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.

Table of Contents:
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-NOx 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