Carbon Dioxide Capture and Acid Gas Injection

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. 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 xiii1 Enthalpies of Carbon Dioxide-Methane and Carbon Dioxide-Nitrogen Mixtures: Comparison with Thermodynamic Models 1Erin L. Roberts and John J. Carroll1.1 Introduction 11.2 Enthalpy 21.3 Literature Review 21.3.1 Carbon Dioxide-Methane 41.3.2 Carbon Dioxide-Nitrogen 41.4 Calculations 51.4.1 Benedict-Webb-Rubin 61.4.2 Lee-Kesler 121.4.3 Soave-Redlich-Kwong 171.4.4 Peng-Robinson 231.4.5 AQUAlibrium 281.5 Discussion 331.6 Conclusion 36References 372 Enthalpies of Hydrogen Sulfide-Methane Mixture: Comparison with Thermodynamic Models 39Erin L. Roberts and John J. Carroll2.1 Introduction 392.2 Enthalpy 402.3 Literature Review 402.4 Calculations 412.4.1 Lee-Kesler 412.4.2 Benedict-Webb-Rubin 432.4.3 Soave-Redlich-Kwong 432.4.4 Redlich-Kwong 472.4.5 Peng-Robinson 472.4.6 AQUAlibrium 502.5 Discussion 502.6 Conclusion 52References 543 Phase Behavior and Reaction Thermodynamics Involving Dense-Phase CO2 Impurities 55J.A. Commodore, C.E. Deering and R.A. Marriott3.1 Introduction 553.2 Experimental 573.3 Results and Discussion 583.3.1 Phase Behavior Studies of SO2 Dissolved in Dense CO2 Fluid 583.3.2 The Densimetric Properties of CS2 and CO2 Mixtures 60References 614 Sulfur Recovery in High Density CO2 Fluid 63S. Lee and R.A. Marriott4.1 Introduction 644.2 Literature Review 644.3 Methodology 654.4 Results and Discussion 664.5 Conclusion and Future Directions 67References 685 Carbon Capture Performance of Seven Novel Immidazolium and Pyridinium Based Ionic Liquids 71Mohamed Zoubeik, Mohanned Mohamedali and Amr Henni5.1 Introduction 715.2 Experimental Work 735.2.1 Materials 735.2.2 Density Measurement 735.2.3 Solubility Measurement 735.3 Modeling 765.3.1 Calculation of Henry’s Law Constants 765.3.2 Critical Properties Calculations 765.3.3 Peng Robinson EoS 765.4 Results and Discussion 775.4.1 Density 775.4.2 Critical Properties 775.4.3 CO2 Solubility 785.4.4 The Effect of Changing the Cation 815.4.5 The Effect of Changing the Anion 845.4.6 Henry’s Law Constant, Enthalpy and Entropy Calculations 855.4.7 Thermodynamic Modeling of CO2 Solubility 865.5 Conclusion 87Acknowledgements 88References 886 Vitrisol a 100% Selective Process for H2S Removal in the Presence of CO2 91W.N. Wermink, N. Ramachandran, and G.F. Versteeg6.1 Introduction 926.2 Case Definition 946.3 “Amine-Treated” Cases by PPS 956.3.1 Introduction to PPS 956.3.2 Process Description 966.3.3 PFD 976.3.4 Results 976.3.4.1 Case 1 976.3.4.2 Case 2 976.4 VitrisolƒòƒnProcess Extended with Regeneration of Active Component 996.4.1 Technology Description 996.4.2 Parameters Determining the Process Boundary Conditions 996.4.3 Absorption Section 1016.4.4 Regeneration Section 1026.4.5 Sulphur Recovery Section 1046.4.6 CO2-Absorber 1056.4.7 PFD 1056.5 Results 1056.6 Discussion 1106.6.1 Comparison of Amine Treating Solutions to Vitrisolƒòƒn1106.6.2 Enhanced H2S Removal of Barnett Shale Gas (case 2) 112viii Contents6.7 Conclusions 1136.8 Notation 115References 115Appendix 6-A: H&M Balance of Case 1 (British Columbia shale) of the Amine Process 117Appendix 6-B H&M Balance of Case 2a (Barnett shale) of the Amine Process with Stripper Promoter 119Appendix 6-C H&M Balance of Case 3 (Barnett shale) of the Amine Process (MEA) 121Appendix 6-D: H&M Balance of Case 1 (British Columbia shale) of the Vitrisolƒnprocess 123Appendix 6-E H&M Balance of Case 2 (Barnett shale) of the VitrisolƒnProcess 1257 New Amine Based Solvents for Acid Gas Removal 127Yohann Coulier, Elise El Ahmar, Jean-Yves Coxam, Elise Provost, Didier Dalmazzone, Patrice Paricaud, Christophe Coquelet and Karine Ballerat-Busserolles7.1 Introduction 1287.2 Chemicals and Materials 1317.3 Liquid-Liquid Equilibria 1317.3.1 LLE in {methylpiperidines – H2O} and {methylpiperidines – H2O – CO2} 1317.3.2 Liquid-Liquid Equilibria of Ternary Systems {Amine – H2O – Glycol} 1357.3.3 Liquid-Liquid Equilibria of the Quaternary Systems {CO2 – NMPD – TEG – H2O} 1367.4 Densities and Heat Capacities of Ternary Systems {NMPD – H2O – Glycol} 1377.4.1 Densities 1377.4.2 Specific Heat Capacities 1377.5 Vapor-Liquid Equilibria of Ternary Systems {NMPD – TEG – H2O – CO2} 1397.6 Enthalpies of Solution 1407.7 Discussion and Conclusion 143Acknowledgments 143References 144Contents ix8 Improved Solvents for CO2 Capture by Molecular Simulation Methodology 147William R. Smith8.1 Introduction 1478.2 Physical and Chemical Models 1498.3 Molecular-Level Models and Algorithms for Thermodynamic Property Predictions 1508.4 Molecular-Level Models and Methodology for MEA–H2O–CO2 1538.4.1 Extensions to Other Alkanolamine Solvents and Their Mixtures 155Acknowledgements 157References 1579 Strategies for Minimizing Hydrocarbon Contamination in Amine Acid Gas for Reinjection 161Mike Sheilan, Ben Spooner and David Engel9.1 Introduction 1629.2 Amine Sweetening Process 1629.3 Hydrocarbons in Amine 1649.4 Effect of Hydrocarbons on the Acid Gas Reinjection System 1669.5 Effect of Hydrocarbons on the Amine Plant 1679.6 Minimizing Hydrocarbon Content in Amine Acid Gas 1719.6.1 Option 1. Optimization of the Amine Plant Operation 1719.6.2 Option 2. Amine Flash Tanks 1769.6.3 Option 3. Rich Amine Liquid Coalescers 1789.6.4 Option 4. Use of Skimming Devices 1809.6.5 Option 5. Technological Solutions 182References 18310 Modeling of Transient Pressure Response for CO2 Flooding Process by Incorporating Convection and Diffusion Driven Mass Transfer 185Jianli Li and Gang Zhao10.1 Introduction 18610.2 Model Development 18710.2.1 Pressure Diffusion 18710.2.2 Mass Transfer 18810.2.3 Solutions 190x Contents10.3 Results and Discussion 19110.3.1 Flow Regimes 19110.3.2 Effect of Mass Transfer 19210.3.3 Sensitivity Analysis 19510.3.3.1 CO2 Bank 19510.3.3.2 Reservoir Outer Boundary 19610.4 Conclusions 196Acknowledgments 197References 19711 Well Modeling Aspects of CO2 Sequestration 199Liaqat Ali and Russell E. Bentley11.1 Introduction 19911.2 Delivery Conditions 20011.3 Reservoir and Completion Data 20111.4 Inflow Performance Relationship (IPR) and Injectivity Index 20111.5 Equation of State (EOS) 20211.6 Vertical Flow Performance (VFP) Curves 20511.7 Impact of the Well Deviation on CO2 Injection 20811.8 Implication of Bottom Hole Temperature (BHT) on Reservoir 20911.9 Impact of CO2 Phase Change 21311.10 Injection Rates, Facility Design Constraints and Number of Wells Required 21411.11 Wellhead Temperature Effect on VFP Curves 21411.12 Effect of Impurities in CO2 on VFP Curves 21611.13 Concluding Remarks 217Conversion Factors 218References 21812 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 221Qi Li, Xiaying Li, Zhiyong Niu, Dongqin Kuang, Jianli Ma, Xuehao Liu, Yankun Sun and Xiaochun Li12.1 Introduction 22212.2 The Amu Darya Right Bank Gas Reservoirs in Turkmenistan 223Contents xi12.3 Model Development 22312.3.1 State equation 22412.3.1.1 Introduction of Traditional PR State Equation 22412.3.1.2 Modifications for the Vapor-Aqueous System 22412.3.2 Salinity 22512.3.3 Diffusion 22612.3.3.1 Diffusion Coefficients 22612.3.3.2 The Cross-Phase Diffusion Coefficients 22612.4 Simulation Model 22712.4.1 Model Parameters 22712.4.2 Grid-Sensitive Research of the Model 22712.4.3 The Development and Exploitation Mode 23012.5 Results and Discussion 23012.5.1 Reservoir Pressure 23012.5.2 Gas Sequestration 23212.5.3 Production 23512.5.4 Recovery Ratio and Recovery Percentage 23812.6 Conclusions 23912.7 Acknowledgments 240References 241Index 245