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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.

Preface xiii

1 Enthalpies of Carbon Dioxide-Methane and Carbon Dioxide-Nitrogen Mixtures: Comparison with Thermodynamic Models 1
Erin L. Roberts and John J. Carroll

1.1 Introduction 1

1.2 Enthalpy 2

1.3 Literature Review 2

1.3.1 Carbon Dioxide-Methane 4

1.3.2 Carbon Dioxide-Nitrogen 4

1.4 Calculations 5

1.4.1 Benedict-Webb-Rubin 6

1.4.2 Lee-Kesler 12

1.4.3 Soave-Redlich-Kwong 17

1.4.4 Peng-Robinson 23

1.4.5 AQUAlibrium 28

1.5 Discussion 33

1.6 Conclusion 36

References 37

2 Enthalpies of Hydrogen Sulfide-Methane Mixture: Comparison with Thermodynamic Models 39
Erin L. Roberts and John J. Carroll

2.1 Introduction 39

2.2 Enthalpy 40

2.3 Literature Review 40

2.4 Calculations 41

2.4.1 Lee-Kesler 41

2.4.2 Benedict-Webb-Rubin 43

2.4.3 Soave-Redlich-Kwong 43

2.4.4 Redlich-Kwong 47

2.4.5 Peng-Robinson 47

2.4.6 AQUAlibrium 50

2.5 Discussion 50

2.6 Conclusion 52

References 54

3 Phase Behavior and Reaction Thermodynamics Involving Dense-Phase CO2 Impurities 55
J.A. Commodore, C.E. Deering and R.A. Marriott

3.1 Introduction 55

3.2 Experimental 57

3.3 Results and Discussion 58

3.3.1 Phase Behavior Studies of SO2 Dissolved in Dense CO2 Fluid 58

3.3.2 The Densimetric Properties of CS2 and CO2 Mixtures 60

References 61

4 Sulfur Recovery in High Density CO2 Fluid 63
S. Lee and R.A. Marriott

4.1 Introduction 64

4.2 Literature Review 64

4.3 Methodology 65

4.4 Results and Discussion 66

4.5 Conclusion and Future Directions 67

References 68

5 Carbon Capture Performance of Seven Novel Immidazolium and Pyridinium Based Ionic Liquids 71
Mohamed Zoubeik, Mohanned Mohamedali and Amr Henni

5.1 Introduction 71

5.2 Experimental Work 73

5.2.1 Materials 73

5.2.2 Density Measurement 73

5.2.3 Solubility Measurement 73

5.3 Modeling 76

5.3.1 Calculation of Henry’s Law Constants 76

5.3.2 Critical Properties Calculations 76

5.3.3 Peng Robinson EoS 76

5.4 Results and Discussion 77

5.4.1 Density 77

5.4.2 Critical Properties 77

5.4.3 CO2 Solubility 78

5.4.4 The Effect of Changing the Cation 81

5.4.5 The Effect of Changing the Anion 84

5.4.6 Henry’s Law Constant, Enthalpy and Entropy Calculations 85

5.4.7 Thermodynamic Modeling of CO2 Solubility 86

5.5 Conclusion 87

Acknowledgements 88

References 88

6 Vitrisol a 100% Selective Process for H2S Removal in the Presence of CO2 91
W.N. Wermink, N. Ramachandran, and G.F. Versteeg

6.1 Introduction 92

6.2 Case Definition 94

6.3 “Amine-Treated” Cases by PPS 95

6.3.1 Introduction to PPS 95

6.3.2 Process Description 96

6.3.3 PFD 97

6.3.4 Results 97

6.3.4.1 Case 1 97

6.3.4.2 Case 2 97

6.4 VitrisolƒòƒnProcess Extended with Regeneration of Active Component 99

6.4.1 Technology Description 99

6.4.2 Parameters Determining the Process Boundary Conditions 99

6.4.3 Absorption Section 101

6.4.4 Regeneration Section 102

6.4.5 Sulphur Recovery Section 104

6.4.6 CO2-Absorber 105

6.4.7 PFD 105

6.5 Results 105

6.6 Discussion 110

6.6.1 Comparison of Amine Treating Solutions to Vitrisolƒòƒn110

6.6.2 Enhanced H2S Removal of Barnett Shale Gas (case 2) 112viii Contents

6.7 Conclusions 113

6.8 Notation 115

References 115

Appendix 6-A: H&M Balance of Case 1 (British Columbia shale) of the Amine Process 117

Appendix 6-B H&M Balance of Case 2a (Barnett shale) of the Amine Process with Stripper Promoter 119

Appendix 6-C H&M Balance of Case 3 (Barnett shale) of the Amine Process (MEA) 121

Appendix 6-D: H&M Balance of Case 1 (British Columbia shale) of the Vitrisolƒnprocess 123

Appendix 6-E H&M Balance of Case 2 (Barnett shale) of the VitrisolƒnProcess 125

7 New Amine Based Solvents for Acid Gas Removal 127
Yohann Coulier, Elise El Ahmar, Jean-Yves Coxam, Elise Provost, Didier Dalmazzone, Patrice Paricaud, Christophe Coquelet and Karine Ballerat-Busserolles

7.1 Introduction 128

7.2 Chemicals and Materials 131

7.3 Liquid-Liquid Equilibria 131

7.3.1 LLE in {methylpiperidines – H2O} and {methylpiperidines – H2O – CO2} 131

7.3.2 Liquid-Liquid Equilibria of Ternary Systems {Amine – H2O – Glycol} 135

7.3.3 Liquid-Liquid Equilibria of the Quaternary Systems {CO2 – NMPD – TEG – H2O} 136

7.4 Densities and Heat Capacities of Ternary Systems {NMPD – H2O – Glycol} 137

7.4.1 Densities 137

7.4.2 Specific Heat Capacities 137

7.5 Vapor-Liquid Equilibria of Ternary Systems {NMPD – TEG – H2O – CO2} 139

7.6 Enthalpies of Solution 140

7.7 Discussion and Conclusion 143

Acknowledgments 143

References 144Contents ix

8 Improved Solvents for CO2 Capture by Molecular Simulation Methodology 147
William R. Smith

8.1 Introduction 147

8.2 Physical and Chemical Models 149

8.3 Molecular-Level Models and Algorithms for Thermodynamic Property Predictions 150

8.4 Molecular-Level Models and Methodology for MEA–H2O–CO2 153

8.4.1 Extensions to Other Alkanolamine Solvents and Their Mixtures 155

Acknowledgements 157

References 157

9 Strategies for Minimizing Hydrocarbon Contamination in Amine Acid Gas for Reinjection 161
Mike Sheilan, Ben Spooner and David Engel

9.1 Introduction 162

9.2 Amine Sweetening Process 162

9.3 Hydrocarbons in Amine 164

9.4 Effect of Hydrocarbons on the Acid Gas Reinjection System 166

9.5 Effect of Hydrocarbons on the Amine Plant 167

9.6 Minimizing Hydrocarbon Content in Amine Acid Gas 171

9.6.1 Option 1. Optimization of the Amine Plant Operation 171

9.6.2 Option 2. Amine Flash Tanks 176

9.6.3 Option 3. Rich Amine Liquid Coalescers 178

9.6.4 Option 4. Use of Skimming Devices 180

9.6.5 Option 5. Technological Solutions 182

References 183

10 Modeling of Transient Pressure Response for CO2 Flooding Process by Incorporating Convection and Diffusion Driven Mass Transfer 185
Jianli Li and Gang Zhao

10.1 Introduction 186

10.2 Model Development 187

10.2.1 Pressure Diffusion 187

10.2.2 Mass Transfer 188

10.2.3 Solutions 190x Contents

10.3 Results and Discussion 191

10.3.1 Flow Regimes 191

10.3.2 Effect of Mass Transfer 192

10.3.3 Sensitivity Analysis 195

10.3.3.1 CO2 Bank 195

10.3.3.2 Reservoir Outer Boundary 196

10.4 Conclusions 196

Acknowledgments 197

References 197

11 Well Modeling Aspects of CO2 Sequestration 199
Liaqat Ali and Russell E. Bentley

11.1 Introduction 199

11.2 Delivery Conditions 200

11.3 Reservoir and Completion Data 201

11.4 Inflow Performance Relationship (IPR) and Injectivity Index 201

11.5 Equation of State (EOS) 202

11.6 Vertical Flow Performance (VFP) Curves 205

11.7 Impact of the Well Deviation on CO2 Injection 208

11.8 Implication of Bottom Hole Temperature (BHT) on Reservoir 209

11.9 Impact of CO2 Phase Change 213

11.10 Injection Rates, Facility Design Constraints and Number of Wells Required 214

11.11 Wellhead Temperature Effect on VFP Curves 214

11.12 Effect of Impurities in CO2 on VFP Curves 216

11.13 Concluding Remarks 217

Conversion Factors 218

References 218

12 Effects of Acid Gas Reinjection on Enhanced Natural Gas Recovery and Carbon Dioxide Geological Storage: Investigation of the Right Bank of the Amu Darya River 221
Qi Li, Xiaying Li, Zhiyong Niu, Dongqin Kuang, Jianli Ma, Xuehao Liu, Yankun Sun and Xiaochun Li

12.1 Introduction 222

12.2 The Amu Darya Right Bank Gas Reservoirs in Turkmenistan 223Contents xi

12.3 Model Development 223

12.3.1 State equation 224

12.3.1.1 Introduction of Traditional PR State Equation 224

12.3.1.2 Modifications for the Vapor-Aqueous System 224

12.3.2 Salinity 225

12.3.3 Diffusion 226

12.3.3.1 Diffusion Coefficients 226

12.3.3.2 The Cross-Phase Diffusion Coefficients 226

12.4 Simulation Model 227

12.4.1 Model Parameters 227

12.4.2 Grid-Sensitive Research of the Model 227

12.4.3 The Development and Exploitation Mode 230

12.5 Results and Discussion 230

12.5.1 Reservoir Pressure 230

12.5.2 Gas Sequestration 232

12.5.3 Production 235

12.5.4 Recovery Ratio and Recovery Percentage 238

12.6 Conclusions 239

12.7 Acknowledgments 240

References 241

Index 245