Gas Injection into Geological Formations and Related Topics

This is the eighth volume in the series, Advances in Natural Gas Engineering, focusing on gas injection into geological formations and other related topics, very important areas of natural gas engineering. This volume includes information for both upstream and downstream operations, including chapters detailing the most cutting-edge techniques in acid gas injection, carbon capture, chemical and thermodynamic models, 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 being 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 an ongoing series of books meant to form the basis for the working library of any engineer working in natural gas today.

Preface xvii

1 Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur 1
Mitchell J. Stashick, Gabriel O. Sofekun and Robert A. Marriott

1.1 Introduction 2

1.2 Experimental 3

1.2.1 Materials 3

1.2.2 Rheometer 4

1.3 Results and Discussion 5

1.4 Conclusions 7

References 8

2 Experimental Determination of CO₂ Solubility in Brines At High Temperatures and High Pressures and Induced Corrosion of Materials in Geothermal Equipment 9
Marie Poulain, Jean-Charles Dupin, Hervé Martinez and Pierre Cézac

2.1 Introduction 9

2.2 Experimental Section 11

2.2.1 Chemicals 11

2.2.2 Test Solutions 11

2.2.3 Metals 11

2.2.4 CO₂ Solubility Measurements 12

2.2.5 Material Corrosion Study 13

2.3 Results and Discussion 15

2.3.1 CO₂ Solubility Measurements 15

2.3.2 Material Corrosion Study 16

2.4 Conclusion 19

2.5 Acknowledgments 19

References 19

3 Experimental Study of the Liquid Vapour Equilibrium of the System Water-CO₂-O₂-NO_x Under Pressure at 298 K 21
Esther Neyrolles, Georgio Bassil, François Contamine, Pierre Cézac and Philippe Arpentinier

3.1 Introduction 22

3.2 Literature Review 23

3.2.1 Carbon Dioxide and Water System 23

3.2.2 Nitrogen Oxides and Water System 24

3.2.3 Nitric Oxide Henry Constant at 298 K 25

3.3 Experimental Section 26

3.3.1 Chemicals 26

3.3.2 Apparatus 26

3.3.3 Operating Procedure 27

3.3.4 Experimental Analysis 29

3.3.4.1 Aqueous Analysis 29

3.3.4.2 Gas Phase Analysis 30

3.3.5 Estimation of the Concentrations of All the Species in the Aqueous Phase 31

3.3.6 Uncertainties 32

3.4 Results and Discussion 33

3.4.1 Solubility of Carbon Dioxide 33

3.4.2 Nitrogen Oxides Repartition in the Aqueous Phase 35

3.4.3 Nitric Oxide Henry Constant at 298 K 37

3.5 Conclusion 38

3.6 Acknowledgments 38

References 38

4 The Use of IR Spectroscopy to Follow the Absorption of CO₂ in Amine Media – Evaluation of the Speciation with Time 41
E. Brugere, J-M. Andanson and K. Ballerat-Busserolles

4.1 Introduction 41

4.2 Materials and Methods 44

4.2.1 Chemicals 44

4.2.2 Sample Preparation 44

4.3 Experimental Device 44

4.4 Results and Discussion 46

4.4.1 Kinetic of Absorption 46

4.4.2 Calibration of Speciation 46

4.4.2.1 Sample Preparation 46

4.4.2.2 Spectra and Results 48

4.4.2.3 Physisorption 49

4.4.2.4 Full Curve Speciation 51

4.5 Conclusion 52

4.6 Acknowledgments 53

References 53

5 Solubility of Methane, Nitrogen, Hydrogen Sulfide and Carbon Dioxide in Mixtures of Dimethyl Ethers of Polyethylene Glycol 55
Alan E. Mather and Kurt A. G. Schmidt

5.1 Introduction 56

5.2 Experimental 56

5.3 Equation of State Development 57

5.4 EoS Model Results 62

5.5 Krichevsky-Ilinskaya Equation 67

5.6 Conclusions 70

5.7 Nomenclature 71

References 72

6 Water Content of Hydrogen Sulfide – A Review 77
Eugene Grynia and Bogdan Ambrożek

6.1 Introduction 77

6.2 Literature Review 78

6.2.1 Wright and Maass (1932) 79

6.2.2 Selleck et al. (1951, 1952) 82

6.2.3 Kozintseva (1964) 84

6.2.4 Clarke and Glew (1971) 88

6.2.5 Lee and Mather (1977) 89

6.2.6 Gillespie and Wilson (1982) 92

6.2.7 Carroll and Mather (1989) 94

6.2.8 Suleimenov and Krupp (1994) 96

6.2.9 Chapoy et al. (2005) 97

6.2.10 Marriott et al. (2012) 100

6.3 Discussion of the Results 102

6.4 Conclusions 108

References 112

7 Acid Gas Injection at SemCAMS Kaybob Amalgamated (KA) Gas Plant Operational Design Considerations 115
Rinat Yarmukhametov, James R. Maddocks and Jason Lui

7.1 Project Drivers 116

7.2 Process Design Basis 117

7.2.1 Acid Gas Inlet Design Conditions 117

7.2.2 Acid Gas Compositions 117

7.2.3 Acid Gas Compressor Discharge 118

7.2.3.1 Acid Gas Conditions 118

7.2.3.2 Acid Gas Composition 118

7.3 Acid Gas Compression Description 120

7.4 AGI System Capacity Control 120

7.5 Project Execution 123

7.6 Risk Assessment Strategy 125

7.7 Utilities & Tie-Ins 126

7.8 Relief System Design 127

7.8.1 KA Gas Plant Flare System 127

7.8.2 AGI System Flare System 128

7.8.3 Evaluation of Existing Plant Blowdowns Concurrent with the AGI Compressors Blowdown 128

7.8.4 Inherently Safer Design (ISD) Strategies in Pressure Relief System Design for AGI Systems 129

7.8.5 MDMT Evaluation 131

7.8.6 Drain Management 132

7.9 Discussion 133

7.10 Start-Up 133

7.11 Conclusions 135

8 Reciprocating Compressors in Acid Gas Service 137
Dan Hannon

8.1 Introduction 138

8.2 Reactivity 138

8.3 Safety 138

8.4 Design 139

8.5 Materials 140

8.6 Condensate/Dewpoint 141

8.7 Compressor Selection 142

8.8 Conclusion 144

9 Case Study: Wellbore Thermodynamic Analysis of Erhao Acid Gas Injection Project 145
Zhu Zhu and Shouxi Wang

9.1 Introduction 145

9.2 Erhao Station Process and Injection Basic Data 147

9.3 Acid Gas Injection Well and Reservoir 148

9.3.1 Injection Well 148

9.3.1.1 Basic Data 149

9.3.1.2 Characteristics 149

9.3.2 Injection Reservoir 150

9.4 Thermodynamic Analysis and Injection Pressure 151

9.4.1 Comprehensive Model 151

9.4.2 Initial Acid Gas 152

9.4.3 Compressed and Dehydrated Acid Gas 155

9.4.4 Comparison of Different Acid Gas Composition 158

9.4.5 Comparison of Different Wellhead Temperature 158

9.5 Conclusion 159

References 159

10 Selecting CO₂ Sinks CCUS Deployment in South Mid-West Kansas 161
Eugene Holubnyak, Martin Dubois and Jennifer Hollenbach

10.1 Introduction 161

10.2 Process for Determining Potential Phase II Sites 165

10.2.1 Geologic Setting 165

10.3 Oil Production History and CO₂ Enhanced Oil Recovery Potential in the Region 170

10.4 Estimating CO₂ Storage Volume—Building the Static Model 171

10.4.1 Workflow for Building 3-D Static Model 171

10.4.2 Well Data 172

10.4.3 Petrophysics 173

10.4.4 Three-Dimensional Static Model 174

10.5 Estimating CO₂ Storage Volume—Running the Dynamic Model 175

10.5.1 Initial Reservoir Conditions and Simulation Constraints 176

10.5.2 Simulation Results 177

10.6 Summary/Discussion 179

References 180

11 Salt Precipitation at an Active CO₂ Injection Site 183
Stephen Talman, Alireza Rangriz Shokri, Rick Chalaturnyk and Erik Nickel

11.1 Introduction 184

11.2 Laboratory and Field Data 186

11.2.1 Data Sources 186

11.2.2 Chemical Composition of Formation Water 186

11.2.3 X-Ray Diffraction Analysis of Recovered Salt Samples 187

11.2.4 Downhole Video Analysis and Image Sizing 188

11.2.4.1 Material Fixed to the Wellbore 188

11.2.4.2 Lowest Reaches of the Well 190

11.2.4.3 Dislodged Materials 191

11.3 Implication and Interpretation 193

11.4 Conclusions and Remarks 196

11.5 Acknowledgments 198

References 198

12 The Development Features and Cost Analysis of CCUS Industry in China 201
Hao Mingqiang, Hu Yongle, Wang Shiyu and Song Lina

12.1 Introduction 202

12.2 Characteristics of CCUS Project 202

12.2.1 Distribution and Characteristics of CCUS Project 202

12.2.2 Types and Scales of CCUS Emission Sources 202

12.2.3 Emission Scales and Composition of CO₂ Emission Enterprises in China 204

12.2.4 Distributions of CO₂ Sources in China 204

12.2.5 Characteristic Comparison Between Projects in China and Abroad 205

12.3 Industry Patterns & Driving Modes 209

12.3.1 CCUS Industry Patterns at Home and Aboard 209

12.3.2 Driving Modes of CCUS Industry 210

12.4 Composition & Factors of CO₂ Source Cost 213

12.5 Conclusions 215

References 216

13 CO₂ Movement Monitoring and Verification in a Fractured Mississippian Carbonate Reservoir during EOR at Wellington Field in South Kansas 217
Yevhen Holubnyak, Eric Mackay, Oleg Ishkov and Willard Watney

13.1 Introduction 218

13.2 Wellington Field Faults and Fractures 219

13.3 EOR Field Operations and Production/Injection History 220

13.4 Geochemical Monitoring Survey Setup 221

13.5 Geochemical Monitoring Survey Observations 222

13.6 Conclusions 225

13.7 Acknowledgements 225

13.8 Disclaimer 225

References 226

14 Simulation Study On Carbon Dioxide Enhanced Oil Recovery 227
Maojie Chai and Zhangxin Chen

14.1 Introduction 227

14.2 Phase Behavior Study 229

14.3 Simulation Study 230

14.3.1 Fluid Sample Properties 230

14.3.2 Phase Behavior Simulation 230

14.3.3 Lab Scale Core Flooding Simulation 235

14.3.4 Sensitivity Analysis of Uncertain Parameters 240

14.3.5 Updated Relative Permeability Through History Match 241

14.4 Conclusions 243

References 243

15 Blowout Recovery for Acid Gas Injection Wells 245
Ray Mireault

15.1 Introduction 246

15.2 Methodology 247

15.3 Wellbore Behaviour 247

15.4 Acid Gas Flammability and Toxicity 249

15.5 Escape Plume Behaviour 250

15.6 Blowout Recovery Operations 252

15.6.1 Initial Reconnaissance 253

15.6.2 Heavy Equipment for AG Recovery Operations 253

15.7 Recommendations for Further Investigation 254

15.7.1 Acid Gas Escape Cloud Modelling 254

15.7.2 Personnel Training 255

15.7.3 Development of Recovery Equipment and Procedures 256

15.8 Acknowledgments 256

References 257

16 The Comprehensive Considerations of Leak Detection Solutions for Acid Gas Injection Pipelines 259
Shouxi Wang, John Carroll, Fan Ye, Lirong Yao, Jianqiang Teng and Haifeng Qiu

16.1 Introduction 260

16.2 Flowing and Layout Features, Leak Detection Strategies of the Acid Gas Pipelines 260

16.3 The Behavior of the Acid Gas Flows with Leakages 261

16.3.1 Leak Experiments on Liquid Pipeline 261

16.3.2 Leak Experiments on Gas Pipeline 262

16.3.3 Summary of Leak Responses 265

16.4 Specification, Measurement Requirements and Features of the Available Pipeline Leak Detection Methods 267

16.4.1 Mass Balance (MB) 267

16.4.2 Pressure Point Analysis (PPA) 268

16.4.3 Real-Time Model (RTM) 269

16.4.4 Data Requirements of the CPM Leak Detection Methods 270

16.4.5 Matrix Features of the Pipeline LDS 271

16.5 Evaluation of the Erhaolian AGI LDS System 271

16.5.1 Erhaolian AGI System 271

16.5.2 Measurement Responses to Different Leak Size and Location 271

16.5.3 The Performances of CPM Leak Detection Methods 278

16.6 Conclusion 281

16.7 Acknowledgments 281

References 282

17 Injection of Non-Condensable Gas in SAGD Using Modified Well Configurations - A Simulation Study 283
Yushuo Zhang and Brij Maini

17.1 Introduction 284

17.1.1 Background 284

17.1.2 Project Objectives 284

17.2 Relevant Field History 285

17.2.1 Depositional History 285

17.3 Reservoir Characterization 285

17.3.1 Geology Overview 285

17.3.1.1 Core Analysis 285

17.3.1.2 Log Analysis 285

17.3.1.3 Shale Volume Calculations 286

17.3.1.4 Porosity Calculations 286

17.3.1.5 Water and Oil Saturation 286

17.3.2 Permeability Data 287

17.3.3 PVT Data 287

17.3.4 Reservoir Values 288

17.4 Analytical Production Forecast 288

17.4.1 Butler Model 288

17.4.2 Reservoir Performance with NCG Co-Injection 291

17.5 Reservoir Simulation 291

17.5.1 Geological Model 291

17.5.2 Reservoir Property 292

17.5.3 Well Location 292

17.5.4 Initial Reservoir Simulation Inputs 293

17.5.5 Relative Permeability Data 293

17.5.6 Well Operational Parameters 294

17.5.7 History Match 295

17.5.7.1 Flowing Boundary Condition 295

17.5.7.2 Final History Match Results 295

17.5.8 SAGD Production Forecasts 297

17.5.8.1 Base Case HZ Well Production with Steam Only (Flowing Boundary) 298

17.5.8.2 Forecast Results: Production Rate 299

17.5.8.3 Forecast Results: Steam-to-Oil Ratio 299

17.5.9 Modified Well Simulation Forecast 299

17.5.9.1 Modified Well Configuration with Non-Flowing Boundary 299

17.5.9.2 Perforating Below Top Water Zone 299

17.5.9.3 Forecast Results: Production Rate 302

17.5.9.4 Forecast Results: Steam-to-Oil Ratio 302

17.5.9.5 Steam Chamber Development without NCG 303

17.5.9.6 Steam Chamber Development with NCG 304

17.5.9.7 Simulation Sensitivity Analysis in Non-Flowing Boundary 304

17.5.9.8 Summary of Simulation Results 306

17.6 Conclusion 306

References 308

18 The Study on the Gas Override Phenomenon in Condensate Gas Reservoir 311
Kun Huang, Weiyao Zhu, Qitao Zhang, Jing Xia and Kai Luo

18.1 Introduction 311

18.2 Experimental 312

18.2.1 Pressure-Volume-Temperature Tests 312

18.2.2 Pressure-Volume-Temperature Tests Design 313

18.3 Results and Discussion 313

18.3.1 Phase Behavior During the Injection Process 313

18.3.2 The Effect of Mass Transfer on the Phase Behavior 315

18.3.3 Composition of the Mixture in the Cylinder 317

18.4 Conclusions 319

References 319

19 Study on Characteristics of Water-Gas Flow in Tight Gas Reservoir with High Water Saturation 321
Qitao Zhang, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan

19.1 Introduction 322

19.2 Experiments 322

19.2.1 Materials 322

19.2.2 Experimental Procedure 323

19.2.3 Experimental Results and Analysis 324

19.3 Numerical Simulation for Tight Gas Reservoir with Low Gas Saturation 327

19.3.1 Model Description 327

19.3.2 Model Validation 328

19.3.3 Effect of Threshold Pressure Gradient 329

19.4 Conclusions 331

References 331

20 The Description and Modeling of Gas Override in Condensate Gas Reservoir 333
Weiyao Zhu, Kun Huang, Yan Sun and Qitao Zhang

20.1 Introduction 333

20.2 Mathematical Formulation 335

20.2.1 Numerical Scheme 337

20.3 Results and Discussion 337

20.3.1 The Development and Assessment of Gas Override 337

20.3.2 Sensitivity Analysis 339

20.3.2.1 The Influence of Density Difference on Gas Override 340

20.4 Conclusions 341

References 342

21 Research on the Movable Water in the Pores of Tight Sandstone Gas Reservoirs 343
Guodong Zou, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan

21.1 Introduction 343

21.2 Experimental 344

21.2.1 Experimental Equipment 344

21.2.2 Experimental Procedure 345

21.3 Results and Discussion 346

21.3.1 Change of the Saturated Water 346

21.3.2 Test of the Movable Water 348

21.4 Conclusion 349

References 350

22 Probabilistic Petroleum Portfolio Options Evaluation Model (POEM) 351
Darryl Burns

22.1 Project Economic Evaluation Tool (PEET) 351

22.2 Portfolio Options Evaluation Tool (POET) 352

22.3 Program Calculation Procedures 352

22.3.1 General Cash Flow Calculation and Profitability Indicators 352

22.3.1.1 General Cash Flow Calculation 352

22.4 General Calculation Steps 353

Index 361

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.

John J. Carroll, PhD, PEng is the Director at Geostorage Process Engineering for Gas Liquids Engineering, Ltd. in Calgary, Canada. His first 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.

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.

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 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.