
Liaqat Ali and Ahmad J. Sultan
19.1 Introduction 347
19.2 Description of Reservoir Simulations 348
19.2.1 Acid Gas Composition 350
19.3 Results and Discussion 350
19.3.1 Injection and Production Performance 350
19.3.2 Dynamic Miscibility 353
19.3.2.1 Results of Dynamic Miscibility for Lower Rate Case (Case 1) 356
19.3.2.2 Results of Dynamic Miscibility for Higher Rate Case (Case 2) 357
19.3.2.3 Comparison of Dynamic Miscibility in the Two Cases 359
19.4 Conclusions 360
References 361
20 Quantitative Evaluation of Dynamic Solubility of Acid Gases in Deep Brine Aquifers 363
Liaqat Ali, Ahmad J. Sultan, Russell E. Bentley and K. Patel
20.1 Introduction 364
20.2 Technical Approach and Analysis 367
20.3 Description of Reservoir Simulations 368
20.4 Results and Discussion 369
20.4.1 AGI Into Ellenburger Formation 369
20.4.1.1 Dynamic Solubility in Ellenburger Formation 369
20.4.1.2 Ellenburger Formation Case E-1 370
20.4.1.3 Ellenburger Formation Case E-2 372
20.4.1.4 Comparison of the Cases and the Effect of Salinity 373
20.4.2 H 2 S/co 2 -EOR in Triassic Reservoir 375
20.4.2.1 Dynamic Solubility in Kurra Chine Formation 376
20.4.2.2 Kurra Chine Formation Case KC-1 376
20.4.2.3 Kurra Chine Formation Case KC-2 380
20.4.2.4 Comparison of the Kurra Chine Formation Cases 382
20.4.3 AGI Into Cherry Canyon Formation 384
20.4.3.1 Dynamic Solubility in Cherry Canyon Formation 384
20.4.4 AGI Into Wilcox Formation 387
20.4.4.1 Dynamic Solubility in Wilcox Formation 387
20.4.5 AGI Into Glen Rose Formation 389
20.4.5.1 Dynamic Solubility in Glen Rose Formation 389
20.5 Summary and Conclusions 392
Acknowledgment 393
References 394
21 Highlights of the Northeast BC Carbon Capture and Storage Atlas 401
John Xie, Natalie L. Sweet and Allison J. Gibbs
21.1 Study Workflow and Deliverables 403
21.2 Project Outcomes 404
21.3 Acknowledgments 408
References 408
22 A Novel Method for Calculating Average Formation Pressure of Gas-Reservoir-Type Underground Natural Gas Storage 411
Yubao Gao, Weiyao Zhu, Hongyang Chu and Ming Yue
22.1 Introduction 412
22.2 Methodology 414
22.2.1 Physical Model 414
22.2.2 Mathematical Model 415
22.3 Numerical Validation 418
22.4 Field Application 420
22.4.1 Geological Background 420
22.4.2 Model Application 420
22.5 Conclusions 423
22.6 Acknowledgments 423
References 424
Appendix A-Dimensionless Variable 425
23 Simulation of Multi-Zone Coupling Flow with Phase Change in Fractured Low Permeability Condensate Gas Reservoir 427
Wengang Bu, Weiyao Zhu and Debin Kong
23.1 Introduction 427
23.2 Methodology 428
23.2.1 Physical Model 428
23.2.2 Governing Equations 429
23.2.2.1 Two-Phase Zone 429
23.2.2.2 Transition Zone 429
23.2.2.3 Single-Phase Gas Zone 430
23.2.3 TPG and SS 430
23.2.4 Constraint Equations 431
23.2.5 State Equations 431
23.2.6 Initial and Boundary Conditions 432
23.3 Results and Discussion 432
23.3.1 Model Validation 432
23.3.2 Impact of Condensate 433
23.3.3 Impact of Fractures 435
23.3.4 TPG Distribution 435
23.4 Conclusions 436
Acknowledgments 436
References 436
Index 439
1
Acid 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 H2S 90 mol% 80-85 mol% CO2 5 mol% 9-13 mol% H2O 5 mol% 6 mol% Water content after 4th stage 3.4 g/Sm3
214 lb/MMSCF 4.3-4.8 g/Sm3
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...
