Gas Injection into Geological Formations and Related Topics

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.

• Preface xvii1 Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur 1Mitchell J. Stashick, Gabriel O. Sofekun and Robert A. Marriott1.1 Introduction 21.2 Experimental 31.2.1 Materials 31.2.2 Rheometer 41.3 Results and Discussion 51.4 Conclusions 7References 82 Experimental Determination of CO2 Solubility in Brines At High Temperatures and High Pressures and Induced Corrosion of Materials in Geothermal Equipment 9Marie Poulain, Jean-Charles Dupin, Hervé Martinez and Pierre Cézac2.1 Introduction 92.2 Experimental Section 112.2.1 Chemicals 112.2.2 Test Solutions 112.2.3 Metals 112.2.4 CO2 Solubility Measurements 122.2.5 Material Corrosion Study 132.3 Results and Discussion 152.3.1 CO2 Solubility Measurements 152.3.2 Material Corrosion Study 162.4 Conclusion 192.5 Acknowledgments 19References 193 Experimental Study of the Liquid Vapour Equilibrium of the System Water-CO2-O2-NOx Under Pressure at 298 K 21Esther Neyrolles, Georgio Bassil, François Contamine, Pierre Cézac and Philippe Arpentinier3.1 Introduction 223.2 Literature Review 233.2.1 Carbon Dioxide and Water System 233.2.2 Nitrogen Oxides and Water System 243.2.3 Nitric Oxide Henry Constant at 298 K 253.3 Experimental Section 263.3.1 Chemicals 263.3.2 Apparatus 263.3.3 Operating Procedure 273.3.4 Experimental Analysis 293.3.4.1 Aqueous Analysis 293.3.4.2 Gas Phase Analysis 303.3.5 Estimation of the Concentrations of All the Species in the Aqueous Phase 313.3.6 Uncertainties 323.4 Results and Discussion 333.4.1 Solubility of Carbon Dioxide 333.4.2 Nitrogen Oxides Repartition in the Aqueous Phase 353.4.3 Nitric Oxide Henry Constant at 298 K 373.5 Conclusion 383.6 Acknowledgments 38References 384 The Use of IR Spectroscopy to Follow the Absorption of CO2 in Amine Media – Evaluation of the Speciation with Time 41E. Brugere, J-M. Andanson and K. Ballerat-Busserolles4.1 Introduction 414.2 Materials and Methods 444.2.1 Chemicals 444.2.2 Sample Preparation 444.3 Experimental Device 444.4 Results and Discussion 464.4.1 Kinetic of Absorption 464.4.2 Calibration of Speciation 464.4.2.1 Sample Preparation 464.4.2.2 Spectra and Results 484.4.2.3 Physisorption 494.4.2.4 Full Curve Speciation 514.5 Conclusion 524.6 Acknowledgments 53References 535 Solubility of Methane, Nitrogen, Hydrogen Sulfide and Carbon Dioxide in Mixtures of Dimethyl Ethers of Polyethylene Glycol 55Alan E. Mather and Kurt A. G. Schmidt5.1 Introduction 565.2 Experimental 565.3 Equation of State Development 575.4 EoS Model Results 625.5 Krichevsky-Ilinskaya Equation 675.6 Conclusions 705.7 Nomenclature 71References 726 Water Content of Hydrogen Sulfide – A Review 77Eugene Grynia and Bogdan Ambrożek6.1 Introduction 776.2 Literature Review 786.2.1 Wright and Maass (1932) 796.2.2 Selleck et al. (1951, 1952) 826.2.3 Kozintseva (1964) 846.2.4 Clarke and Glew (1971) 886.2.5 Lee and Mather (1977) 896.2.6 Gillespie and Wilson (1982) 926.2.7 Carroll and Mather (1989) 946.2.8 Suleimenov and Krupp (1994) 966.2.9 Chapoy et al. (2005) 976.2.10 Marriott et al. (2012) 1006.3 Discussion of the Results 1026.4 Conclusions 108References 1127 Acid Gas Injection at SemCAMS Kaybob Amalgamated (KA) Gas Plant Operational Design Considerations 115Rinat Yarmukhametov, James R. Maddocks and Jason Lui7.1 Project Drivers 1167.2 Process Design Basis 1177.2.1 Acid Gas Inlet Design Conditions 1177.2.2 Acid Gas Compositions 1177.2.3 Acid Gas Compressor Discharge 1187.2.3.1 Acid Gas Conditions 1187.2.3.2 Acid Gas Composition 1187.3 Acid Gas Compression Description 1207.4 AGI System Capacity Control 1207.5 Project Execution 1237.6 Risk Assessment Strategy 1257.7 Utilities & Tie-Ins 1267.8 Relief System Design 1277.8.1 KA Gas Plant Flare System 1277.8.2 AGI System Flare System 1287.8.3 Evaluation of Existing Plant Blowdowns Concurrent with the AGI Compressors Blowdown 1287.8.4 Inherently Safer Design (ISD) Strategies in Pressure Relief System Design for AGI Systems 1297.8.5 MDMT Evaluation 1317.8.6 Drain Management 1327.9 Discussion 1337.10 Start-Up 1337.11 Conclusions 1358 Reciprocating Compressors in Acid Gas Service 137Dan Hannon8.1 Introduction 1388.2 Reactivity 1388.3 Safety 1388.4 Design 1398.5 Materials 1408.6 Condensate/Dewpoint 1418.7 Compressor Selection 1428.8 Conclusion 1449 Case Study: Wellbore Thermodynamic Analysis of Erhao Acid Gas Injection Project 145Zhu Zhu and Shouxi Wang9.1 Introduction 1459.2 Erhao Station Process and Injection Basic Data 1479.3 Acid Gas Injection Well and Reservoir 1489.3.1 Injection Well 1489.3.1.1 Basic Data 1499.3.1.2 Characteristics 1499.3.2 Injection Reservoir 1509.4 Thermodynamic Analysis and Injection Pressure 1519.4.1 Comprehensive Model 1519.4.2 Initial Acid Gas 1529.4.3 Compressed and Dehydrated Acid Gas 1559.4.4 Comparison of Different Acid Gas Composition 1589.4.5 Comparison of Different Wellhead Temperature 1589.5 Conclusion 159References 15910 Selecting CO2 Sinks CCUS Deployment in South Mid-West Kansas 161Eugene Holubnyak, Martin Dubois and Jennifer Hollenbach10.1 Introduction 16110.2 Process for Determining Potential Phase II Sites 16510.2.1 Geologic Setting 16510.3 Oil Production History and CO2 Enhanced Oil Recovery Potential in the Region 17010.4 Estimating CO2 Storage Volume—Building the Static Model 17110.4.1 Workflow for Building 3-D Static Model 17110.4.2 Well Data 17210.4.3 Petrophysics 17310.4.4 Three-Dimensional Static Model 17410.5 Estimating CO2 Storage Volume—Running the Dynamic Model 17510.5.1 Initial Reservoir Conditions and Simulation Constraints 17610.5.2 Simulation Results 17710.6 Summary/Discussion 179References 18011 Salt Precipitation at an Active CO2 Injection Site 183Stephen Talman, Alireza Rangriz Shokri, Rick Chalaturnyk and Erik Nickel11.1 Introduction 18411.2 Laboratory and Field Data 18611.2.1 Data Sources 18611.2.2 Chemical Composition of Formation Water 18611.2.3 X-Ray Diffraction Analysis of Recovered Salt Samples 18711.2.4 Downhole Video Analysis and Image Sizing 18811.2.4.1 Material Fixed to the Wellbore 18811.2.4.2 Lowest Reaches of the Well 19011.2.4.3 Dislodged Materials 19111.3 Implication and Interpretation 19311.4 Conclusions and Remarks 19611.5 Acknowledgments 198References 19812 The Development Features and Cost Analysis of CCUS Industry in China 201Hao Mingqiang, Hu Yongle, Wang Shiyu and Song Lina12.1 Introduction 20212.2 Characteristics of CCUS Project 20212.2.1 Distribution and Characteristics of CCUS Project 20212.2.2 Types and Scales of CCUS Emission Sources 20212.2.3 Emission Scales and Composition of CO2 Emission Enterprises in China 20412.2.4 Distributions of CO2 Sources in China 20412.2.5 Characteristic Comparison Between Projects in China and Abroad 20512.3 Industry Patterns & Driving Modes 20912.3.1 CCUS Industry Patterns at Home and Aboard 20912.3.2 Driving Modes of CCUS Industry 21012.4 Composition & Factors of CO2 Source Cost 21312.5 Conclusions 215References 21613 CO2 Movement Monitoring and Verification in a Fractured Mississippian Carbonate Reservoir during EOR at Wellington Field in South Kansas 217Yevhen Holubnyak, Eric Mackay, Oleg Ishkov and Willard Watney13.1 Introduction 21813.2 Wellington Field Faults and Fractures 21913.3 EOR Field Operations and Production/Injection History 22013.4 Geochemical Monitoring Survey Setup 22113.5 Geochemical Monitoring Survey Observations 22213.6 Conclusions 22513.7 Acknowledgements 22513.8 Disclaimer 225References 22614 Simulation Study On Carbon Dioxide Enhanced Oil Recovery 227Maojie Chai and Zhangxin Chen14.1 Introduction 22714.2 Phase Behavior Study 22914.3 Simulation Study 23014.3.1 Fluid Sample Properties 23014.3.2 Phase Behavior Simulation 23014.3.3 Lab Scale Core Flooding Simulation 23514.3.4 Sensitivity Analysis of Uncertain Parameters 24014.3.5 Updated Relative Permeability Through History Match 24114.4 Conclusions 243References 24315 Blowout Recovery for Acid Gas Injection Wells 245Ray Mireault15.1 Introduction 24615.2 Methodology 24715.3 Wellbore Behaviour 24715.4 Acid Gas Flammability and Toxicity 24915.5 Escape Plume Behaviour 25015.6 Blowout Recovery Operations 25215.6.1 Initial Reconnaissance 25315.6.2 Heavy Equipment for AG Recovery Operations 25315.7 Recommendations for Further Investigation 25415.7.1 Acid Gas Escape Cloud Modelling 25415.7.2 Personnel Training 25515.7.3 Development of Recovery Equipment and Procedures 25615.8 Acknowledgments 256References 25716 The Comprehensive Considerations of Leak Detection Solutions for Acid Gas Injection Pipelines 259Shouxi Wang, John Carroll, Fan Ye, Lirong Yao, Jianqiang Teng and Haifeng Qiu16.1 Introduction 26016.2 Flowing and Layout Features, Leak Detection Strategies of the Acid Gas Pipelines 26016.3 The Behavior of the Acid Gas Flows with Leakages 26116.3.1 Leak Experiments on Liquid Pipeline 26116.3.2 Leak Experiments on Gas Pipeline 26216.3.3 Summary of Leak Responses 26516.4 Specification, Measurement Requirements and Features of the Available Pipeline Leak Detection Methods 26716.4.1 Mass Balance (MB) 26716.4.2 Pressure Point Analysis (PPA) 26816.4.3 Real-Time Model (RTM) 26916.4.4 Data Requirements of the CPM Leak Detection Methods 27016.4.5 Matrix Features of the Pipeline LDS 27116.5 Evaluation of the Erhaolian AGI LDS System 27116.5.1 Erhaolian AGI System 27116.5.2 Measurement Responses to Different Leak Size and Location 27116.5.3 The Performances of CPM Leak Detection Methods 27816.6 Conclusion 28116.7 Acknowledgments 281References 28217 Injection of Non-Condensable Gas in SAGD Using Modified Well Configurations - A Simulation Study 283Yushuo Zhang and Brij Maini17.1 Introduction 28417.1.1 Background 28417.1.2 Project Objectives 28417.2 Relevant Field History 28517.2.1 Depositional History 28517.3 Reservoir Characterization 28517.3.1 Geology Overview 28517.3.1.1 Core Analysis 28517.3.1.2 Log Analysis 28517.3.1.3 Shale Volume Calculations 28617.3.1.4 Porosity Calculations 28617.3.1.5 Water and Oil Saturation 28617.3.2 Permeability Data 28717.3.3 PVT Data 28717.3.4 Reservoir Values 28817.4 Analytical Production Forecast 28817.4.1 Butler Model 28817.4.2 Reservoir Performance with NCG Co-Injection 29117.5 Reservoir Simulation 29117.5.1 Geological Model 29117.5.2 Reservoir Property 29217.5.3 Well Location 29217.5.4 Initial Reservoir Simulation Inputs 29317.5.5 Relative Permeability Data 29317.5.6 Well Operational Parameters 29417.5.7 History Match 29517.5.7.1 Flowing Boundary Condition 29517.5.7.2 Final History Match Results 29517.5.8 SAGD Production Forecasts 29717.5.8.1 Base Case HZ Well Production with Steam Only (Flowing Boundary) 29817.5.8.2 Forecast Results: Production Rate 29917.5.8.3 Forecast Results: Steam-to-Oil Ratio 29917.5.9 Modified Well Simulation Forecast 29917.5.9.1 Modified Well Configuration with Non-Flowing Boundary 29917.5.9.2 Perforating Below Top Water Zone 29917.5.9.3 Forecast Results: Production Rate 30217.5.9.4 Forecast Results: Steam-to-Oil Ratio 30217.5.9.5 Steam Chamber Development without NCG 30317.5.9.6 Steam Chamber Development with NCG 30417.5.9.7 Simulation Sensitivity Analysis in Non-Flowing Boundary 30417.5.9.8 Summary of Simulation Results 30617.6 Conclusion 306References 30818 The Study on the Gas Override Phenomenon in Condensate Gas Reservoir 311Kun Huang, Weiyao Zhu, Qitao Zhang, Jing Xia and Kai Luo18.1 Introduction 31118.2 Experimental 31218.2.1 Pressure-Volume-Temperature Tests 31218.2.2 Pressure-Volume-Temperature Tests Design 31318.3 Results and Discussion 31318.3.1 Phase Behavior During the Injection Process 31318.3.2 The Effect of Mass Transfer on the Phase Behavior 31518.3.3 Composition of the Mixture in the Cylinder 31718.4 Conclusions 319References 31919 Study on Characteristics of Water-Gas Flow in Tight Gas Reservoir with High Water Saturation 321Qitao Zhang, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan19.1 Introduction 32219.2 Experiments 32219.2.1 Materials 32219.2.2 Experimental Procedure 32319.2.3 Experimental Results and Analysis 32419.3 Numerical Simulation for Tight Gas Reservoir with Low Gas Saturation 32719.3.1 Model Description 32719.3.2 Model Validation 32819.3.3 Effect of Threshold Pressure Gradient 32919.4 Conclusions 331References 33120 The Description and Modeling of Gas Override in Condensate Gas Reservoir 333Weiyao Zhu, Kun Huang, Yan Sun and Qitao Zhang20.1 Introduction 33320.2 Mathematical Formulation 33520.2.1 Numerical Scheme 33720.3 Results and Discussion 33720.3.1 The Development and Assessment of Gas Override 33720.3.2 Sensitivity Analysis 33920.3.2.1 The Influence of Density Difference on Gas Override 34020.4 Conclusions 341References 34221 Research on the Movable Water in the Pores of Tight Sandstone Gas Reservoirs 343Guodong Zou, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan21.1 Introduction 34321.2 Experimental 34421.2.1 Experimental Equipment 34421.2.2 Experimental Procedure 34521.3 Results and Discussion 34621.3.1 Change of the Saturated Water 34621.3.2 Test of the Movable Water 34821.4 Conclusion 349References 35022 Probabilistic Petroleum Portfolio Options Evaluation Model (POEM) 351Darryl Burns22.1 Project Economic Evaluation Tool (PEET) 35122.2 Portfolio Options Evaluation Tool (POET) 35222.3 Program Calculation Procedures 35222.3.1 General Cash Flow Calculation and Profitability Indicators 35222.3.1.1 General Cash Flow Calculation 35222.4 General Calculation Steps 353Index 361