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Storage of carbon dioxide in depleted natural gas reservoirs as gas hydrate Sun, Duo 2016

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   STORAGE OF CARBON DIOXIDE IN DEPLETED NATURAL GAS RESERVOIRS AS GAS HYDRATE     by    DUO SUN   B. A. Sc, Keio University, 2009 M. A. Sc, Keio University, 2011    A THESIS SUBMITTED IN PARTIAL FULFILLMENT OF  THE REQUIREMENTS FOR THE DEGREE OF    DOCTOR OF PHILOSOPHY  in  THE FACULTY OF GRADUATE AND POSTDOCTORAL STUDIES (Chemical and Biological Engineering)     THE UNIVERSITY OF BRITISH COLUMBIA (Vancouver)       September 2016   © Duo Sun, 2016  ii  Abstract More than 120 depleted natural gas reservoirs in Alberta, Canada have been identified as potential sites for CO2 storage at temperature and pressure conditions at which CO2 may form gas hydrate. Reservoir simulations presented in the literature have demonstrated the feasibility of storing CO2 in such reservoirs. In this thesis, the injection of CO2 in a laboratory size reservoir (packed bed of silica particles) serving as a physical model for a depleted reservoir was studied. The hypothesis was that injecting CO2 into the reservoir at gas hydrate formation conditions will be beneficial in terms of increased CO2 storage density. It is noted that CO2 is stored not only as hydrate but also some is dissolved in the residual pore water (not converted to hydrate) and some as a gas in the remaining pore space. The results indicate that hydrate formation enhances the CO2 storage density. The work also demonstrated that substances like tapioca starch added to the water in small quantities (1 wt %) delayed the onset of hydrate nucleation in the earlier stage but subsequently more CO2 was stored as hydrate compared to the tapioca starch-free systems. The delay in nucleation decreases the risk to form a hydrate plug in the injection system. The injection of the CO2-rich mixture (90 mol % CO2/10 mol % N2), which is a typical composition of a flue gas after CO2 capture process, into a reservoir with CH4 (simulating residual natural gas) was also studied in the laboratory reservoir. It was found that the total CO2 storage density (in hydrate, gaseous and dissolved state) decreased from 143 kg/m3 (the CO2 injection into a CH4 free reservoir) to 119 kg/m3. Finally, relevant phase equilibrium data were obtained in a constant volume high pressure vessel and by calorimetry. The results were found to be in good agreement with thermodynamic model calculated values within ± 40 kPa and ± 0.2 K, respectively.   iii  Preface Versions of Chapter 2 to 5 in this thesis have been published in peer-reviewed journals, in conference proceedings and presented in conferences listed below. Published articles in peer-reviewed Journals1-4: 1. Sun, D., Englezos, P. Storage of CO2 in a partially water saturated porous medium at gas hydrate formation conditions. International Journal of Greenhouse Gas Control 2014, 25, 1-8. 2. Sun, D., Englezos, P. CO2 storage capacity in laboratory simulated depleted hydrocarbon reservoirs - Impact of salinity and additives. Journal of Natural Gas Science and Engineering 2016, http://dx.doi.org/10.1016/j.jngse.2016.03.043 3. Sun, D., Englezos, P. Determination of CO2 storage density in a partially water-saturated lab reservoir containing CH4 from injection of captured flue gas by gas hydrate crystallization. The Canadian Journal of Chemical Engineering 2016, http://onlinelibrary.wiley.com/doi/10.1002/cjce.22655/full 4. Sun, D., Ripmeester, J., Englezos, P. Phase equilibria for the CO2/CH4/N2/H2O system in the hydrate region under conditions relevant to storage of CO2 in depleted natural gas reservoirs. Journal of Chemical and Engineering Date 2016, http://pubs.acs.org/doi/abs/10.1021/acs.jced.6b00547 Published in conference proceedings5: iv  1. Sun, D., Daraboina, N., Ripmeester, J. A., Englezos, P. Capture of CO2 and storage in depleted reservoirs in Alberta as gas hydrate. In Gas Injection for Disposal and Enhanced Recovery 2014, 305-310. Conference presentations: 1. Sun, D., Daraboina, N., Englezos, P. Storage of CO2 in the form of solid hydrate in depleted gas pool in Alberta. 62nd Canadian Chemical Engineering Conference. Vancouver, Canada, 14-17 October, 2012. 2. Sun, D., Englezos, P. Laboratory assessment of CO2 storage in a fixed bed of sand particles. Carbon Management Canada Conference. Calgary, Canada, 3-5 June, 2013. 3. Sun, D., Daraboina, N., Ripmeester, J. A., Englezos, P. Secure storage of CO2 as gas hydrate in depleted gas reservoirs in Northern Alberta. 4th International Acid Gas Injection Symposium. Calgary, Canada, 24-27, 2013. 4. Sun, D., Englezos, P. CO2 storage in partially water saturated sand bed by spiral and vertical tubes injection. Carbon Management Canada Conference. Banff, Canada, 27-29 May, 2014. 5. Sun, D., Englezos, P. Assessment of CO2 storage capacity in a laboratory bed of silica sand particles. 8th International Conference on Gas Hydrate. Beijing, China, 28 July-1 August, 2014. v  6. Sun, D., Englezos, P. Gas hydrate mediated storage of carbon dioxide in depleted gas reservoirs in Alberta. 64th Canadian Chemical Engineering Conference. Niagara Falls, Canada, 19-22 October, 2014. 7. Sun, D., Englezos, P. Effect of gas injection methods, additives and salinity on CO2 storage capacity in Alberta reservoirs. 65th Canadian Chemical Engineering Conference. Calgary, Canada, 4-7 October, 2015. Professor Peter Englezos is my principal research supervisor in Chemical and Biological Engineering Department at the University of British Columbia. Also, it is my pleasure to have fruitful discussions regarding this research project with Dr. John A. Ripmeester, a principal research officer from Steacie institute for Molecular Studies, National Research Council of Canada and Dr. Hassan Hassanzadeh, an associate professor from Schulich School of Engineering at the University of Calgary. I was responsible for literature review, experimental design, performing experiments and data analysis under the supervision of Professor Peter Englezos. I conducted the preparation of the manuscript under careful supervision.       vi  Table of Contents  Abstract .......................................................................................................................................... ii Preface ........................................................................................................................................... iii Table of Contents ......................................................................................................................... vi List of Tables ................................................................................................................................ ix List of Figures ................................................................................................................................ x List of Symbols ............................................................................................................................ xv List of Abbreviations ................................................................................................................. xix Acknowledgements .................................................................................................................... xxi Dedication ................................................................................................................................. xxiii Chapter 1    Introduction and Literature Review ...................................................................... 1 1.1. Emission and storage of CO2 ........................................................................................... 1 1.2. Why gas hydrate and depleted natrual gas reservoirs? .................................................... 6 1.3. Research objectives and thesis organization .................................................................. 13 Chapter 2    Injection of CO2 into a Partially Water Saturated Reservoir ........................... 15 2.1. Materials ......................................................................................................................... 15 2.2. Injection of CO2 in a gas cap under batch, series-batch and constant pressure mode ... 15 2.2.1. Experimental setup and methods ............................................................................ 15 2.2.2. Results and discussion ............................................................................................ 21 2.3. Injection of CO2 using spiral tubing under constant pressure mode .............................. 28 2.3.1. Experimental setup and methods ............................................................................ 28 2.3.2. Results and discussion ............................................................................................ 29 2.4. Injection of CO2 using vertical tubing under constant pressure mode and constant flow rate followed by constant pressure mode .................................................................................. 34 2.4.1. Experimental setup and methods ............................................................................ 34 2.4.2. Results and discussion ............................................................................................ 37 2.5. Summary ........................................................................................................................ 41 Chapter 3    Injection of CO2 into Reservoirs Containing PVP, Tapioca Starch and Saline Solution ........................................................................................................................................ 43 3.1. Materials and methods ................................................................................................... 43 vii  3.2. Injection of CO2 into a reservoir containing 1 and 3 wt % of PVP................................ 44 3.3. Injection of CO2 into a reservoir containing 0.5, 1 and 3 wt % of tapioca starch .......... 49 3.4. Injection of CO2 into a reservoir containing 2 and 4 wt % NaCl solution ..................... 54 3.5. Summary ........................................................................................................................ 58 Chapter 4     Injection of CO2 and CO2/N2 into CH4 Rich and CH4 Free Reservoirs .......... 61 4.1. Materials ......................................................................................................................... 61 4.2. Injection of CO2 into a reservoir containing 500 kPa CH4 ............................................ 63 4.3. Injection of CO2/N2 (90/10 mol %) into a reservoir without CH4 ................................. 67 4.4. Injection of CO2/N2 (90/10 mol %) into a reservoir containing 500 kPa CH4 ............... 71 4.5. Injection of CO2/N2 (90/10 mol %) into a reservoir containing 500 kPa CH4 and 1 wt % tapioca starch ............................................................................................................................. 75 4.6. Summary ........................................................................................................................ 77 Chapter 5    Measurement of Hydrate Phase Equilibria in the CO2/CH4/N2/H2O system in a Stirred High Pressure Crystallizer and High Pressure Micro Differential Scanning Calorimetry (HP-µDSC) ............................................................................................................. 79 5.1. Materials ......................................................................................................................... 79 5.2. Hydrate formation and dissociation in a stirred high pressure crystallizer containing water, 2 and 4 wt % saline solution ........................................................................................... 79 5.2.1. Experiment setup and methods. .............................................................................. 79 5.2.2. Results and discussion. ........................................................................................... 83 5.3. Hydrate dissociation in a high pressure micro differential scanning calorimetry containing water, 2 and 4 wt % saline solution ......................................................................... 87 5.3.1. Experiment setup and methods. .............................................................................. 87 5.3.2. Results and discussion. ........................................................................................... 89 5.4. Summary ........................................................................................................................ 97 Chapter 6    CO2 Storage Density .............................................................................................. 98 6.1. CO2 storage density with and without hydrate technology ............................................ 98 6.2. CO2 storage density in an Alberta reservoir ................................................................. 103 6.3. Economic analysis of CO2 storage ............................................................................... 104 Chapter 7    Conclusions and Recommendations ................................................................... 107 7.1. Conclusions. ................................................................................................................. 107 7.2. Recommendations for future work. .............................................................................. 109 viii  Bibliography .............................................................................................................................. 111 Appendices ................................................................................................................................. 127 Appendix A: Mass balance and energy balance...................................................................... 127 Appendix B: Apparatus of the experiments of hydrate equilibria measurement using high pressure crystallizers. .............................................................................................................. 131                   ix  List of Tables  Table 1.1. CO2 emission mitigation technologies.. ........................................................................ 4  Table 2.1. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for gas cap mode CO2 injection experiments ............... 27  Table 2.2. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for spiral tubing mode CO2 injection experiments ....... 33  Table 2.3. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for vertical tubing mode CO2 injection experiments .... 41  Table 3.1. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for the experiments of CO2 injection into a reservoir containing 1 and 3 wt % PVP. ...................................................................................................... 46  Table 3.2. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for the experiments of CO2 injection into a reservoir containing 0.5, 1 and 3 wt % tapioca starch ................................................................................. 53  Table 3.3. The number of moles of CO2 stored in hydrate (𝑛𝐶𝑂2,𝐻), the percent of water formed hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), the CO2 storage density as the form of hydrate (𝜌𝐶𝑅𝐶𝑂2,𝐻) and the induction time for the experiments of CO2 injection into a reservoir containing 2 and 4 wt % NaCl solutions ....................................................................................... 58  Table 4.1. The hydrate formation induction time, the number of moles of CO2 stored in hydrate form (𝑛𝐶𝑂2,𝐻), the percentage of reservoir water formed CO2 hydrate (𝑅𝐶𝑂2,𝑊), the CO2 hydrate saturation (𝑆𝐶𝑂2,𝐻), CO2 storage density in hydrate form (𝜌𝐶𝑅𝐶𝑂2,𝐻). All experiments at 277 K .... 62  Table 5.1. Hydrate equilibrum pressure measured in high poressure crystallizer at fixed temperature ................................................................................................................................... 81  Table 5.2. Hydrate dissociation temperatures and endothermic heat measured under constant 3200 kPa in a HP-μDSC in the water droplet and water, 2 and 4 wt % NaCl solution fully saturated reservoir. ........................................................................................................................ 90  Table 6.1. Experimental conditions of experiments (a) to (s) .................................................... 100 x  List of Figures  Figure 1.1. Canadian national GHG emission, 1990 to 2013. (Adapted from Environment Canada, 2015) ................................................................................................................................. 2  Figure 1.2. Canadian emission breakdown by components. (Adapted from Environment Canada, 2015) ............................................................................................................................................... 3  Figure 1.3. Canadian emission breakdown by sources. (Adapted from Environment Canada, 2015) ............................................................................................................................................... 3  Figure 1.4. Concept of CO2 storage into depleted gas reservoirs. (Adapted from Zatsepina and Pooladi-Darvish, 2011) ................................................................................................................... 7  Figure 1.5. Canadian emission breakdown by provinces. (Adapted from Environment Canada, 2015) ............................................................................................................................................... 7  Figure 1.6. Three common hydrate unit crystal structures. (Adapted from Sloan, 2003) ............. 9  Figure 1.7. Schematic image of CO2 hydrate............................................................................... 10  Figure 2.1. CO2 injection experimental setup for experiments (a) to (f) ..................................... 16  Figure 2.2. Schematic of injection of CO2 into a gas cap ............................................................ 17  Figure 2.3. Pressure profiles in the crystallizer in gas cap mode CO2 injection experiments for 24 h. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments .................................................................................................................... 22  Figure 2.4. Temperature profiles in the crystallizer in gas cap mode CO2 injection experiments for 24 h. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments ............................................................................................................. 23  Figure 2.5. Temperature profiles in the crystallizer in gas cap mode CO2 injection experiments for the first 60 min. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments ............................................................................................... 25  Figure 2.6. Schematic of injection of CO2 using spiral tubing (A) and the spiral tubing (B) ...... 29  Figure 2.7. Temperature profiles in the crystallizer in spiral tubing mode CO2 injection experiments for 24 h. (d1) Single spiral tubing gas injection (Top), (e1) Single spiral tubing gas injection (Bottom), and (f1) Double spiral tubing gas injection (Top + Bottom) experiments .... 30  Figure 2.8. Temperature profiles in the crystallizer in spiral tubing mode CO2 injection experiments for the first 60 min. (d1) Single spiral tubing gas injection (Top), (e1) Single spiral xi  tubing gas injection (Bottom), and (f1) Double spiral tubing gas injection (Top + Bottom) experiments ................................................................................................................................... 31  Figure 2.9. CO2 injection setup for the experiments under constant pressure and constant flow rate followed by constant pressure mode gas injection method ................................................... 35  Figure 2.10. Schematic of injection of CO2 using vertical tubing (A) and the picture of vertical tubing (B) ...................................................................................................................................... 36  Figure 2.11. Temperature profiles in the reservoir corresponding to experiment (g1) for injection of CO2 under constant pressure (3200 kPa) into the crystallizer for 24 h and the first 120 min .. 38  Figure 2.12. Pressure and temperature profiles in the reservoir corresponding to experiment (h4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the crystallizer for 24 h, the first 360 min and 120 h .......................................... 40  Figure 2.13. CO2 partial phase diagram with Alberta depleted natural gas reservoirs P-T condition region ............................................................................................................................ 42  Figure 3.1. Pressure and temperature profiles in the reservoir corresponding to experiment (i4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 1 wt % PVP aqueous solution for 24 h, the first 360 min and 120 h ....................................................................................................................................... 45  Figure 3.2. Pressure and temperature profiles in the reservoir corresponding to experiment (j4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 3 wt % PVP aqueous solution for 24 h, the first 360 min and 120 h ....................................................................................................................................... 48  Figure 3.3. Pressure and temperature profiles in the reservoir corresponding to experiment (k4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 0.5 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h ................................................................................................................. 50  Figure 3.4. Pressure and temperature profiles in the reservoir corresponding to experiment (l4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 1 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h......................................................................................................................... 51  Figure 3.5. Pressure and temperature profiles in the reservoir corresponding to experiment (m4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 3 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h......................................................................................................................... 52  Figure 3.6. Pressure and temperature profiles in the reservoir corresponding to experiment (n1) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure xii  (3200 kPa) into the reservoir containing 2 wt % NaCl solution for 24 h and for the first 360 min....................................................................................................................................................... 55  Figure 3.7. Pressure and temperature profiles in the reservoir corresponding to experiment (o1) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 4 wt % NaCl solution for 24 h and for the first 360 min....................................................................................................................................................... 57  Figure 3.8. The number of moles of CO2 stored in hydrate in deionized water (h4), 3 wt % PVP (j4) and 1 wt % tapioca starch (l4) reservoirs in 120 h experiments ............................................ 59  Figure 3.9. CO2 hydrate phase diagram in pure water, 2, 4, 7.4 and 9.1 wt % saline solutions. ΔP0 = 1218 kPa, ΔP2 = 1013 kPa, ΔP4 = 768 kPa, ΔP7.4 = 196 kPa and ΔP9.1 = -211 kPa ............ 60  Figure 4.1. Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (p1) for 24 h, the first 360 min and 120 h .................................................................. 64  Figure 4.2. CO2/CH4-H2O partial phase diagram. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/CH4 (84/16 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPp = 3100 kPa-2118 kPa = 982 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/CH4 (95/5 mol %) mixture at 277 K after 120 h, where driving force ΔPp = 3200 kPa-2022 kPa = 1178 kPa ........................... 67  Figure 4.3. Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (q1) for 24 h, the first 360 min and 120 h .................................................................. 70  Figure 4.4. CO2/N2-H2O partial phase diagrams. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/N2 (90/10 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPq = 3200 kPa-2219 kPa = 981 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/N2 (85/15 mol %) mixture at 277 K after 120 h, where ΔPq = 3200 kPa-2359 kPa = 841 kPa ................................................... 71  Figure 4.5. Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (r1) for 24 h, the first 360 min and 120 h ................................................................... 73  Figure 4.6. CO2/N2/CH4-H2O partial phase diagrams. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/N2/CH4 (76/8/16 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPr = 3200 kPa-2329 kPa = 871 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/N2/CH4 (78/16/6 mol %) mixture at 277 K after 120 h, where driving force ΔPr = 3200 kPa-2457 kPa = 743 kPa ............ 74  Figure 4.7. Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (s1) for 24 h, the first 600 min and 120 h .................................................................. 76  Figure 4.8. The ratio of moles of CO2 stored in hydrate form over the moles of water in place in the reservoir after every 24 h in experiments (h1) and (p1) to (s1) .............................................. 78  xiii  Figure 5.1. Schematic of the apparatus for hydrate formation and dissociation in bulk system . 82  Figure 5.2. CO2 hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions ........................................................................................................................................ 84  Figure 5.3. CO2/CH4 (95/5 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions .................................................................................................................. 85  Figure 5.4. CO2/N2 (85/15 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions .................................................................................................................. 86  Figure 5.5. CO2/N2/CH4 (78/16/6 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions......................................................................................................... 87  Figure 5.6. Droplet sample holder and reservoir sample holder using in HP-μDSC ................... 89  Figure 5.7. Hydrate dissociation peaks for four hydrate forming systems (#1) observed with HP-μDSC in the droplet sample holder under a 0.1 K/min heating protocol ...................................... 91  Figure 5.8. CO2 hydrate dissociation peaks for hydrate formed in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol ............................................................................................................................ 93  Figure 5.9. Hydrate dissociation peaks for hydrate formed by the CO2/CH4 (95.10/4.90 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol ........................................................ 94  Figure 5.10. Hydrate dissociation peaks for hydrate formed by the CO2/N2 (85.03/14.97 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol ........................................................ 95  Figure 5.11. Hydrate dissociation peaks for the hydrate formed by the CO2/N2/CH4 (78.02/15.89/6.09 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol .............. 96  Figure 6.1. Total CO2 storage densities (Average for the three runs of experiments under each method) ....................................................................................................................................... 101  Figure 6.2. Average of total CO2 storage densities in the experiments (s), CO2 storage as low pressure gas at 2110 kPa and 277 K and high pressure gas at 5220 kPa and 285 K under the injection of CO2/N2 (90/10 mol %) gas mixture into a reservoir without water and CH4 .......... 103  xiv  Figure 6.3. Economic analysis of CO2 storage .......................................................................... 105  Figure B.1. Apparaqtus od the experiments of hydrate equilibria measurement using high pressure crystallizer. (Adapted from Sharifi et al., 2014) ........................................................... 132                    xv  List of Symbols  𝐴𝑛𝐺−𝐿 Gas-liquid surface area per unit volume in the block n [m2/m3] 𝐴𝑛𝐻 Hydrate surface area per unit volume in the block n [m2/m3] ∆𝐸 Activation energy [J] 𝐹𝑛𝐶𝑂2 Mass flux of CO2 transported through the gas-water surface in block n [kg/m2 s] 𝐹𝑛ℎ Heat flux flowed to the surrounding volume [J/m2] 𝐹𝑛𝑊 Mass flux of water transported through the gas-water surface in block n [kg/m2 s] 𝑓𝑒𝑞 Fugacity of CO2 at the hydrate equilibrium pressure [kPa] 𝑓𝑛 Fugacity of CO2 at the pressure of block n [kPa] H Heat [mJ] 𝐻𝐶𝑂2 Enthalpy of CO2 gas for energy balance modeling [J] 𝐻𝐻 Enthalpy of hydrate for energy balance modeling [J] 𝐻𝑆 Enthalpy of silica sand energy balance modeling [J] 𝐻𝑊 Enthalpy of water for energy balance modeling [J] 𝑘𝑓 The hydrate formation rate constant 𝐾𝑓0 Intrinsic formation rate constant 𝑀𝐻 Molecular weight of the hydrate [g/mol] 𝑀𝑛𝐶𝑂2 Mass change of CO2 per unit volume of block n [kg/m3] xvi  𝑀𝑛𝐻 Mass change of hydrate per unit volume of block n [kg/m3] 𝑀𝑛𝑊 Mass change of water per unit volume of block n [kg/m3] 𝑁 Number of moles of hydrate per unit volume of block n [mol] n A block in the reservoir assumed for the mass and energy balance modeling 𝑛𝐶𝑂2,𝐻 Number of moles of CO2 as hydrate in the crystallizer [mol] 𝑛𝐶𝑅−𝐶𝑂2,0 Number of moles of CO2 as gaseous in the crystallizer at time 0 [mol] 𝑛𝐶𝑅−𝐶𝑂2,𝑡 Number of moles of CO2 as gaseous in the crystallizer at time t [mol] 𝑛𝐷,𝑡 Number of moles of CO2 dissolved in the crystallizer water at time t [mol] 𝑛𝑆𝑉−𝐶𝑂2,0 Number of moles of CO2 as gaseous in the supply vessel at time 0 [mol] 𝑛𝑆𝑉−𝐶𝑂2,𝑡              Number of moles of CO2 as gaseous in the supply vessel at time t [mol] 𝑛𝑊,𝐶𝑂2𝐻                  Number of moles of original reservoir water formed CO2 hydrate [mol] 𝑛𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙                   Number of moles of original reservoir water [mol] P                                  Pressure [kPa/MPa] ∆P0, ∆P2, ∆P4, ∆P7.4, ∆P9.1 Pressure driving force of CO2 hydrate forming in water, 2, 4, 7.4 and 9.1 wt % NaCl solutions ∆PP, ∆Pq, ∆Pr, ∆Ps Pressure driving force at the hydrate nucleation point in experiment (p1) to (s1)  𝑃𝐶𝑅 Crystallizer pressure [kPa] 𝑃𝑆𝑉                         Supply vessel pressure [kPa] 𝑄𝑛𝐻 Enthalpy of  hydrate per unit volume of block n [J/m3] 𝑞𝑛𝐶𝑂2,𝑐𝑜𝑛 Consumption rate of CO2 per unit volume of block n [kg/m3 s] xvii  𝑞𝑛𝐶𝑂2,𝑖𝑛𝑗 Injection rate of CO2 per unit volume of block n [kg/m3 s] 𝑞𝑛𝐻,𝑓𝑜𝑟 Formation rate of hydrate per unit volume of block n [kg/m3 s] 𝑞𝑛𝑊,𝑐𝑜𝑛 Injection rate of water per unit volume of block n [kg/m3 s] R Universal gas constant [8.314 J/K mol] 𝑅𝐶𝑂2,𝑊                   Percentage of initial reservoir water formed CO2 hydrate 𝑆𝐶𝑂2 Saturation of CO2 gas for energy balance modeling 𝑆𝐶𝑂2,𝐻                       CO2 hydrate saturation in the reservoir free space 𝑆𝐻 Saturation of hydrate for energy balance modeling 𝑆𝑊 Saturation of water for energy balance modeling 𝑆𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙 Initial reservoir water saturation in the reservoir free space T                                  Temperature [K/°C] 𝑈𝑛 Total internal energy per unit volume of block n [J/m3] 𝑉𝐶𝑅 Crystallizer volume [cm3] 𝑉𝑃 Porous volume in the reservoir [m3] 𝑉𝑆𝑉 Supply vessel volume [cm3] 𝑊𝐶𝑂2,𝐺 Mass of CO2 stored in reservoir as gaseous form [kg] 𝑊𝐶𝑂2,𝐻 Mass of CO2 stored in reservoir as hydrate form [kg] 𝑊𝐶𝑂2,𝑊                       Mass of CO2 stored in reservoir as dissolving in the water [kg] 𝑦𝐶𝑂2,0                            Mole fraction of CO2 at time 0 𝑦𝐶𝑂2,𝑡                            Mole fraction of CO2 at time t xviii  z                                       Compressibility factor ∅ Porosity of the reservoir 𝜌𝐶𝑂2 Density of CO2 gas for energy balance modeling [kg/m3] 𝜌𝐶𝑅𝐶𝑂2,𝐻                                                         Total CO2 storage density (in hydrate, gaseous and dissolved state) in the reservoir [kg/m3] 𝜌𝐶𝑅𝐶𝑂2,𝐺                CO2 storage density in the reservoir as gaseous form [kg/m3] 𝜌𝐶𝑅𝐶𝑂2,𝐻                             The CO2 storage density in the reservoir as hydrate form [kg/m3] 𝜌𝐶𝑅𝐶𝑂2,𝑊                     The CO2 storage density in the reservoir as dissolving in the water [kg/m3] 𝜌𝐻 Density of hydrate for energy balance modeling [kg/m3] 𝜌𝑆 Density of silica sand for energy balance modeling [kg/m3] 𝜌𝑊 Density of water for energy balance modeling [kg/m3]                   xix  List of Abbreviations  AEUB Alberta Energy and Utilities Board CO2-ECBM Enhanced coal-bed methane recovery using CO2 injection CO2-EGR Enhanced gas recovery using CO2 injection CO2-EOR Enhanced oil recovery using CO2 injection CR                               Crystallizer DAQ system Data acquisition system DSC Differential scanning calorimetry -eq Equivalent ER External refrigerator GC                               Gas Chromatograph GHG Greenhouse gas HP- μDSC High pressure micro differential scanning calorimetry IPCC Intergovernmental Panel on Climate Change KHIs Kinetic hydrate inhibitors PC Personal computer PID controller              Proportional integral derivative controller PT Pressure transmitter PVCap Polyvinylcaprolactam PVP Polyvinylpyrrolidone xx  SDS Sodium dodecyl sulfate SES Sodium ethyl sulfate SV Supply vessel sI, sII and sH Structure I, II and H for hydrate sm3 Standard cubic meter                         xxi  Acknowledgements I would like to thank the faculty, staff, students and friends who helped me and participated in this four-years research work. I offer my special gratitude to my supervisor, Professor Peter Englezos, for his sciential guidance through the whole period of my research project. His intelligent mind encouraged me to practice and improved myself. I appreciate your consistent support to guide me to complete this work. I owe acknowledge and sincere gratitude to Dr. John A. Ripmeester, Dr. Hassan Hassanzadeh, Dr. Jim C. Lim and Dr. Olga Zatsepina for their scientific discussion and advice to create me a scientific thinking. I would like to thank Dr. Jim C. Lim and Dr. Gabriel Potvin who offered me a teaching assistant position to develop my research and practice my teaching skill. I always appreciate the fruitful discussion with them. I would also like to thank Dr. Zhao-Yang Chen and Dr. Gang Li from Dr. Xiao-Sen Li research group. Their suggestions helped in the experimental studies and it was my pleasure to work with them. I would like to continue this acknowledgement to my colleagues and friends: Hassan, who I worked with in the lab for four years (including plenty of discussion); Alireza, who I always talked with in the office; Nagu, Yi-Zhou and Iwan, who helped me when I first came to the lab to start the experimental work; Negar and Bryan, who provided help for the chemicals preparation. Thanks to Li-Tao, Moritz, Christine, Simon and Bill for their participation in CHBE 606 works which left a wonderful memory in my life. xxii  Sincere thanks to the CHBE staff: Helsa, Joanne, Jane, Lori, Amber, Salman, Sarah, Magnolia, Gina, Ivan, Marleen, Doug, Gordon, Charle, David, Graham, Alex, Ken, Richard Ryoo and Richard Zhang for their support. Particular thanks are owed to my parents, who have supported me throughout my years of education and life. Without your love this work could not have been possible. Finally, thank you Olivia for being my love. Your endless support and encouragement made me a completed life.                 xxiii  Dedication  To my parents; Ying & Yao-Cheng & my love; Olivia                    1  1 Introduction and Literature Review 1.1 Emission and storage of CO2 CO2, one of the most prevalent greenhouse gases (GHG), took the center place of the stage where the climate change concerns have been frequently discussed in recent decades. The increased concentration of greenhouse gases in the atmosphere, as a result of human activities, has caused serious concern about global warming. Also, a consequence of rising atmospheric CO2 is that more CO2 dissolves in the oceans to form carbonic acid and reduces the pH of the ocean water6. It is estimated that the emission of 1,000 Gt of CO2-eq leads to about 1.75 °C increase in global average temperature and the Intergovernmental Panel on Climate Change (IPCC) reported that the global average temperature has increased 0.76 °C between 1850 to 1899 and 2001 to 20057. From 2000 to 2010, the GHG emissions increased at a 2.2 % annual rate and reached 49 Gt CO2-eq at 2010. Fossil fuel energy combustion is considered the major source of anthropogenic CO2 emitted to the atmosphere8. It is estimated that 65 % of the emissions, which is about 32 Gt originates from the fossil fuel combustion sources and industrial processes9. In Canada, as shown in Figure 1.1, it is estimated that 700 to 760 Mt of CO2-eq was annually emitted in 2005 to 201310. Canada signed the Copenhagen Accord in 2009 and agreed to reduce its GHG emissions to 17 % below 2005 levels (749 Mt CO2-eq) by 2020. Figure 1.2 and 1.3 shows the Canadian emission breakdown by components and sources in 201310. About 80 % of the GHG emitted is CO2 and 45 % of the GHG emission were from stationary combustion sources. It is noted that it is considered easier to be collect CO2 from stationary sources 2  compared to the GHG emitted from other sources. Capture and storage of CO2 is a possible strategy that deals with the CO2 emitted from the fossil fuel combustion sources in order to reduce the GHG emission and achieve the Copenhagen Accord goal.    Figure 1.1 Canadian national GHG emission, 1990 to 2013. (Adapted from Environment Canada, 2015) 3   Figure 1.2 Canadian emission breakdown by components. (Adapted from Environment Canada, 2015)  Figure 1.3 Canadian emission breakdown by sources. (Adapted from Environment Canada, 2015) 4  Table 1.1 CO2 emission mitigation technologies Geological media for CO2 storage Storage capacity Cost Feasibility Leak risk Unmineable coal bed Large High Easy High Deep saline formation Very large Very high Hard High Depleted oil and gas reservoir Large Low Easy Very low  Geological storage of captured CO2 is considered to be one of the most promising methods which can contribute towards significant reduction in CO2 emission and permanent storage stability. Geological storage may be defined as the placement of CO2 into a subsurface formation11. CO2 can be stored in unmineable coal beds, deep saline formations and in depleted oil and gas reservoirs. Table 1.1 shows the potential of geological storage of CO2 in these three media. The in situ carbon mineralization is considered another form of geological CO2 storage12-14. Although the CO2 storage capacity through carbon mineralization is large as 1 Gt per year14, the high injection cost and slow reaction rate created a barrier for the carbon mineralization to be widely applied to reduce CO2 emission. In addition, the CO2 storage potential in selected coal beds for enhanced coal-bed methane recovery using CO2 injection (CO2-ECBM) has also been discussed15 and 300 to 1000 Gt of CO2 was suggested to be stored in this manner16. Saline formations/aquifers are attractive candidates for CO2 disposal and it is important to understand the behavior of CO2 when it is injected. Particularly CO2 hydrate will form when injection is applied at a sufficiently high pressure17. However, CO2 hydrate formation is not always a negative occurrence on CO2 storage. Koide et al. suggested that the storage of CO2 emitted from 5  fossil fuel power plants in depleted gas and oil reservoirs can be aided by a forming CO2 hydrate gas cap to prevent leakage of stored CO218. The concept of the gas hydrate to seal a natural gas storage reservoir was also suggested earlier by Evrenos et al. in 197119 and Hatzikiriakos and Englezos in 199420. The deep saline formations could store 2700 Gt CO2, however it requires energy to inject the CO2 and store it at supercritical conditions. There is also the leakage concern21. CO2 storage in depleted oil and gas reservoirs is indeed another option to reduce CO2 and can produce oil or natural gas in the meantime18. The reservoirs are known to have held liquids and gases for millions of years. Their geology is known and there is substantial available capacity estimated globally at 400 to 900 Gt22. It is noted that enhanced oil recovery using CO2 injection (CO2-EOR) into depleted oil field is relatively mature technology and has been applied in the petroleum industry during the past four decades15. On the other hand, enhanced gas recovery using CO2 injection (CO2-EGR) into depleted natural gas reservoirs is also a commercially viable method to store CO2 and simultaneously produce natural gas15,23-26. Depleted gas reservoirs are considered the most suitable sites to store CO2 since they have already proven gas capacity and storage safety over geological time scales22. The first industrial scale CO2 storage project was the depleted Krechba gas field in the central region of Algeria, which was started in 200427. Another example of underground storage of CO2 in porous and permeable reservoir rocks is the Sleipner West gas field in the North Sea28. More recently, the Otway project in Australia and similar projects in Europe (Pathfinding project in the Netherlands and Germany, CO2SINK Integrated project in Germany and Lacq CO2 pilot project in France) demonstrated the long term storage of CO2 in a gas field26,29,30. 6  The geological storage of captured CO2 represents an attractive method to deal with climate change concerns arising form the continued use of fossil fuels and the resulting emission of CO2. In this work, we focus on depleted gas reservoirs because such formations have been effective in storing natural gas prior to its extraction. More specifically, we will be focusing on shallow reservoirs where the temperature conditions may favour CO2 gas hydrate formation. 1.2 Why gas hydrate and depleted natural gas reservoirs? A new thinking about CO2 storage in the form of solid hydrate into depleted natural gas reservoirs was first provided in 200431. The concept of CO2 storage into gas reservoirs is shown in Figure 1.4. Due to CO2 injection the pressure in those gas reservoirs will increase and enter the region of thermodynamic stability of CO2 hydrate. Preliminary research indicated that 61 gas reservoirs in Alberta (Cold Lake and Fort McMurray area) have CO2 storage potential in hydrate form in 201032,33. Three years later the number of reservoirs with such CO2 storage potential increased to 121 and the amount of CO2 that could be stored in these gas reservoirs was estimated to be 61 Gt34. The depleted gas reservoirs located at a 200 to 1400 m depth region (108 of the gas reservoirs are located 200 to 500 m underground) and consist of a porous medium containing water and residual natural gas at 2 to 5 MPa and 1 to 10 °C34. As shown in Figure 1.5 it was reported that Alberta emitted 267 Mt CO2 in 2013 and approximately 187 Mt (70 %) of the CO2 came from large stationary sources (e.g. power plants, refineries, oil sands operations, and petrochemical and cement plants)10. The injection of CO2 into the depleted gas reservoirs in Alberta and the storage of CO2 as gas hydrate would be able to store the CO2 emitted from Alberta sources for 326 years.  7   Figure 1.4 Concept of CO2 storage into depleted gas reservoirs. (Adapted from Zatsepina and Pooladi-Darvish, 2011)    Figure 1.5 Canadian emission breakdown by provinces. (Adapted from Environment Canada, 2015) 8  Gas hydrates, also called clathrate hydrates are non-stoichiometric crystalline compounds consisting of hydrogen-bonded water molecules. The water molecules, generally called “host molecules”, build a network with hydrogen bonds to stabilize molecules other than water, generally called “guest molecules”. Gas hydrates were first found by Sir Humphrey Davy in 1810, who observed that a solution of chlorine gas in water freezes faster than pure water. After that research on hydrates attracted the strong attention of scientists. In 1934, Hammerschmidt reported that formation of gas hydrates in oil or gas transportation pipelines may cause blockage35 and such hydrates were concerned as a hindrance of the natural gas industry. The idea of storing natural gas as hydrate has been presented as early as in 1945 and related applications were proposed19,36. It was also reported in the mid-1960s that gas hydrates occur naturally in the earth. Several applications of hydrate for the development of technologies for gas separation, gas transportation and storage, heat storage, sea water desalination, and others have been widely discussed37-44. Three crystallographic structures of hydrates have been known to exist—structure I (sI), structure II (sII), and structure H (sH)—which have different lattice dimensions to accommodate the respective guest molecules45-49. Three structures of hydrates are shown in Figure 1.6 and also described below. • sI:  Consist of small cavities labeled 512 as it has twelve pentagonal faces and large cavities labeled 51262 as it has twelve pentagonal and two hexagonal faces. • sII:  9  Consist of small cavities labeled 512 as it has twelve pentagonal faces and large cavities labeled 51264 as it has twelve pentagonal and two hexagonal faces. • sH:  Consist of small cavities labeled 512 as it has twelve pentagonal faces, large cavities labeled 51268 as it has twelve pentagonal and two hexagonal faces and irregular cavities labeled 435663 as it has three square, six pentagonal and three hexagonal faces.  Figure 1.6 Three common hydrate unit crystal structures. (Adapted from Sloan, 2003)  10   Figure 1.7 Schematic image of CO2 hydrate. Figure 1.7 shows four CO2 molecules trapped in cages of CO2 hydrate. Cages are formed by hydrogen bonded water molecules. Gas hydrates may contain a significant quantity of gas. For example, the volume of CO2 gas stored in 1 m3 of CO2 hydrate is approximately 160 m3 at standard temperature and pressure49. Using the large gas storage capability of gas hydrates, novel applications, such as the storage and transportation of CO2, natural gas and H2, have been studied38,50,51. Considering the large gas capacity of hydrates, trapping CO2 in hydrate form to store carbon is an attractive option to significantly reduce CO2 emissions to the atmosphere. Numerical studies of geological storage CO2 as gas hydrate in natural gas hydrate reservoirs have been reported recently. CO2 hydrate formation due to injection and coincident CO2 storage/CH4 production from natural gas were demonstrated. The temperature rises indicate hydrate formation because it is an exothermic reaction. However, the continuation of gas injection could lead to near-well blockage by forming hydrate52,53. Zatsepina and Pooladi-Darvish examined hydrate formation during a period of 270 days by employing a reservoir simulator. CO2 injection was simulated into a 5 m thickness depleted natural gas reservoir. The rate of CO2 injection was constant at 0.1 × 106 sm3/day. Results indicated that more hydrate forms at the bottom and top 11  position where heat of hydrate formation diffuses to the base and cap shale. The effect of initial conditions has been discussed. The higher the initial reservoir temperature is, the later the process of hydrate formation will be. For a higher initial pressure, hydrate formation occurs earlier because larger pressure driving force was provided. The amount of hydrate decreases with increasing initial pressure. Moreover, the higher the injection temperature, the further away from the wellbore hydrate forms54-56. To prevent the formation of hydrate near the injection well, the effect of kinetic hydrate inhibitors (KHIs) on hydrate formation has been studied57-60. Polyvinylpyrrolidone (PVP) and tapioca starch are known to prolong the hydrate formation induction time and reduce the hydrate crystalline growth rate61-63. A delay in hydrate nucleation may reduce the possibility of undesirable hydrate formation in the injection system but over long periods of time may interestingly lead to improved hydrate conversion64. PVP is a soluble polymeric compound with pendant rings structures which is suggested to be critical structures related to the mode the KHIs interact with the hydrate structures65. Tapioca starch is a natural polymer which is usually cationized to use in industrial applications according the non-toxic and biodegradable property61. Therefore, the assessment of the effect of the addition of KHIs on CO2 hydrate formation and CO2 storage capacity is of interest because it may increase the amount of CO2 stored.  It is well known that natural gas and oil reservoirs may contain electrolytes and thus the salinity of the reservoir may be a consideration since it will affect the hydrate phase equilibrium conditions. Dissolved electrolytes were also reported to slightly reduce the water conversion to hydrate in the porous media66. Canadian Geological Survey reported that up to 4 wt % salinity exists in some of the Alberta reservoirs which have CO2 storage potential in the gas hydrate 12  form34. Thus the assessment of the effect of reservoir salinity on hydrate formation and CO2 storage capacity is required.  It is noted that although our study is motivated by our focus on hydrocarbon reservoirs in Alberta, Canada, the conclusions can be generalized to reservoirs elsewhere in the world. According to this concept of CO2 storage, CO2 will be injected into a natural gas (CH4) reservoir. The thermodynamic (P-T) conditions are such that the hydrate forming molecules in the reservoir will form hydrate with two guests (CH4 and CO2). The equilibrium conditions for CH4/CO2 hydrate are different from the hydrate formed by either CH4 or CO2.  CH4 hydrate requires higher pressure or lower temperature to be stabilized compared to CO2 hydrate. Moreover, it has been suggested that at the range from 0 °C to 10 °C, CH4 hydrate needs approximately 2 MPa more kinetics driving force to form hydrate compared to CO2 hydrate at the same temperature67-71. Considering that 0.5 MPa CH4 gas originally exists in the gas reservoirs located in Alberta, 2 MPa to 3.5 MPa of CO2 can be injected to form mixed hydrate without liquefaction of CO255.  In order to advance further our understanding of the parameters affecting CO2 storage we need to take into account the fact that CO2 gas captured from large stationary sources is mixed with impurities like N2 and O2. In order to render the CO2 capture (separation) process economically viable the CO2 concentration in the treated flue gas is about 90 mol %72. Comparing to CO2, it requires much higher pressure for N2 to form hydrate according to the hydrate equilibria calculation using CSMGem software49. Thus the effect of presence of CH4 and N2 in the reservoir on hydrate formation need to be studied. 13  Recently, the studies of hydrate formation and dissociation behaviors in the presence of KHIs and gas mixture have been conducted with the techniques using high pressure reactor62,63,73-81 and differential scanning calorimetry (DSC)63,81-86 in terms of achieving efficient experimental test. These apparatuses were also applied in this experimental study. 1.3 Research objectives and thesis organization As seen in the previous sections, numerical simulation of CO2 injection into depleted natural gas reservoirs accompanied by gas hydrate formation has given merit to the idea of storing CO2 into such reservoirs. Our first objective in the present thesis was to demonstrate this CO2 storage concept in a laboratory reservoir at temperature and pressure conditions found in Alberta. In addition, our objective was to assess the effects of additives in the reservoir to enhance the conversion of CO2 into hydrate and thus store more CO2. Finally, our objective was also to determine the effects of N2 in the injection gas, the residual CH4 in place in the reservoir, and the presence of salinity in the reservoir on hydrate formation and CO2 storage density. The hypothesis was that the injection of CO2 into the reservoir at gas hydrate formation conditions will improve CO2 storage capacity and the addition of additives will benefit in terms of increasing hydrate formation and thus storage capacity. In this work, the demonstration of CO2 hydrate formation under physical CO2 injection into laboratory scaled reservoir and the comparison of the amount of CO2 stored as hydrate under various gas injection methods were shown in Chapter 2. The effects of PVP, tapioca starch and saline solution on hydrate formation were discussed in Chapter 3. The effects of N2 in the injection gas and CH4 in the reservoir on hydrate formation were assessed in Chapter 4. The dissociation temperature and pressure of the hydrate formed in typical depleted natural gas 14  reservoir conditions were measured in a stirred high pressure crystallizer and by a high pressure micro differential scanning calorimetry and their consistency with the calculation data was described in Chapter 5. The discussion of CO2 storage density with and without hydrate technology, the economic evaluation and a mass and energy balance model were shown in Chapter 6. Finally, the conclusions of this experimental work and recommendations for the future work were presented in Chapter 7.              15  2 Injection of CO2 into a Partially Water Saturated Reservoir 2.1  Materials Silica sand obtained from Sigma-Aldrich with particle diameter raging from 150 to 630 μm, average size of 329 μm and deionized water were employed to form a sand bed to simulate the Alberta depleted natural gas reservoirs. CO2 obtained from Praxair has a purity of 99.5 %. 2.2 Injection of CO2 in a gas cap under batch, series-batch and constant pressure mode 2.2.1 Experimental setup and methods Figure 2.1 shows the schematic of the apparatus. The crystallizer (CR) has an inner diameter of 10.16 cm and inner height of 15.24 cm. The inside volume of crystallizer is calculated as 1236 cm3. The crystallizer was immersed in a water bath the temperature of which was adjusted by an external chiller (VWR Scientific, model 1187). A pressure transmitter obtained from Rosemount Inc. was employed to measure pressure in crystallizer with a maximum uncertainty of 0.075 % of the span 0 to 15000 kPa. Four thermocouples obtained from Omega Engineering Inc. were used to measure the crystallizer inner temperature in different positions inside the crystallizer. The uncertainty of thermocouples is 0.1 K. The crystallizer pressure was regulated by a PID controller and a control valve obtained from Fisher Bauman. A DAQ (data acquisition system) and the LabView 8.0 software obtained from National Instrument Inc. were used to send order to the control valve and collect the pressure and temperature data. 16   Figure 2.1 CO2 injection experimental setup for experiments (a) to (f). The injection of CO2 from the top of the silica sand bed will be called gas cap CO2 injection. This configuration may not necessarily correspond to an actual reservoir injection and it is used for convenience in this work. Nevertheless, the configuration allows observation of essential 17  features of the process of hydrate formation at the lab scale87. Figure 2.2 shows the schematic of injection of CO2 in a gas cap. Before starting a gas injection experiment, the sand bed was prepared. The amount of silica sand was placed in the crystallizer is 1650 g. The volume of water required to fill the void space of sand to make water saturation of 0.25 is found to be 90 mL. Silica sand and water were alternately and equably placed into crystallizer. In this case, silica sand and water consisted a sand bed to fill the inside volume of the crystallizer but left a 81 cm3 gas phase area (gas cap) above sand bed and a 270 cm3 gas phase area among the sand bed due to 0.75 gas saturation. The aspects ratio of the sand bed is 1.00 (W/H). The total volume of gas phase is 351 cm3. A thermocouple was set to measure the temperature of gas cap and another three were placed into the sand bed to measure the temperatures of top, middle and bottom position of the sand bed.   Figure 2.2 Schematic of injection of CO2 into a gas cap. After setting up the sand bed and placing the thermocouples, the crystallizer was closed and placed into a temperature controlled water bath at 274.15 K. When the crystallizer temperatures 18  indicated a temperature of 274.15 K the crystallizer was pressurized with CO2 to 1500 kPa and depressurized to atmospheric pressure for three times to eliminate the presence of air in the crystallizer. Then the CO2 gas was injected into the crystallizer from the CO2 cylinder or a supply vessel (SV) which was immersed in the same water bath as the CR. The amount of CO2 in the hydrate phase, percent of initial water converted to hydrate, hydrate saturation and CO2 storage density were calculated to evaluate the CO2 storage capacity as hydrate formed in the sand bed. The CO2 injections were conducted and the metrics were calculated as the following three modes of operation: (a) Batch gas injection: The crystallizer was pressurized with CO2 to 3200 kPa and without any further injection of gas. The pressure dropped due to hydrate formation and the experiment was stopped after 24 h.  The total number of moles of CO2 consumed to form hydrate in the process at any given time is the change in the number of moles of CO2 in gas phase in the crystallizer (𝑛𝐶𝑅−𝐶𝑂2,0 −𝑛𝐶𝑅−𝐶𝑂2,𝑡) and the number of moles of CO2 (𝑛𝐷,𝑡) dissolved in the water phase. 𝑛𝐶𝑂2,𝐻 = (𝑛𝐶𝑅−𝐶𝑂2,0 − 𝑛𝐶𝑅−𝐶𝑂2,𝑡) − 𝑛𝐷,𝑡                                                                                   (2.1) where 𝑛𝐶𝑂2,𝐻 is the number of moles of CO2 in the hydrate form. The number of moles in the hydrate phase at the start of experiments is 0. Hence, the number of moles of CO2 stored in the hydrate at a given time t is 𝑛𝐶𝑂2,𝐻 = 𝑛𝐶𝑅,0 − 𝑛𝐶𝑅,𝑡 − 𝑛𝐷,𝑡 = (𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,0− (𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,𝑡− 𝑛𝐷,𝑡                                       (2.2) 19  where 𝑃𝐶𝑅 and T are the pressure and temperature in the crystallizer, 𝑉𝐶𝑅 is the volume of gas in the crystallizer, z is the compressibility factor calculated by Pitzer’s correlation88 and R is the gas constant. The mole fraction of CO2 dissolved in the water phase is 0.016 at 274.15 K, 1850 kPa based on an interpolation from experimental data89. The percentage of initial water converted to hydrate was calculated below  𝑅𝐶𝑂2,𝑊 =𝑛𝑊,𝐶𝑂2𝐻𝑛𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙=𝑛𝐶𝑂2,𝐻×6.17𝑛𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙× 100 %                                                                                  (2.3) where 𝑛𝑊,𝐶𝑂2𝐻  indicates the number of moles of water consumed to form hydrate, 𝑛𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙 indicates the number of moles of initial water. The mole ratio of CO2 and water is called hydration number. It has been shown that the CO2 occupied 95 to 100 % of the large cages and 60 to 80 % of the small cages90-94. In this work the hydration numbers were calculated using the CSMGem software49. The value for the hydration number of CO2 hydrate was used is 6.17.  The CO2 hydrate saturation indicates the concentration of CO2 hydrate in Hydrate-Water-Gas system, which can be calculated as follows 𝑆𝐶𝑂2,𝐻 = 𝑅𝐶𝑂2,𝑊 × 𝑆𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙 × 1.1                                                                                             (2.4) where 𝑆𝑊,𝑖𝑛𝑖𝑡𝑖𝑎𝑙 indicates the original water saturation in the sand bed. When water converts to hydrate the volume expands and it can be considered as 1.1 times larger than original water49. The mass of CO2 (kg) stored in the reservoir within the pore volume (kg/ m3) is given by the following equation 𝜌𝐶𝑅𝐶𝑂2 = 𝜌𝐶𝑅𝐶𝑂2,𝐻 + 𝜌𝐶𝑅𝐶𝑂2,𝐺 + 𝜌𝐶𝑅𝐶𝑂2,𝑊 =𝑊𝐶𝑂2,𝐻𝑉𝑝+𝑊𝐶𝑂2,𝐺𝑉𝑝+𝑊𝐶𝑂2,𝑊𝑉𝑝                                                 (2.5) 20  where 𝑊𝐶𝑂2,𝐻, 𝑊𝐶𝑂2,𝐺 and 𝑊𝐶𝑂2,𝑊 indicate the mass of CO2 stored in sand bed as hydrate and gas form and dissolved in water, 𝑉𝑝 indicates the pore volume in the sand bed. Note that 25 % of the pore volume was occupied by water and CO2 gas occupied the remaining space. On the other hand, because not all the initial water was converted to hydrate and the amount of CO2 dissolved into water was also considered. The CO2 storage density was calculated as the total of the three different forms. (b) Series-batch gas injection: The crystallizer was pressurized with CO2 to 3200 kPa. After 6 and 20 h of operation the crystallizer was again pressurized with CO2 to restore the pressure to 3200 kPa. The experiment was stopped after 24 h. Series-batch gas injection experiment can be considered as three batch gas injection experiments in series (0-6 h, 6-20 h, and 20-24 h). The total number of moles of CO2 consumed to form hydrate after 24 h experiment is the sum of CO2 uptake in these three time periods. 𝑛𝐶𝑂2,𝐻 = 𝑛𝐻,0−6 + 𝑛𝐻,6−20 + 𝑛𝐻,20−24                                                                                       (2.6) The mole fraction of CO2 dissolved in the water phase is approximately 0.016 at 274.15 K, 3180 kPa which is the temperature and pressure condition of crystallizer after 24 h. It is noted that the solubility of CO2 in water in the presence of hydrates decreases with decreasing temperature in the hydrate formation region and is not a strong function of pressure over the hydrate formation region89. The calculations of 𝑅𝐶𝑂2,𝑊, 𝑆𝐻 and 𝜌𝐶𝑅𝐶𝑂2 were the same as (a) Batch gas injection. (c) Constant pressure gas injection: The crystallizer was pressurized with CO2 to 3200 kPa then the pressure in the crystallizer was maintained constant at 3200 kPa by continuously injecting 21  CO2 with the help of the PID controller from the supply vessel. The experiment was stopped after 24 h. A constant crystallizer pressure was maintained by delivering CO2 from a supply vessel. The number of moles of CO2 consumed to form hydrate in the crystallizer (𝑛𝐶𝑂2,𝐻) is the change in the number of moles of CO2 in the supply vessel ( 𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡 ) which can be calculated by the supply vessel pressure change. The number of moles of CO2 (𝑛𝐷,𝑡) dissolved in the water phase in the crystallizer was also be taken into account.  𝑛𝐶𝑂2,𝐻 = 𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡 − 𝑛𝐷,𝑡 = (𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,0− (𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,𝑡− 𝑛𝐷,𝑡                          (2.7) where 𝑃𝑆𝑉 and T are the pressure and temperature in the supply vessel, 𝑉𝑆𝑉 is the volume of the supply vessel. The mole fraction of CO2 in water at 274.15 K and 3200 kPa is 0.01689. The calculations of 𝑅𝐶𝑂2,𝑊, 𝑆𝐶𝑂2,𝐻 and 𝜌𝐶𝑅𝐶𝑂2 were the same as (a) Batch gas injection. 2.2.2 Results and discussion Figure 2.3 shows the pressure profiles in the crystallizer corresponding to experiments (a1), (b1) and (c1) for the CO2 injection in a gas cap for 24 h. Due to the hydrate formation and gas dissolution the pressure in the crystallizer decreased. The amount of CO2 dissolved in water is small compared to that consumed to form hydrate. During the (a) Batch gas injection experiment, the pressure dropped quickly in the first 3 h and then moderately. A rapid pressure decrease can also be observed under the (b) Series-batch gas injection experiment during the first 3 h. After the crystallizer was pressurized again to 3200 kPa at the 6 h mark, the crystallizer pressure dropped quickly in 20 min and then exhibited a moderate decrease to about 3000 kPa. The 22  pressure decreased very moderately after pressurization at the 20 h mark which is likely due to the fact that there is less water available for hydrate formation. Under the case of (c) Constant pressure gas injection experiment, a constant crystallizer pressure was maintained at 3200 ± 3 kPa.   Figure 2.3 Pressure profiles in the crystallizer in gas cap mode CO2 injection experiments for 24 h. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments.  23   Figure 2.4 Temperature profiles in the crystallizer in gas cap mode CO2 injection experiments for 24 h. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments. 24  Figure 2.4 shows the temperature profiles in the crystallizer corresponding to experiments (a1), (b1) and (c1) for the CO2 injection in a gas cap for 24 h and Figure 2.5 shows the temperature profiles for the first 60 min. Hydrate crystal formation is an exothermic process and a corresponding temperature rise is seen to occur at the 1 to 5 min mark in all of the three experiments. This point marks the onset of hydrate crystal formation (nucleation). After that the crystallizer temperatures were back to the initial set temperature. In (b) Series-batch gas injection experiment, temperature rises were observed when crystallizer was pressurized at the 6 and 20 h mark indicating the hydrate crystal formation. 25   Figure 2.5 Temperature profiles in the crystallizer in gas cap mode CO2 injection experiments for the first 60 min. (a1) Batch gas injection, (b1) Series-batch gas injection, and (c1) Constant pressure gas injection experiments. 26  Figure 2.5 clearly shows the temperature changes corresponding to experiments (a1), (b1) and (c1) when hydrate started to form. In all the three experiments, the temperatures of top and middle positions of the crystallizer are higher than the temperature of bottom position during the 5 to 60 min mark. This indicates that more hydrate formed in the top and middle area of sand bed than the bottom area in the crystallizer. The crystallizer was sitting on a rubber pad in the water bath and the thermal conductivity of rubber is less than water. Thus when the heat generated from the hydrate formation in the crystallizer transferred to the water bath higher temperature changes were observed at the bottom area of the crystallizer. In (a) Batch gas injection experiment and (b) Series-batch gas injection experiment, the temperatures in all positions decreased just after the first temperature rise. However, in (c) Constant pressure gas injection experiment, the temperatures of top and middle positions kept at 281 K for 15 min and 10 min respectively. This shows that more hydrate formed. Table 2.1 shows the number of moles of CO2 in the CO2 hydrate phase, percentage of water converted to hydrate, CO2 hydrate saturation and CO2 storage density of the three gas cap mode CO2 injection experiments. Results indicate that under the (c) Constant pressure gas injection mode more CO2 is stored compared to the other two injection modes. It was observed that 42 %, 44 % and 51 % of the original water converted to hydrate in (a) Batch, (b) Series-batch and (c) Constant pressure gas injection experiments, respectively. After 24 h, CO2 hydrate saturation results 0.11 to 0.14. The rest in the pore space of the sand bed can be considered to be unconverted water and gaseous CO2. Based on the above data the gas cap injection is able to achieve conversion of only half of the water available. The CO2 storage density as hydrate form was 40 to 50 kg/m3.  27  Table 2.1 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for gas cap mode CO2 injection experiments. Injection mode Exp. 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (a) Batch gas injection a1 0.342 42.2 0.12 41.8 2 a2 0.335 41.3 0.11 40.9 4 a3 0.337 41.6 0.12 41.2 2 (b) Series-batch gas injection b1 0.355 43.8 0.12 43.3 2 b2 0.360 44.4 0.13 44.0 2 b3 0.368 45.5 0.13 45.0 5 (c) Constant pressure gas injection c1 0.415 51.2 0.14 50.7 3 c2 0.414 51.1 0.14 50.6 2 c3 0.410 50.6 0.14 50.1 2    28  2.3 Injection of CO2 using spiral tubing under constant pressure mode 2.3.1 Experimental setup and methods An alternative injection mode was also followed by using a stainless steel spiral tubing. Figure 2.6 (A) shows the injection of CO2 using the spiral tubing. The initial temperature was set at 277.15 K in the spiral tubing mode CO2 injection experiments to reflect the fact that this is a more likely reservoir temperature. It is noted that only Constant pressure gas injection was conducted and the metrics are the same as in the gas cap mode Constant pressure gas injection experiments. The mole fraction of CO2 dissolved in the water phase is 0.019 at 277.15 K, 3200 kPa according to interpolation from experimental data89. Figure 2.6 (B) shows a picture of the spiral tubing. Each tubing has 15 holes with the diameter of 0.5 mm that opened in the same direction perpendicular to the spiral plane on the 1/8’’ stainless steel tubing in order to inject CO2 into the crystallizer. Silica sand and water placed in the crystallizer were 1800 g and 98 ml to obtain a 0.25 initial water saturation sand bed in this mode. In this case, silica sand and water (sand bed) filled the inside volume of the crystallizer but left a 8 cm3 gas phase area (gas cap) above the sand bed and a 292 cm3 gas phase area in the silica sand. Thus the total volume of the gas phase is 300 cm3. The aspects ratio of the sand bed is 0.74 (W/H). The CO2 injection was conducted by the following three methods: (d) Single top spiral tubing gas injection: A spiral tubing was placed above the sand bed in the crystallizer. Holes were open facing down to inject CO2 gas. (e) Single bottom spiral tubing gas injection: A spiral tubing was placed at the bottom of the sand bed in the crystallizer. Holes were open facing up to inject CO2 gas. 29  (f) Double spiral tubing (Top + Bottom) gas injection: Two spiral tubing were placed at the top and bottom of the sand bed in the crystallizer. Holes were opening up and down respectively to inject CO2 gas.  Figure 2.6 Schematic of injection of CO2 using spiral tubing (A) and the spiral tubing (B). 2.3.2 Results and discussion The pressure was kept constant at 3200 kPa in this case so the pressure profile is similar to that of the Constant pressure gas injection experiment in Figure 2.3. Figure 2.7 shows the temperature profiles in the crystallizer corresponding to experiments (d1), (e1) and (f1) in spiral tubing mode CO2 injection experiments and Figure 2.8 shows the temperature profiles during the first 120 min. 4 K temperature rises appeared at the Top, Middle and Bottom positions at the 10 to 20 min mark.  30   Figure 2.7 Temperature profiles in the crystallizer in spiral tubing mode CO2 injection experiments for 24 h. (d1) Single spiral tubing gas injection (Top), (e1) Single spiral tubing gas injection (Bottom), and (f1) Double spiral tubing gas injection (Top + Bottom) experiments. 31   Figure 2.8 Temperature profiles in the crystallizer in spiral tubing mode CO2 injection experiments for the first 60 min. (d1) Single spiral tubing gas injection (Top), (e1) Single spiral tubing gas injection (Bottom), and (f1) Double spiral tubing gas injection (Top + Bottom) experiments. 32  Figure 2.8 clearly shows the temperature changes when hydrate started to form. In experiment (d1), the temperature at Bottom position decreased just after the first temperature rise and temperatures of Top and Middle position kept at 280.5 K for 30 mins then started to decrease. The reason that the temperature profiles show flat top is considered the temperatures in the crystallizer reached the CO2 hydrate phase boundary (280.7 K, 3200 kPa)49. Thus no more temperature rises were observed. In experiment (e1), the temperatures kept 280 K to 280.5 K for 10 min in Middle and Bottom position and 40 min in Top position. In experiment (f1), the temperature of Bottom position decreased just after the first temperature rise and temperatures of Top and Middle position kept at 281 K for 30 and 10 min respectively then started to decrease. Temperature remained approximately 7 K higher than the initial crystallizer temperature in the Top position for a longer period than in the Middle and Bottom positions. It indicates that more hydrate formed in the top area of sand bed than in the other area. All of the temperatures of Top, Middle and Bottom positions of sand bed fell back to near 277 K at 120 min and no temperature jump was observed until the end of experiments.  Table 2.2 shows the number of moles of CO2 in the CO2 hydrate phase, percentage of water converted to hydrate, CO2 hydrate saturation and CO2 storage density of the three spiral tubing mode CO2 injection experiments. The (f) Double spiral tubing gas injection experiment results in more CO2 consumed to form hydrate. For all three experiments the percent of water converted to hydrate exceed 50 %. After 24 h, CO2 hydrate saturation results in 0.15 to 0.16 and hydrate form CO2 storage density was 50 to 60 kg/m3. Results indicate that more CO2 was stored in the spiral tubing mode CO2 injection as compared to the gas cap mode CO2 injection, which points to an opportunity to improve the hydrate conversion by proper design of the injection method.  33  Table 2.2 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for spiral tubing mode CO2 injection experiments. Injection mode Exp. 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (d) Single top spiral tubing gas injection d1 0.483 54.7 0.15 54.2 9 d2 0.486 55.1 0.15 54.6 16 d3 0.486 55.1 0.15 54.6 11 (e) Single bottom spiral tubing gas injection e1 0.481 54.5 0.15 54.0 18 e2 0.479 54.3 0.15 53.8 12 e3 0.478 54.2 0.15 53.7 10 (f) Double spiral tubing gas injection f1 0.525 59.5 0.16 58.9 10 f2 0.522 59.2 0.16 58.6 9 f3 0.523 59.3 0.16 58.7 12   34  2.4 Injection of CO2 using vertical tubing under constant pressure mode and constant flow rate followed by constant pressure mode 2.4.1 Experimental setup and methods Figure 2.9 shows the apparatus of CO2 injection under constant pressure and constant flow rate followed by constant pressure mode. Figure 2.10 (A) shows the injection of CO2 using vertical tubing and Figure 2.10 (B) shows a picture of the vertical tubing. The tubing has four 1.0 mm diameter holes in each one of 5 positions located at a distance of 2.5 cm from each other. The end of the vertical tubing was sealed. The sand bed was prepared by placing 10 layers of 180 g of silica sand and 40 mL of deionized water in the crystallizer and finally placing 36 g of silica sand on top. Thus, the reservoir consists of 1836 g of silica sand and 400 mL of water. In this way the silica sand was fully water saturated in the crystallizer (water saturation = 1.00). Subsequently, compressed air was injected into the crystallizer to drain the water out of the sand bed. This operation was conducted until no water came out from the crystallizer. About 60 hours were required to complete this sand bed preparation. The volume of the drained water was found to be 312 mL and thus, the water that remained in the reservoir was 88 mL. The water saturation in the reservoir was therefore found to be 0.22 and the rest of the pore space was occupied by air. The aspects ratio of the sand bed is 0.67 (W/H). The vertical tubing was located in the center of the sand bed to deliver CO2 gas into the simulated reservoir.  35   Figure 2.9 CO2 injection setup for the experiments under constant pressure and constant flow rate followed by constant pressure mode gas injection method. 36   Figure 2.10 Schematic of injection of CO2 using vertical tubing (A) and the picture of vertical tubing (B). CO2 injection under (g) Vertical tubing constant pressure gas injection and (h) Vertical tubing constant flow rate followed by constant pressure gas injection into the simulated reservoir were conducted.  The experiment of (g) Vertical tubing constant pressure gas injection was run three times for 24 h. The CO2 injection method and the metrics calculation were the same as (c) Constant pressure gas injection in a gas cap. In the experiment (h) Vertical tubing constant flow rate followed by constant pressure gas injection, a Quizix Q5000 pump shown in Figure 2.9 was employed to provide a 5 mL/min constant flow rate gas delivery from the supply vessel to the reservoir. When the crystallizer pressure increased to 3200 kPa the gas injection was switched to the constant pressure mode until 24 h of the operation. This experiment was also run three times and an additional experiment was run for 120 h. Because a constant crystallizer pressure was 37  maintained through the continuous supply of CO2 from the supply vessel, the number of moles of CO2 uptake to form hydrate in the crystallizer (𝑛𝐶𝑂2,𝐻) is given by the following formula 𝑛𝐶𝑂2,𝐻 = (𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡) − (𝑛𝐶𝑅−𝐶𝑂2,𝑡 − 𝑛𝐶𝑅−𝐶𝑂2,0) − 𝑛𝐷,𝑡           = [(𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,0− (𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,𝑡] − [(𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,𝑡− (𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,0] − 𝑛𝐷,𝑡                    (2.8) where, the change in the number of moles of CO2 in the supply vessel is 𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡, the change in the number of moles of CO2 in the crystallizer is 𝑛𝐶𝑅−𝐶𝑂2,𝑡 − 𝑛𝐶𝑅−𝐶𝑂2,0, 𝑃𝑆𝑉 and 𝑃𝐶𝑅 indicate the pressure of the supply vessel and the crystallizer, T indicates the temperature, 𝑉𝑆𝑉  and 𝑉𝐶𝑅 indicate the volume of the supply vessel and the crystallizer.  The other metrics calculations were the same as (c) Constant pressure gas injection in a gas cap. 2.4.2 Results and discussion Figure 2.11 shows the temperature profiles when CO2 was injected into the crystallizer. These correspond to experiment (g1). The reservoir pressure was maintained at 3200 kPa by continuously supplying CO2 gas delivered from the supply vessel. The temperature profiles for the other two experiments were similar with the induction times varying as seen in Table 2.3. A temperature rise of 3.5 K was seen to occur at around the 12 min at three different positions in the reservoir. This is an indication of hydrate crystal formation owing to the exothermic nature of the process. While the three temperature peaks are the same the decaying profiles are different suggested different amounts of hydrate crystals formed. More hydrate crystals formed at the top of the reservoir. As seen from the data in Table 2.3, 0.467 mol of CO2 was stored in hydrate form and 58.9 % of the original water converted to hydrate after 24 h. Unconverted water and gas phase CO2 were considered to fill the rest of the pore space in the sand bed. 38   Figure 2.11 Temperature profiles in the reservoir corresponding to experiment (g1) for injection of CO2 under constant pressure (3200 kPa) into the crystallizer for 24 h and the first 120 min.  39  The pressure and temperature profiles in the reservoir corresponding to experiment (h4) for the injection of CO2 under constant flow rate followed by constant pressure into pure water reservoir for 24 h, the first 360 min and 120 h are seen in Figure 2.12. The reservoir pressure increased gradually until 2500 kPa under a constant flow rate of 5 mL/min CO2 gas injection. Rapid temperature rises and pressure drop were observed due to the hydrate formation. It is noted that the pressure drop at about 74 min was due to higher rate of CO2 gas consumption to form hydrate as compared to the rate of CO2 injection. The temperature rise was about 1.5 K higher than the initial point. The pressure reached the target value of 3200 kPa at about 6 h and remained constant during the 24 h and 120 h experiments. The temperature remained at about 277 K during this period. After 24 h and 120 h of CO2 injection 0.684 and 0.738 mol of CO2 were stored in hydrate form respectively. It was also found that 86.3 % and 93.1 % of the original water was converted to hydrate with a CO2 hydrate saturation values of 0.209 and 0.225, respectively. This indicates that almost all of the original water in the reservoir formed CO2 hydrate after 120 h. Thus, under the same temperature and initial water saturation conditions the amount of CO2 stored gas under constant flow rate followed by constant pressure injection increased by about 50 % compared to constant pressure injection. It may be the case that at constant pressure gas injection more hydrate formed within a small period of time at the beginning (higher temperature rise) and hindered the gas transfer to the reservoir thus significantly reducing hydrate formation in the reservoir. 40   Figure 2.12 Pressure and temperature profiles in the reservoir corresponding to experiment (h4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the crystallizer for 24 h, the first 360 min and 120 h. 41  Table 2.3 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for vertical tubing mode CO2 injection experiments. Injection mode Exp. Duration (h) 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (g) Vertical tubing constant pressure gas injection g1 24 0.467 58.9 0.14 51.4 12 g2 24 0.467 58.9 0.14 51.4 12 g3 24 0.466 58.8 0.14 51.3 10 (h) Vertical tubing constant flow rate followed by constant pressure gas injection h1 24 0.684 86.3 0.21 75.2 74 h2 24 0.707 89.2 0.22 77.8 70 h3 24 0.709 89.5 0.22 78.0 77 h4 120 0.738 93.1 0.23 81.2 74  2.5 Summary In this lab study the injection of CO2 into a partially water saturated sand bed was studied at conditions where hydrate formation is thermodynamically possible as seen in Figure 2.13 and the hydrate formation was observed. This demonstrates that CO2 can be stored as hydrate when the gas is injected into a porous formation simulating a depleted natural gas reservoir. Multiple 42  positions gas injection resulted in more CO2 gas uptake than the gas cap injection mode. It was also noted that injected CO2 under a constant flow rate into the reservoir at the beginning promoted the hydrate formation and provided more CO2 storage. It may be the case that at constant pressure gas injection more hydrate formed within a small period of time at the beginning (higher temperature rise) and hindered the gas transfer to the reservoir thus reducing hydrate formation.  Figure 2.13 CO2 partial phase diagram with Alberta depleted natural gas reservoirs P-T condition region.    43  3 Injection of CO2 into Reservoirs Containing PVP, Tapioca Starch and Saline Solution  Since the injection of CO2 using vertical tubing under constant flow rate followed by constant pressure into a partially water saturated reservoir resulted in enhanced hydrate formation and corresponding CO2 storage, this gas injection mode was used for the assessment of the CO2 storage as hydrate in further experimental studies. In this chapter we explore the use of additives to further enhance hydrate formation and thus CO2 storage. In addition, the fact that natural reservoirs have saline waters taken into account to determine the potential impact on CO2 storage density. 3.1 Materials and methods The CO2 gas was obtained from Praxair and had 99.5 % purity. Sodium Chloride (NaCl, Fisher Scientific), Polyvinylpyrrolidone (PVP, average molecular mass of 3.5 kDa, Acros Organics) and tapioca starch (average molecular mass of 3 mDa, National Starch ULC) were used. Silica sand was obtained from Sigma-Aldrich with the average diameter of 329 μm and porosity of 0.35. Different with (h) Vertical tubing constant flow rate followed by constant pressure gas injection experiments the water contained (i) 1 wt %, (j) 3 wt % of PVP, (k) 0.5 wt %, (l) 1 wt % and (m) 3 wt % of tapioca starch, (n) 2 wt % and (o) 4 wt % NaCl were used to prepare the sand bed. The CO2 gas injection method was the same as experiments (h). PVP and NaCl solutions were directly made of the mixture of PVP and NaCl chemicals with deionized water, however the tapioca starch solution was prepared according to a method described elsewhere95. Briefly the tapioca starch powder was mixed with water in a beaker to prepare a starch solution at 95 °C. 44  The starch solution was cooled down to the room temperature before using it for injection in the reservoir. The CO2 injection operation and the metrics calculation were the same as described in experiments (h). Each experiment was run three times for 24 h and once for 120 h. In the absence of any literature data for the hydration number of CO2 hydrate formed in 1 wt %, 3 wt % of PVP and 0.5 wt %, 1 wt % and 3 wt % of tapioca starch solutions the value for CO2 hydrate formed in pure water of 6.17 was used. The values for the hydration number for CO2 hydrate formed in 2 wt % and 4 wt % NaCl solutions were determined by CSMGem as 6.14 and 6.11 respectively49. 3.2 Injection of CO2 into a reservoir containing 1 and 3 wt % of PVP Figure 3.1 shows the pressure and temperature profiles in the reservoir corresponding to experiment (i4) for the injection of CO2 under constant flow rate followed by constant pressure into a reservoir containing 1 wt % PVP solution for 24 h, the first 360 min and 120 h. It is noted that 1 to 2 K temperature rises were observed in this case and compared to the pure water case the onset of hydrate nucleation was prolonged from 74 min to 118 min as expected. As seen in Table 3.1, the amount of CO2 stored as hydrate was 0.642 mol and 81.0 % of the original water formed CO2 hydrate after 24 h. It is also noted that after 120 h, 0.720 mol of CO2 was stored in hydrate form and 90.9 % of water was converted to hydrate. Thus, the addition of 1 wt % of PVP in the reservoir reduced the hydrate formation and CO2 storage in both 24 h and 120 h experiments. While the delay in the onset of nucleation is expected when additives like PVP are included in the water the fact that the hydrate conversion did not improve is contrary to our expectation based on observations of accelerated hydrate growth in static systems64. 45   Figure 3.1 Pressure and temperature profiles in the reservoir corresponding to experiment (i4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 1 wt % PVP aqueous solution for 24 h, the first 360 min and 120 h. 46  Table 3.1 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for the experiments of CO2 injection into a reservoir containing 1 and 3 wt % PVP. Injection mode Exp. Duration (h) 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (i) Constant flow rate followed by constant pressure gas injection into a reservoir containing 1 wt % PVP i1 24 0.642 81.0 0.196 70.6 118 i2 24 0.627 79.1 0.191 69.0 109 i3 24 0.635 80.1 0.194 69.9 121 i4 120 0.720 90.9 0.220 79.2 118 (j) Constant flow rate followed by constant pressure gas injection into a reservoir containing 3 wt % PVP j1 24 0.542 68.4 0.166 59.6 142 j2 24 0.538 67.9 0.164 59.2 125 j3 24 0.532 67.1 0.162 58.5 148 j4 120 0.786 99.2 0.240 86.5 142  Figure 3.2 shows the pressure and temperature profiles in the reservoir corresponding to experiment (j4) for the injection of CO2 under constant flow rate followed by constant pressure into a reservoir containing 3 wt % PVP solution for 24 h, the first 360 min and 120 h. It is noted that 1 to 1.5 K temperature rises were observed when pressure increased to 3200 kPa at 142 min 47  which is later than the pure water and the case with 1 wt % of PVP. Thus, the onset of hydrate formation is prolonged as expected. The pressure was maintained at 3200 kPa after 2.5 h and 0.542 and 0.786 mol of CO2 stored in hydrate form after 24 and 120 h. The amount of water that was converted to hydrate was 68.4 % and 99.2 % after 24 h and 120 h, respectively. The corresponding CO2 hydrate saturation was 0.166 and 0.240 respectively. The addition of 3 wt % of PVP in the reservoir delayed the onset of hydrate nucleation and reduced the amount of hydrate formed in the early stage but accelerated the crystal growth and almost all of the water formed hydrate after 120 h. Accelerated hydrate growth in the presence of PVP is consistent with recent findings64. From a practical standpoint the delay in nucleation is welcome to avoid possible hydrate blockage in the injection system. The increase in hydrate formation is also beneficial since it increases the CO2 storage density of the reservoir.       48   Figure 3.2 Pressure and temperature profiles in the reservoir corresponding to experiment (j4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 3 wt % PVP aqueous solution for 24 h, the first 360 min and 120 h. 49  3.3 Injection of CO2 into a reservoir containing 0.5, 1 and 3 wt % of tapioca starch Figure 3.3, 3.4 and 3.5 shows the pressure and temperature profiles in the reservoir corresponding to experiment (k4), (l4) and (m4) for the injection of CO2 under constant flow followed by constant pressure rate into reservoirs containing 0.5 wt %, 1 wt % and 3 wt % tapioca starch for 24 h, the first 360 min and 120 h. It is noted that 1 to 2 K temperature rises were observed in (k4) and (l4) at 70 to 80 min and 1.5 to 3 K temperature rises were observed in (m4) at 110 min. The increase of the concentration of tapioca starch delayed the onset of hydrate nucleation as expected but the growth showed interesting behaviour. As the starch concentration increases the period during which the temperature decays to its starting value after reaching its peak decreases. Also noted is a second temperature rise of 0.5 to 1 K, which was observed in experiment (l4) at about 195 min and is seen in Figure 3.4. This is the thermal signature of another intensive hydrate formation period. As seen in Table 3.2, the numbers of moles of CO2 stored in hydrate were 0.715, 0.681 and 0.631 after 24 h in experiments (k4), (l4) and (m4) respectively. The amount of stored CO2 increased to 0.747, 0.772 and 0.688 mol after 120 hours. It is then interesting that increasing tapioca starch does not have the same benefit as adding PVP i.e. to increase CO2 storage.     50   Figure 3.3 Pressure and temperature profiles in the reservoir corresponding to experiment (k4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 0.5 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h. 51   Figure 3.4 Pressure and temperature profiles in the reservoir corresponding to experiment (l4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 1 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h. 52   Figure 3.5 Pressure and temperature profiles in the reservoir corresponding to experiment (m4) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 3 wt % tapioca starch aqueous solution for 24 h, the first 360 min and 120 h. 53  Table 3.2 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for the experiments of CO2 injection into a reservoir containing 0.5, 1 and 3 wt % tapioca starch. Injection mode Exp. Duration (h) 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (k) Constant flow rate followed by constant pressure gas injection into a reservoir containing 0.5 wt % tapioca starch k1 24 0.715 90.2 0.218 78.7 76 k2 24 0.718 90.6 0.219 79.0 77 k3 24 0.720 90.9 0.220 79.2 119 k4 120 0.747 94.3 0.228 82.2 76 (l) Constant flow rate followed by constant pressure gas injection into a reservoir containing 1 wt % tapioca starch l1 24 0.681 85.9 0.208 74.9 74 l2 24 0.674 85.1 0.206 74.1 95 l3 24 0.684 86.3 0.209 75.2 92 l4 120 0.772 97.4 0.236 84.9 74 (m) Constant flow rate followed by constant pressure gas injection into a reservoir containing 3 wt % tapioca starch m1 24 0.631 79.6 0.193 69.4 110 m2 24 0.620 78.2 0.189 68.2 96 m3 24 0.622 78.5 0.190 68.4 105 m4 120 0.688 86.8 0.210 75.7 110  54  3.4 Injection of CO2 into a reservoir containing 2 and 4 wt % NaCl solution Figure 3.6 shows the pressure and temperature profiles in the reservoir corresponding to experiment (n1) for the injection of CO2 under constant flow rate followed by constant pressure into a reservoir containing 2 wt % NaCl solution for 24 h and the first 360 min. It is noted that 2 to 2.5 K temperature rises were observed at 121 min. Unlike the above mentioned cases the reservoir temperature in this case started to decrease just after the peaks. When hydrates form the electrolyte is excluded from the hydrate crystal. Since the amount of water decreases the electrolyte concentration increases and this causes the equilibrium hydrate formation pressure to increase. Consequently, the driving force for hydrate growth decreases under the isothermal conditions of the experiment. As seen in Table 3.3, 0.587 mol of CO2 stored in hydrate form and 73.7 % of initial water converted to hydrate. The hydrate saturation was 0.178 after 24 h.  55   Figure 3.6 Pressure and temperature profiles in the reservoir corresponding to experiment (n1) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 2 wt % NaCl solution for 24 h and for the first 360 min.     56  Table 3.3 The number of moles of CO2 stored in hydrate (𝒏𝑪𝑶𝟐,𝑯), the percent of water formed hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), the CO2 storage density as the form of hydrate (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯) and the induction time for the experiments of CO2 injection into a reservoir containing 2 and 4 wt % NaCl solutions. Injection mode Exp. Duration (h) 𝒏𝑪𝑶𝟐,𝑯  (mol) 𝑹𝑪𝑶𝟐,𝑾  (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯  (kg/m3) Induction time (min) (n) Constant flow rate followed by constant pressure gas injection into a reservoir containing 2 wt % NaCl solution n1 24 0.587 73.7 0.178 64.6 121 n2 24 0.574 72.1 0.174 63.1 124 n3 24 0.583 73.2 0.177 64.1 113 (o) Constant flow rate followed by constant pressure gas injection into a reservoir containing 4 wt % NaCl solution o1 24 0.451 56.4 0.136 49.6 99 o2 24 0.447 55.9 0.135 49.2 132 o3 24 0.450 56.2 0.136 49.5 102  Figure 3.7 shows the pressure and temperature profiles in the reservoir corresponding to experiment (o1) for the injection of CO2 under constant flow rate followed by constant pressure into a reservoir containing 4 wt % NaCl solution for 24 h and the first 360 min. It is noted that 1 to 1.5 K temperature rises were observed at 99 min. It is lower than the temperature rises in 2 wt % saline contained reservoir case. The pressure reached 3200 kPa at 3.2 h then remained constant. 57  It is also noted that 0.451 mol of CO2 stored in hydrate form and 56.4 % of initial water converted to hydrate. Hydrate saturation reached 0.136 after 24 h. These observations are consistent with the fact that increased salinity increases the equilibrium hydrate formation pressure and thus decreases the driving force for hydrate growth.  Figure 3.7 Pressure and temperature profiles in the reservoir corresponding to experiment (o1) for the injection of CO2 under constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) into the reservoir containing 4 wt % NaCl solution for 24 h and for the first 360 min.  58  3.5 Summary In order to improve the CO2 storage density in the reservoir as gas hydrate a small amount of PVP and tapioca starch were added in the sand bed. Figure 3.8 shows the number of moles of CO2 stored in hydrate form in the reservoirs containing pure water, 3 wt % PVP and 1 wt % tapioca starch solutions in 120 h. The number of moles of CO2 stored in 3 wt % of PVP and 1 wt % of tapioca starch contained reservoirs exceeded the one stored in pure water containing reservoir at 80 and 26 h, respectively. After 120 h the increase of the number of moles of CO2 stored as hydrate in the reservoirs almost stopped due to decreasing amount of potential water for the CO2 hydrate formation. Reservoirs with higher water saturation will have more capacity to store CO2. The addition of PVP and tapioca starch solution in the reservoir played a role as hydrate inhibitors at the early stage of the experiments. It can be considered a positive factor for the CO2 gas injection into the depleted reservoirs due to a decreased risk to plug the injection system arising from the formation of the hydrate.  59   Figure 3.8 The number of moles of CO2 stored in hydrate in deionized water (h4), 3 wt % PVP (j4) and 1 wt % tapioca starch (l4) reservoirs in 120 h experiments. Figure 3.9 shows how the salinity shifts the hydrate formation equilibrium to a higher pressure (at constant temperature) or lower temperature (at constant pressure). The equilibria are calculated using a CSMGem software. During hydrate formation the salinity increases and in the experiments with 2 and 4 wt % salinity the water was consumed to form hydrate and the resulting salinity was 7.4 and 9.1 wt % (average of the three experiments in each case), respectively. The equilibrium curves for these salinities are also shown. Thus, it is easy to see how the driving force expressed as P-Peq changes during hydrate formation due to the change in the salinity from 2 to 7.4 or 4 to 9.1 wt %, respectively. There is 1218 kPa pressure driving force 60  for the CO2 to form hydrate in the pure water reservoir ever after 24 h. However, the driving force in the 2 wt % saline contained reservoir reduced to 196 kPa after 24 h. Thus reduction in the value of the driving force causes the decrease in the hydrate growth. In the case of the 4 wt % saline containing reservoir, the salinity increases and approaches a point where the equilibrium pressure approaches the experimental value of 3200 kPa. This means that hydrate growth ceases when the driving force approaches zero and the salinity does not increase any further.  Figure 3.9 CO2 hydrate phase diagram in pure water, 2, 4, 7.4 and 9.1 wt % saline solutions. ΔP0 = 1218 kPa, ΔP2 = 1013 kPa, ΔP4 = 768 kPa, ΔP7.4 = 196 kPa and ΔP9.1 = -211 kPa.   61  4 Injection of CO2 and CO2/N2 into CH4 Rich and CH4 Free Reservoirs  In order to advance further our understanding of the parameters affecting CO2 storage we need to take into account the fact that CO2 gas captured from large stationary sources are mixed with impurities like N2 and O2. In order to render the CO2 capture (separation) process economically viable the CO2 concentration in the treated flue gas is about 90 mol %. Another practical consideration is the fact that depleted gas reservoirs still contain residual gas at a pressure of about 500 kPa. Because natural gas forms gas hydrate as well it is important that this is taken into account in any consideration for the injection of CO2 into depleted gas reservoirs. 4.1 Materials The material to create the porous medium was the same silica sand (SiO2) used in previous experiments. CO2, CH4 and N2 gas were obtained from Praxair and the purities were 99.5, 99.97 and 99.999 %, respectively. Tapioca starch (average molecular mass of 3 mDa, National Starch ULC) was also used as a hydrate kinetic additive. The gas injection apparatus was the same as Figure 2.9 and the vertical tubing shown in Figure 2.10 was applied. The list of experiments is given in Table 4.1. The CO2/N2 (90/10 mol %) gas mixture was injected at constant flow rate followed by constant pressure injection at 277 K. In addition, three experiments were conducted with CO2 gas. The reservoir conditions at the beginning of the injection (residual gas and water phase) are also shown in Table 4.1 along with the duration of the experiment and the relevant results. In all experiments 1836 g of silica sand and 88 mL of water were used in the reservoir and resulted in water saturation value of 0.22. 62  Table 4.1. The hydrate formation induction time, the number of moles of CO2 stored in hydrate form (𝒏𝑪𝑶𝟐,𝑯), the percentage of reservoir water formed CO2 hydrate (𝑹𝑪𝑶𝟐,𝑾), the CO2 hydrate saturation (𝑺𝑪𝑶𝟐,𝑯), CO2 storage density in hydrate form (𝝆𝑪𝑹𝑪𝑶𝟐,𝑯). All experiments at 277 K.  Exp. Injected gas or gas mixture Gas and solution in the reservoir (at the start of experiment) Induction time (min) Sampling point (h) 𝒏𝑪𝑶𝟐,𝑯 (mol) 𝑹𝑪𝑶𝟐,𝑾 (%) 𝑺𝑪𝑶𝟐,𝑯 𝝆𝑪𝑹𝑪𝑶𝟐,𝑯 (kg/m3) p1  CO2  500 kPa CH4 Deionized water 109 24 0.637 80.3 0.194 70.1 p2 97 24 0.632 79.6 0.193 69.5 p3 113 24 0.640 80.6 0.195 70.4 p1 109 120 0.672 84.7 0.205 73.9 p2 97 120 0.673 84.8 0.205 74.0 p3 113 120 0.677 85.3 0.206 74.5 q1 CO2/N2 (90/10 mol %)  Deionized water 154 24 0.620 78.1 0.189 68.2 q2 138 24 0.617 77.7 0.188 67.9 q3 262 24 0.622 78.4 0.190 68.4 q1 154 120 0.705 88.8 0.215 77.6 q2 138 120 0.700 88.2 0.213 77.0 q3 262 120 0.705 88.8 0.215 77.6 r1 CO2/N2 (90/10 mol %) 500 kPa CH4 Deionized water 216 24 0.576 72.5 0.175 63.4 r2 233 24 0.558 70.2 0.170 61.4 r3 220 24 0.566 71.2 0.172 62.3 r1 216 120 0.638 80.3 0.194 70.2 r2 233 120 0.664 83.5 0.202 73.0 r3 220 120 0.660 83.0 0.201 72.6 s1 CO2/N2 (90/10 mol %) 500 kPa CH4 1 wt % aqueous tapioca starch solution 337 24 0.557 70.1 0.170 61.3 s2 315 24 0.551 69.3 0.168 60.6 s3 331 24 0.546 68.7 0.166 60.1 s1 337 120 0.680 85.5 0.207 74.8 s2 315 120 0.677 85.2 0.206 74.5 s3 331 120 0.679 85.4 0.207 74.7 63  4.2 Injection of CO2 into a reservoir containing 500 kPa CH4 The CO2 was injected into the crystallizer from the supply vessel through the Quizix Q5000 pump under 5 cm3/min constant flow rate. When the reservoir pressure reached 3200 kPa the gas injection method was switched from constant flow rate to that at constant pressure of 3200 kPa through the use of a PID controller. Three experiments were conducted and each lasted 120 h. Gas samples in the crystallizer were taken every 24 hours by a 0.15 cm3 inner volume stainless steel gas sampling tubing and analyzed with a GC. Considering the crystallizer volume of 1236 cm3, the amount of the sampling gas was assumed that it did not affect the gas phase composition in the crystallizer. Before each analysis the column of the GC and the gas sampling tubing were purged with He gas for three times. The number of moles of CO2 stored in hydrate is given by the following formula 𝑛𝐶𝑂2,𝐻 = (𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡) − (𝑛𝐶𝑅−𝐶𝑂2,𝑡 − 𝑛𝐶𝑅−𝐶𝑂2,0) − 𝑛𝐷,𝑡     = [(𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,0− (𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,𝑡] − [(𝑦𝐶𝑂2,𝑡𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,𝑡− 0] − 𝑛𝐷,𝑡                               (4.1) In equation, 𝑦𝐶𝑂2,𝑡 indicates the mole fraction of CO2 gas in the crystallizer at time t determined by GC analysis. The other metrics calculations were the same as (c) Constant pressure gas injection in a gas cap. The hydration number of CO2/CH4 hydrate was considered to be 6.1649. 64   Figure 4.1 Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (p1) for 24 h, the first 360 min and 120 h. Figure 4.1 shows the pressure and temperature profiles in the reservoir for experiment (p1) during which the injection of CO2 into a reservoir containing 500 kPa CH4 for 120 h was 65  conducted. The profiles for the first 24 h and 360 min are also shown in the figure. CO2 gas was injected into the reservoir under 5 cm3/min and a rapid 3 K temperature rise was observed at 100 to 110 min which indicates hydrate crystal formation. The time elapsed from the beginning of gas injection into the reservoir to the onset of hydrate formation is called induction time. The reservoir pressure reached 3200 kPa at about 300 min and was maintained at that level for the rest of the experiment through the use of the PID controller. During the constant pressure phase of the experiment the temperature profile indicates slow hydrate formation. Figure 4.2 shows the calculated CO2/CH4 hydrate partial phase diagram using CSMGem software49. The presence of CH4 changes the hydrate equilibrium and shifts the CO2 hydrate phase boundary to a higher pressure at constant temperature. At the nucleation point (3100 kPa) the gas phase composition resulting from the injection of pure CO2 into the reservoir containing pure CH4 at 500 kPa is 84 mol % CO2. The equilibrium hydrate formation for this CO2/CH4 mixture is 2118 kPa (see Figure 4.2) and hence the pressure driving force to form hydrate is 3100-2118=982 kPa. This driving force is responsible for the hydrate formation and the corresponding temperature rise. The CO2/CH4 gas phase composition after 120 h is approximately 95/5 mol % CO2 (experiment p1). As seen in Figure 4.2 there is a small change in the minimum pressure required to form hydrates from the CO2/CH4 (95/5 mol %) gas mixture compared to having pure CO2 at a given temperature. In general, a shift in the phase boundary impacts the driving force for hydrate formation74. As seen in Figure 4.2 there exists a 1178 kPa pressure driving force to form hydrate in the reservoir at 277 K. This is because the crystallizer pressure is 3200 kPa and the equilibrium pressure for the CO2/CH4 (95/5 mol %) hydrate is 2022 kPa. Thus, there still exists a pressure driving force to form hydrates. However, as shown in Figure 4.1 the hydrate formation process almost stopped after 24 h as seen from the pressure and temperature profiles. 66  Considering that there still exists 15 % of water in place available to form hydrates (as discussed in the section below) the reason why hydrate formation reduces drastically is the fact that the hydrate crystals that already formed have created a barrier to the mass transfer of hydrate forming gas to the residual pore water. As seen in Table 4.1 0.636 mol of CO2 gas was stored in hydrate form (average of experiments p1, p2, and p3) and 80.2 % (average of experiments p1, p2 and p3) of the reservoir water formed CO2 hydrate in 24 h. After 120 hours 0.674 mol of CO2 formed hydrate with 84.9 % of the original water in place (average). The CO2 storage density in hydrate form reached the value of 74.1 kg/m3 (average) which is about 8 % less than the storage density in the experiment of CO2 injection into CH4 free reservoir reported in 2.4.2. Thus, the presence of CH4 in the reservoir reduced the amount of CO2 stored in hydrate mainly due to the fact that some cages are now filled with CH4 molecules. 67   Figure 4.2 CO2/CH4-H2O partial phase diagram. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/CH4 (84/16 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPp = 3100 kPa-2118 kPa = 982 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/CH4 (95/5 mol %) mixture at 277 K after 120 h, where driving force ΔPp = 3200 kPa-2022 kPa = 1178 kPa. 4.3 Injection of CO2/N2 (90/10 mol %) into a reservoir without CH4 In experiments (q) CO2/N2 (90/10 mol %) was injected to the reservoir following the same injection procedure in experiments (p). The number of moles of CO2 stored in hydrate in the reservoir is given by the next equation 68  𝑛𝐶𝑂2,𝐻 = (𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡) − (𝑛𝐶𝑅−𝐶𝑂2,𝑡 − 𝑛𝐶𝑅−𝐶𝑂2,0) − 𝑛𝐷,𝑡       = [(0.9𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,0− (0.9𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,𝑡] − [(𝑦𝐶𝑂2,𝑡𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,𝑡− (𝑦𝐶𝑂2,0𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,0] − 𝑛𝐷,𝑡       (4.2) Calculations of the percentage of water conversion, CO2 hydrate saturation and CO2 storage density ware the same as in the experiments (p). The hydration number of CO2/N2 hydrate formed was considered to be 6.1649. Figure 4.3 shows the pressure and temperature profiles in the reservoir for experiment (q1) during which a CO2/N2 (90/10 mol %) gas mixture was injected into a reservoir that did not contain any CH4. The CO2/N2 gas mixture was injected into the reservoir at 277 K and at the rate of 5 cm3/min (0.0072 m3/day).  Hydrate did not form until the reservoir pressure reached 3200 kPa. A 3.5 K rapid temperature rise was observed at about 160 min. This temperature rise is larger than the temperature rise of 1.5 K observed at about 74 min and the reservoir pressure of 2456 kPa in the experiments of CO2 injection into a reservoir without CH4 reported in 2.4.2, which shows less hydrate formed at lower pressure driving force (2456-1982=454 kPa) conditions. Thus the presence of N2 in the reservoir resulted in a higher pressure required to form hydrate and prolonged the onset of hydrate formation under the same method of CO2 gas injection into the reservoir. A delay in the onset of hydrate formation reduces the risk of hydrate plug formation in the injection system. The reservoir temperatures slowly decreased to 277 K after the peak and no significant temperature change appeared indicating a decreased rate of hydrate formation due to mass transfer limitations noted above. Figure 4.4 shows the calculated CO2/N2 hydrate partial phase diagram using CSMGem software47. The presence of N2 changes the hydrate equilibrium and shifts the CO2 hydrate phase boundary to a higher pressure at constant temperature. The CO2/N2 hydrate equilibrium shifted from CO2/N2 (90/10 mol %) to 69  that of a CO2/N2 (85/15 mol %) mixture after 120 h reflecting the gas phase composition change while hydrate was forming. The pressure driving force for experiment (q1) at the nucleation point is 981 kPa (3200 kPa-2219 kPa) because the equilibrium hydrate formation pressure of the CO2/N2 (90/10 mol %) mixture is 2219 kPa. The pressure driving force after 120 h is 841 kPa (3200 kPa-2359 kPa) because the equilibrium pressure of the CO2/N2 (85/15 mol %) mixture is 2359 kPa. There still exists a pressure driving force of about 841 kPa to form hydrate in the reservoir since the experimental pressure is 3200 kPa and there is still water in the reservoir (12 % of the original water in place). As seen in Table 1 the number of moles of CO2 stored in hydrate form after 24 h and 120 h was 0.620 (average for experiments q1, q2 and q3) and 0.703 (average), respectively. The CO2 storage density in hydrate form reached 77.3 kg/m3 after 120 h (average). This is more than the 74.1 kg/m3 (average for experiments p1, p2 and p3) and indicates that more hydrate formed in experiments with CO2/N2 injection in CH4-free reservoir compared to CO2 injection in a CH4 reservoir. 70   Figure 4.3 Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (q1) for 24 h, the first 360 min and 120 h.  71   Figure 4.4 CO2/N2-H2O partial phase diagrams. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/N2 (90/10 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPq = 3200 kPa-2219 kPa = 981 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/N2 (85/15 mol %) mixture at 277 K after 120 h, where ΔPq = 3200 kPa-2359 kPa = 841 kPa. 4.4 Injection of CO2/N2 (90/10 mol %) into a reservoir containing 500 kPa CH4 The injection procedure in experiments (r) is the same as in experiments (q) but it is noted that (𝑛𝐶𝑅−𝐶𝑂2,0) = 0 because at the beginning of the experiment there was no CO2 in the reservoir. The number of moles of CO2 stored in hydrate in the reservoir is calculated as follows 72  𝑛𝐶𝑂2,𝐻 = (𝑛𝑆𝑉−𝐶𝑂2,0 − 𝑛𝑆𝑉−𝐶𝑂2,𝑡) − (𝑛𝐶𝑅−𝐶𝑂2,𝑡 − 𝑛𝐶𝑅−𝐶𝑂2,0) − 𝑛𝐷,𝑡         = [(0.9𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,0− (0.9𝑃𝑆𝑉𝑉𝑆𝑉𝑧𝑅𝑇)𝑆𝑉,𝑡] − [(𝑦𝐶𝑂2,𝑡𝑃𝐶𝑅𝑉𝐶𝑅𝑧𝑅𝑇)𝐶𝑅,𝑡− 0] − 𝑛𝐷,𝑡                       (4.3) Calculations of the percentage of water conversion, CO2 hydrate saturation and CO2 storage density ware the same as those for experiments (p). The hydration number of CO2/N2/CH4 hydrate formed in this experimental work was found to be 6.1549. Figure 4.5 shows the pressure and temperature profiles for experiment (r1) during which a CO2 /N2 (90/10 mol %) gas mixture was injected into a reservoir containing 500 kPa CH4. Like experiment (q1) no hydrate formation in the reservoir was observed during the constant flow rate CO2/N2 injection period. A 3 K rapid temperature rise was observed at about 220 min. The temperature rise in experiment (r1) is lower than that in experiment (q1) perhaps because the presence of CH4 in the gas mixture reduced the pressure driving force and this in turn results in a lower hydrate crystal growth and less hydrate formed overtime. Figure 4.6 shows the calculated CO2/N2/CH4 hydrate partial phase diagram49. The driving force for experiment (r1) at the nucleation point is 871 kPa (3200 kPa-2329 kPa) because the gas phase composition is CO2/N2/CH4 (76/8/16 mol %). The equilibrium hydrate formation pressure for this mixture is 2329 kPa. The driving force for (r1) is less than the 981 kPa for experiment (q1) indicating a delay in nucleation and less hydrate being formed. Indeed, the average nucleation time in experiments (r) is 223 min whereas for experiments (q) is 185 min as seen from Table 4.1. The driving force after 120 h for experiment (r1) is 743 kPa (3200 kPa-2457 kPa) because the gas phase composition after 120 hours is CO2/N2/CH4 (78/16/6 mol %). The amount of CO2 stored also reflects the fact that less hydrate formed. As seen in Table 4.1, 0.567 and 0.654 mol (average for r1, r2 and r3) of CO2 stored in hydrate form after 24 h and 120 h, respectively. 73  These amounts are less than the corresponding amounts reported for experiment (q1). The CO2 storage density in hydrate form in the reservoir is 71.9 kg/m3 (average) after 120 h.  Figure 4.5 Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (r1) for 24 h, the first 360 min and 120 h. 74    Figure 4.6 CO2/N2/CH4-H2O partial phase diagrams. The dark circle represents the equilibrium pressure of hydrate formed by the CO2/N2/CH4 (76/8/16 mol %) mixture at 277 K at the hydrate nucleation point, where driving force ΔPr = 3200 kPa-2329 kPa = 871 kPa. The dark spot represents the equilibrium pressure of hydrate formed by the CO2/N2/CH4 (78/16/6 mol %) mixture at 277 K after 120 h, where driving force ΔPr = 3200 kPa-2457 kPa = 743 kPa.   75  4.5 Injection of CO2/N2 (90/10 mol %) into a reservoir containing 500 kPa CH4 and 1 wt % tapioca starch It is noted that a 1 wt % tapioca starch aqueous solution was used in experiments (s). The tapioca starch solution was prepared according to the method mentioned in 3.3. The reservoir preparation, gas injection procedures and metrics calculations are the same as in experiments (r). No literature data has been found for the hydration number of CO2/N2/CH4 hydrate formed 1 wt % tapioca starch solutions. Because tapioca starch is known not to enter the hydrate crystal lattice it is assumed that the hydration number remains unchanged 6.15. 76   Figure 4.7 Progress of the pressure and temperature profiles in the reservoir corresponding to experiment (s1) for 24 h, the first 600 min and 120 h.  77  Figure 4.7 shows the pressure and temperature profiles in the reservoir for experiment (s1) during which a CO2/N2 (90/10 mol %) gas mixture was injected into a reservoir containing 500 kPa CH4 and 1 wt % tapioca starch. Rapid hydrate formation was observed at 350 min according to a 3 K temperature rise. The reservoir temperatures decreased gradually to 277 K in the following two hours and no significant temperature change was observed in the rest of the experiment. The gas composition shows no difference with the experiment (r1). As shown in Table 4.1 0.551 mol of CO2 stored in hydrate and CO2 storage density in hydrate form reached 61.3 kg/m3 after 24 h which is less than the CO2 storage in experiment (r1). However, the CO2 storage density reached 74.7 kg/m3 (average for s1, s2 and s3) after 120 h, which is more than the 71.9 kg/m3 (average for experiments r1, r2 and r3). The addition of 1 wt % tapioca starch postponed the onset of hydrate formation because the starch is a hydrate kinetic inhibitor. Moreover, the presence of starch was found to reduce the amount of CO2 stored in hydrate in the first 38 h but then accelerated the hydrate formation during the rest of the experiment period. This observation was also reported in 3.3 and denotes the fact that tapioca starch acts as a kinetic hydrate inhibitor like Polyvinylcaprolactam (PVCap). About 85.4 % (average for experiments s1, s2 and s3) of initial reservoir water formed CO2 hydrate and the CO2 hydrate saturation in the reservoir was 0.207 after 120 h (average). 4.6 Summary Figure 4.8 shows the average ratio of moles of CO2 stored in hydrate over the moles of water in place in the reservoir. Data from 2.4.2 are also included for comparison purposes. It is noted that after the first 24 h, more CO2 stored in the experiments (p1) than (q1). However, the opposite results were observed in the experiments during the rest four days. The addition of 1 wt % 78  tapioca starch affects the hydrate formation and the CO2 storage. In the first 24 h more CO2 stored in the experiments (r1) than (s1). However, the amount of CO2 stored in experiments (s1) is more than experiments (r1) in the rest four days. This phenomenon has been also observed in 3.3. The presence of 1 wt % tapioca starch in the reservoir prevented the hydrate formation in the early stage and then enhanced the hydrate formation. This may be considered a positive factor in the process of CO2 gas injection into the depleted reservoirs in two ways. First, it decreases the risk of plug formation near the injection wellbore due to the delay in the onset of nucleation. Secondly, the hydrate formation is enhanced at later stage of the injection process and this in turn increases the amount of stored CO2 as hydrate.    Figure 4.8 The ratio of moles of CO2 stored in hydrate form over the moles of water in place in the reservoir after every 24 h in experiments (h1) and (p1) to (s1). 79  5 Measurement of Hydrate Phase Equilibria in the CO2/CH4/N2/H2O system in a Stirred High Pressure Crystallizer and High Pressure Micro Differential Scanning Calorimetry (HP-μDSC)  In this chapter the equilibria of hydrate formed in high pressure crystallizer as well as with calorimetry at the typical depleted natural gas reservoir conditions were measured and the measured values were compared with calculated values using CSMGem software were also discussed. 5.1 Materials The CO2, CH4 and N2 gas with 99.5 %, 97.97 % and 99.999 % purities respectively were obtained from Praxair. Sodium Chloride (NaCl) was obtained from Fisher Scientific. The silica sand was obtained from Sigma-Aldrich with the porosity of 0.35 and the average diameter of 329 μm. Tapioca starch (average molecular mass of 3 mDa) was obtained from National Starch ULC. 5.2 Hydrate formation and dissociation in a stirred high pressure crystallizer containing water, 2 and 4 wt % saline solution 5.2.1 Experimental setup and methods Binary mixtures containing a target concentration of 95 and 85 mol % CO2 with CH4 and N2, respectively, prepared from the above gases and were employed in the experiments. The exact concentrations of the gas mixtures obtained by Gas Chromatography are shown in Table 5.1, 80  which lists all the experiments. A ternary CO2/N2/CH4 mixture with a target composition of 78/16/6 mol % was also prepared and the real concentrations are shown in Table 5.1. The incipient hydrate equilibrium formation pressures were determined by the well-known isothermal pressure search method62,96. The hydrate formation and dissociation apparatus is shown in Figure 5.1 and was descried elsewhere63 (the literature reported apparatus is shown in Appendix B). Briefly, a 211 mL high pressure crystallizer was employed to conduct the hydrate equilibria measurement experiments. There were two circle windows on the crystallizer to provide visual observation of the hydrate formation and dissociation process. An amount of 80 mL of deionized water or 2 and 4 wt % NaCl solutions prepared by weighting the salt was located into the crystallizer. The crystallizer was then immersed into the temperature controlled bath. Three thermocouples (Omega) with 0.1 K uncertainties were employed to measure the gas, liquid and gas/water interface temperatures. Pressure transducers (Rosemount, model 3051) with maximum uncertainty of 0.075 % of the 0 to 15000 kPa span were used to measure the crystallizer and supply vessel pressures. The temperature and pressure data were logged by a data acquisition system every 5 sec to a computer using LabView software. The crystallizer was pressurized with CO2 gas or the gas mixtures to 1500 kPa and then was depressurized three times to eliminate the presence of the air. When all the three temperatures arrived at the desired value the CO2 gas or the gas mixtures was injected into the crystallizer to approximately 1000 kPa higher than the hydrate equilibrium pressure at the given temperature and started stirring at 500 rpm in the crystallizer. The temperature rises and pressure decreases indicated the formation of gas hydrate. The nucleation of hydrate also can be verified by the visual observation through the window on the crystallizer. Flocculent crystals were initially formed at the interface of the gas and liquid, then grew toward to the liquid phase. 81  Table 5.1 Hydrate equilibrium pressures measured in high pressure crystallizer at fixed temperature. Sample gas or gas mixtures T (K) P (kPa) in water  in 2 wt % NaCl  in 4 wt % NaCl This work CSMGem  This work CSMGem  This work CSMGem CO2 276.15 1760 1776  1956 1967  2164 2185   1752   1932   2149    1747   1931   2187  277.15 2023 2009  2222 2231  2498 2487  1996   2195   2476   1995   2214   2467  278.15 2296 2278  2560 2540  2856 2838  2245   2519   2850   2258   2555   2828  CO2/CH4 (95/5 mol %) 276.15 1772 1792  1971 1980  2182 2194 #1: (95.10/4.90 mol %) #2: (95.03/4.97 mol %) #3: (94.95/5.05 mol %)  1785   1979   2190   1800   1977   2191  277.15 2008 2024  2240 2241  2495 2491  2013   2267   2482   2011   2235   2475  278.15 2288 2290  2557 2545  2839 2843  2268   2522   2852   2271   2518   2821  CO2/N2 (85/15 mol %) 276.15 2080 2071  2308 2295  2564 2553   2092   2301   2577    2083   2315   2543  #1: (85.03/14.97 mol %) #2: (84.83/15.17 mol %) #3: (84.94/15.06 mol %) 277.15 2350 2346  2619 2609  2921 2913  2359   2625   2940   2363   2576   2912   278.15 2675 2666  2955 2977  3327 3343  2664   2943   3309   2668   2985   3317  CO2/N2/CH4 (78/16/6 mol %) 276.15 2140 2128  2342 2352  2589 2608 #1: (78.02/15.89/6.09 mol %) #2: (77.98/15.98/6.04 mol %) #3: (77.85/16.06/6.09 mol %)  2149   2316   2636   2151   2351   2617  277.15 2430 2405  2664 2667  2971 2968  2409   2698   2964   2383   2682   2939  278.15 2740 2727  3037 3035  3389 3391  2744   3010   3410   2711   3064   3421  82    Figure 5.1 Schematic of the apparatus for hydrate formation and dissociation in bulk system. 83  As shown in Table 5.1 the gas hydrate dissociation pressures were measured at 276.15, 277.15 and 278.15 K, which represent the typical Alberta hydrocarbon reservoirs temperatures. The calculation values using CSMGem software49 are also shown in Table 5.1. Once the hydrate formed the crystallizer was depressurized to decompose the hydrate. The induction of hydrate nucleation and the hydrate decomposition was repeated twice more to enhance the degree of the liquid phase structuralization and to eliminate the hysteresis phenomenon. Then the crystallizer was pressurized again with specific gases 10 kPa above the calculated hydrate equilibrium pressures to induce the hydrate formation. After 3 to 4 h if a small amount of hydrate formation was observed while temperatures and pressure remained steady then the crystallizer pressure was considered to be the equilibrium pressure at the setting temperature. If no hydrate formation was detected the crystallizer was pressurized 20 kPa higher than the previous value and the crystallizer was left at these conditions for 3 to 4 h. The operation was repeated until temperature and pressure conditions remained steady while there is a small amount of hydrate present. If hydrate already formed, then the crystallizer was depressurized by 20 kPa to decomposed the hydrate. Then the above mentioned procedure was repeated to increase the pressure 20 kPa once until hydrate equilibrium pressure was obtained. The equilibrium pressure measurement was conducted from 278.15 K then lower temperatures of 277.15 and 276.15 K were subsequently set to measure the following hydrate equilibrium pressures. All the equilibria measurement experiments were conducted three times. 5.2.2 Results and discussion The measured CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %) and CO2/N2/CH4 (78/16/6 mol %) hydrate equilibrium pressures at 276.15, 277.15 and 278.15 K in water, 2 and 4 wt % NaCl solutions are shown in Table 1. The measured equilibrium pressures and the calculated 84  values using the CSMGem software are shown in Figure 5.2 to 5.5. The NaCl as expected shifts the hydrate equilibrium to a higher pressure region at constant temperature. The measured hydrate equilibrium pressures are in a good agreement with the calculated values (within ± 40 kPa).    Figure 5.2 CO2 hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions. 85   Figure 5.3 CO2/CH4 (95/5 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions.  86   Figure 5.4 CO2/N2 (85/15 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions.  87   Figure 5.5 CO2/N2/CH4 (78/16/6 mol %) hydrate equilibrium pressures measured in the stirred high pressure crystallizer and by high pressure micro differential scanning calorimetry in water, 2 and 4 wt % NaCl solutions. 5.3 Hydrate dissociation in a high pressure micro differential scanning calorimetry containing water, 2 and 4 wt % saline solution  5.3.1 Experimental setup and methods The use of the calorimeter to obtain equilibrium data is briefly described62. The HP-μDSC 7 Evo, Setaram high pressure calorimeter was used to detect and measure the heat transfer when gas hydrate formed and dissociated. Double-stage temperature control with Peltier coolers was used 88  in the HP-μDSC to provide a programmable temperature scanning between 228.15 and 393.15 K under the heating or cooling rate of 0.001 to 2 K/min. The uncertainties of the temperature and heat flow measurement are known to be 0.1 K and 0.05 mJ. The HP-μDSC has two 1 mL cells, sample cell and reference cell, which both can sustain up to 40 MPa. Two types of sample holder were used and are shown in Figure 5.6. One is called droplet sample holder and its description can be found elsewhere63. Briefly, it is a customized stainless steel holder with four 1.5 mm diameter, 2.6 mm depth pits and a 1.6 mm diameter, 7 mm length rod. The volume for each pit is 1 mL and 1 μL deionized water or 2 or 4 wt % NaCl solution was injected into the pits using a micro-syringe carefully. Thus the total volume of the injected water or solutions was 4 μL. The other one is a reservoir sample holder and was developed in this work. It consists of a high-pressure Nylo-Seal Nylon tubing with an inside diameter of 2.3 mm and inside height of 8 mm. The cylindrical tubing was sealed at the bottom to make it a sample holder. 40 mg silica sand was placed into the holder and 8.7 μL of aqueous solution was injected into the sand using a micro-syringe to render it fully water saturated. The list of the experiments using HP-μDSC is shown in Table 5.2. The sample holder was then placed in the high-pressure sample cell. The sample cell and the reference cell were pressurized to 1500 kPa with the gas hydrate forming gas. This was followed by depressurization. This operation was repeated two times to eliminate the air in the cells. Subsequently, the cells were pressurized to 3200 kPa and the temperature ramping program was started. The cells were cooled from 288.15 K to 248.15 K at the rate of 0.1 K/min to form gas hydrate and were heated from 248.15 K to 288.15 K at the same rate to decompose the hydrate. Gas hydrate nucleation and dissociation are represented by exothermic and endothermic peaks respectively. It is noted that all the experiments with the HP-μDSC were conducted three times. 89    Figure 5.6 Droplet sample holder and reservoir sample holder using in HP-μDSC. 5.3.2 Results and discussion The measured hydrate equilibrium dissociation temperatures and endothermic heat under constant 3200 kPa in a HP-μDSC in the water droplet and water, 2 and 4 wt % NaCl solutions fully saturated reservoir are shown in Table 5.2 and Figure 5.2 to 5.5. Figure 5.7 shows the hydrate dissociation peaks for CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %) and CO2/N2/CH4 (78/16/6 mol %) gas or gas mixture hydrate forming systems observed with HP-μDSC in the water droplet sample holder under a 0.1 K/min heating protocol. The presence of 5 mol % of CH4 in the CO2/CH4 shows a very small effect on the hydrate dissociation temperatures compared to the case of pure CO2. It is calculated by using CSMGem software that at a given temperature the hydrate equilibrium pressure of CO2 increases by about 35 kPa when hydrates form from a CH4/CO2 mixture with 5 mol % CH449. 90  Table 5.2 Hydrate dissociation temperatures and endothermic heat measured under constant 3200 kPa in a HP-μDSC in the water droplet and water, 2 and 4 wt % NaCl solutions fully saturated reservoir.  Sample gas/gas mixtures Droplet  Reservoir in water  in water  in 2 wt % NaCl  in 4 wt % NaCl T (K) H (mJ)  T (K) H (mJ)  T (K) H (mJ)  T (K) H (mJ) This work CSMGem   This work   This work CSMGem   This work CSMGem  CO2 280.8 280.7 482.3  280.6 3636.0  279.8 279.8 3050.3  278.9 279.0 2204.5  280.9  492.4  280.6 3696.7  279.8  3098.4  278.8  2185.9 280.8  488.1  280.6 3643.5  279.7  3110.8  278.9  2238.6 CO2/CH4 (95/5 mol %) 280.6 280.7 469.1  280.5 3404.0  279.8 279.9 2798.0  278.9 279.0 1920.3 #1: (95.10/4.90 mol %) #2: (95.03/4.97 mol %) #3: (94.95/5.05 mol %) 280.6  447.7  280.6 3379.3  279.9  2805.1  279.0  1895.4 280.7  453.9  280.6 3309.1  279.8  2765.2  278.9  1919.0 CO2/N2 (85/15 mol %) 279.6 279.5 449.7  279.6 2980.4  278.6 278.7 2490.6  277.7 277.8 1537.7 #1: (85.03/14.97 mol %) #2: (84.83/15.17 mol %) #3: (84.94/15.06 mol %) 279.5  439.0  279.4 3008.8  278.7  2491.3  277.8  1572.8 279.6  446.2  279.6 2973.3  278.5  2439.7  277.7  1598.5 CO2/N2/CH4 (78/16/6 mol %) 279.3 279.4 433.0  279.3 2898.9  278.5 278.6 2426.9  277.7 277.7 1522.7 #1: (78.02/15.89/6.09 mol %) #2: (77.98/15.98/6.04 mol %) #3: (77.85/16.06/6.09 mol %) 279.3  435.1  279.4 2878.1  278.4  2419.8  277.6  1530.9 279.3  427.8  279.4 2937.4  278.5  2400.5  277.6  1519.4 91   Figure 5.7 Hydrate dissociation peaks for four hydrate forming systems (#1) observed with HP-μDSC in the droplet sample holder under a 0.1 K/min heating protocol. The hydrate dissociation temperature shifts to a lower region when N2 or N2 and CH4 are added to CO2. The endothermic heat measured during the dissociation of hydrate in the HP-μDSC is also shown in Table 5.2. It is also noted that during the CO2/N2 (85/15 mol %) hydrate dissociation process, a second and much smaller endothermic peak is observed at about 280 K and it is not known why. The measured hydrate dissociation temperatures show - 0.1 to 0.2 K differences from the calculated values. As shown in Figure 5.7, peaks with shoulder or tail were observed. It may be related to the different subcooling for the different droplets and this could result in slightly different dissociations for the four droplets and therefore the dissociation peaks. 92  Figure 5.8 to 11 show the hydrate dissociation peaks for hydrates formed by the CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %) and CO2/N2/CH4 (78/16/6 mol %) in deionized water, 2 and 4 wt % NaCl solutions. The measured hydrate dissociation temperatures and the calculation data are shown in Table 5.2. Similar to the measurements with the water droplet sample holder, the presence of N2, CH4 or N2/CH4 in the CO2 shifted the hydrate dissociation temperature to a lower region. The increase of salinity in the reservoir resulted in lower hydrate dissociation temperatures at the constant pressure of 3200 kPa. The hydrate dissociation endothermic heat also showed a decreasing trend with the increasing of the salinities in the reservoir, which indicates less hydrate formed. It is noted that the hydrate dissociation process in 2 and 4 wt % NaCl reservoirs lasted longer period compared to the hydrate dissociation in the water reservoir. Because NaCl does not participate in the hydrate lattice, the salinity of the aqueous solution increases as hydrate formation proceeds. Similarly, when the hydrate decomposes the salinity is restored as water is being released. The incipient equilibrium hydrate formation points correspond to the presence of an infinitesimal amount of hydrate (onset of hydrate formation) or when an infinitesimal amount of hydrate remains undissociated62,63,96. It is also noted that the measured hydrate dissociation temperatures in the reservoir sample holders show ± 0.2 K difference with the calculated values49. 93   Figure 5.8 CO2 hydrate dissociation peaks for hydrate formed in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol. 94   Figure 5.9 Hydrate dissociation peaks for hydrate formed by the CO2/CH4 (95.10/4.90 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol. 95   Figure 5.10 Hydrate dissociation peaks for hydrate formed by the CO2/N2 (85.03/14.97 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol. 96   Figure 5.11 Hydrate dissociation peaks for the hydrate formed by the CO2/N2/CH4 (78.02/15.89/6.09 mol %) gas mixture in deionized water, 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol. The percentage of water converted to hydrate was calculated based on the endothermic heat measured when hydrate dissociated in the HP-μDSC. It is known that the enthalpy change is 65 kJ/mol and the hydration number is 6.17 for the CO2 hydrate49,97. Results showed that about 21 % of the initial water in the droplet sample holders formed hydrate, which is much less than 72 % of the water conversion in the reservoir sample holder. This observation is consistent with experimental findings reported in the literature for sand beds98. It is noted that the enhanced rate in the presence of a porous medium created by sand prompted further work with other media in 97  an effort to optimize the clathrate hydrate processes for CO2 capture99,100. The water conversion in the reservoir samples containing 2 and 4 wt % NaCl solutions was found to be 61 and 43 %, respectively, indicating less hydrate formed at higher salinity, which is expected as the pressure was constant. 5.4 Summary The incipient hydrate equilibrium pressures measured in the stirred autoclave are in a good agreement with the calculated values (within ± 40 kPa). The hydrate dissociation temperatures determined by the calorimeter using a droplet and a porous media (reservoir) sample holder also show good agreement with the calculated values (within ± 0.2 K). The salinity shifts hydrate equilibrium to higher pressure region at constant temperature or lower dissociation temperature region at constant pressure as expected. Correspondingly, the amount of formed hydrate is reduced. Results indicate that 40 to 60 % of the original water formed hydrate when CO2 was injected into a typical saline reservoir sample.       98  6 CO2 Storage Density   In this chapter the CO2 storage density in kg/m3 (mass of CO2 per pore volume in the laboratory reservoir) based on our experimental data is calculated. In addition, the amount that can be stored in a typical Alberta reservoir is estimated as well as the total storage capacity of the 121 Alberta reservoirs 6.1 CO2 storage density with and without hydrate technology The stored CO2 consists of CO2 as hydrate, CO2 gas in the remaining pore volume not occupied by hydrate and also the amount of CO2 dissolved in the remaining water. Table 6.1 shows the experimental conditions from experiments (a) to (s). Figure 6.1 shows the total CO2 storage densities (kg/m3, mass of CO2 per pore volume in the laboratory reservoir) that was determined in the experiments (a) to (s) mentioned in Chapter 2, 3 and 4 (average for the three runs of experiments under each method). The standard deviations of the total CO2 storage density for the experiments which were run for three times are given as (a) 0.374, (b) 0.698, (c) 0.262, (d) 0.189, (e) 0.125, (f) 0.125, (g) 0.047, (h) 1.275, (i) 0.655, (j) 0.455, (k) 0.205, (l) 0.464, (m) 0.525, (n) 0.624, (o) 0.170, (p-24 h) 0.374, (p-120 h) 0.262, (q-24 h) 1.134, (q-120 h) 0.283, (r-24 h) 0.818, (r-120 h) 1.236, (s-24 h) 0.492 and (s-120 h) 0.125. The conditions for CO2 stored in gas form in experiments (a), (b) and (c) are 1850 kPa, 274 K, 3180 kPa, 274 K and 3200 kPa, 274 K, respectively. 3200 kPa, 277 K are the conditions for CO2 storage as gas in all the other experiments. More CO2 stored in multiple gas injection cases (gas injection through spiral and vertical tubing) than the experiments of gas injection in a gas cap. Gas injection under constant flow rate and constant pressure experiment results in more CO2 storage compared to constant pressure injection case. Higher initial pressure driving force in constant pressure injection 99  experiment likely leads to rapid hydrate formation in the porous bed. This may hinder mass transfer of gas into the unconverted water in other interstitial spaces. Even though the rate of hydrate growth decreases after the first few hours it continues beyond the 24 h period. Experiments conducted after 120 h showed that more total CO2 storage density in the reservoirs containing 1 wt % of tapioca starch (experiments l, 145.2 kg/m3) and 3 wt % of PVP (experiments j, 146.6 kg/m3) compared to in a pure water reservoir (experiments h, 142.9 kg/m3). The effect of the addition of 3 wt % of PVP and 1 wt % of tapioca starch on hydrate formation is in accordance with a previous work58. However, if the tapioca starch concentration increases to 3 wt % both 24 h and 120 h experiments results less CO2 storage density than pure water experiment. It is also seen that the presence of 2 wt % (experiments n, 126.7 kg/m3) and 4 wt % (experiments o, 114.0 kg/m3) of salinity in the reservoir reduces the CO2 storage density compared to a reservoir containing pure water (experiments h, 138.2 kg/m3) after 24 h. When a CO2/N2 gas mixture is injected in a reservoir containing CH4 the total CO2 storage density (experiments r, 118.6 kg/m3) decreases by 17 % compared to the CO2 injection into a CH4 free reservoir (experiments h, 142.9 kg/m3) after 120 h. The addition of 1 wt % of tapioca starch in the reservoir containing CO2/N2/CH4 (experiments s) results in 121.0 kg/m3 total CO2 storage density which is 2 % higher than the CO2 storage density in the reservoir without starch (experiments r, 118.6 kg/m3) after 120 h. 100  Table 6.1 Experimental conditions of experiments (a) to (s)  Exp. Injection gas Injection method Initial reservoir temperature [k] Additives in reservoir Residual gas in reservoir (a) CO2 Batch injection in a gas cap 274.15 - - (b) CO2 Series-batch injection in a gas cap 274.15 - - (c) CO2 Constant pressure injection in a gas cap (3200 kPa) 274.15 - - (d) CO2 Constant pressure injection through a spiral tubing at top (3200 kPa) 277.15 - - (e) CO2 Constant pressure injection through a spiral tubing at bottom (3200 kPa) 277.15 - - (f) CO2 Constant pressure injection through spiral tubing at both top and bottom (3200 kPa) 277.15 - - (g) CO2 Constant pressure injection through a vertical tubing (3200 kPa) 277.15 - - (h) CO2 Constant flow rate (5 mL/min) followed by constant pressure (3200 kPa) injection through a vertical tubing 277.15 - - (i) CO2 Same as above 277.15 1 wt % PVP - (j) CO2 Same as above 277.15 3 wt % PVP - (k) CO2 Same as above 277.15 0.5 wt % starch - (l) CO2 Same as above 277.15 1 wt % starch - (m) CO2 Same as above 277.15 3 wt % starch - (n) CO2 Same as above 277.15 2 wt % NaCl - (o) CO2 Same as above 277.15 4 wt % NaCl - (p) CO2 Same as above 277.15 - 500 kPa CH4 (q) CO2/N2 (90/10 mol %) Same as above 277.15 - - (r) CO2/N2 (90/10 mol %) Same as above 277.15 - 500 kPa CH4 (s) CO2/N2 (90/10 mol %) Same as above 277.15 1 wt % starch 500 kPa CH4 101   Figure 6.1 Total CO2 storage densities (Average for the three runs of experiments under each method). 102  Figure 6.2 shows the average of total CO2 storage densities in experiments (s) for 120 h, CO2 storage as low pressure gas form at 2110 kPa, 277 K and high pressure gas form at 5220 kPa, 285 K under the injection of CO2/N2 (90/10 mol %) gas mixture into a reservoir without water and CH4. The CO2/N2 (90/10 mol %) gas mixture is assumed to occupy all of the free space in the reservoir for the gas and liquid form storage, respectively. The average of total CO2 storage density in the experiments (s) is 121.0 kg/m3, which is about 190 % greater compared to the low pressure gas storage (41.3 kg/m3) and is almost the same as the high pressure gas storage (120.2 kg/m3). If CO2 is stored as liquid at conditions near the bubble point of CO2/N2 (90/10 mol %) at 8500 kPa and 285 K, the CO2 storage density as liquid is 890 kg/m3 i.e. approximately 6 times higher than the average CO2 storage density in experiments (s) in this work. However, CO2 storage in that liquid CO2 state requires significantly more power for gas compression and is not safe.  103   Figure 6.2 Average of total CO2 storage densities in the experiments (s), CO2 storage as low pressure gas at 2110 kPa and 277 K and high pressure gas at 5220 kPa and 285 K under the injection of CO2/N2 (90/10 mol %) gas mixture into a reservoir without water and CH4. 6.2 CO2 storage density in an Alberta reservoir To assess the CO2 storage potential in a depleted hydrocarbon reservoir in the field the CO2 storage density obtained in this experimental work is applied to a reservoir selected from the borehole database provided by Alberta Energy and Utilities Board (AEUB)101 as a case study. The reservoir (Pool code 328098) with the porosity of 0.28 located 204 m underground in the LIEGE field has a reservoir volume of 1.1 × 107 m3 and the initial pressure/temperature 104  conditions are 840 kPa and 277 K. The initial water saturation was 0.25. Assuming that the CO2 storage density is the same as that found in experiments (s) which indicate the CO2/N2 (90/10 mol %) injection into a reservoir containing 500 kPa CH4 and 1 wt % starch then the potential to store CO2 as hydrate + gas + dissolved in water form is calculated as 373 kt in the real field reservoir. Considering the total volume of 2.1 × 1012 m3 of Alberta depleted natural gas reservoir was investigated30, about 71.2 Gt (43.9 Gt as hydrate form) of CO2 can potentially be stored in these reservoirs if hydrate technology applied. Thus, storage of CO2 using hydrate technology in depleted natural gas reservoirs in Alberta would be able to potentially store local CO2 for more than 250 years. 6.3 Economic analysis of CO2 storage The motivation to store CO2 in depleted natural gas reservoirs is of course driven by climate change concerns but also from the economic considerations. There is a profit or economic advantage from the CO2 storage arising from savings (avoidance) of CO2 emission levies. Current CO2 levies in Alberta are $ 30 USD/tonne of CO2 emitted and it shows an increasing trend in the next few years8. The costs of the CO2 storage are mainly from the CO2 capture from the flue gas, transportation, compression and the right to use the depleted natural gas reservoirs13.  The estimated costs are $ 11 to 57 USD/t for the CO2 capture, $ 3 to 4 USD/t for the transportation and $ 6 to 7 USD for the compression and injection (disposal)102. The land use, air and water emission permits cost $ 100 k USD/site103. The cost of the addition of tapioca starch is $ 300 to 350 USD/100 tonnes and amount of starch required in one reservoir is about 1000 tonnes. Thus the cost of the starch can be ignored compared to other costs. The economic analysis of CO2 storage is shown in Figure 6.3. The profit and cost estimation are given based on 105  the US dollar per tonne of CO2. The costs are given as a range of the source value and three estimations of CO2 storage profit are given by applying different CO2 emission levies. One sees the interplay between carbon price and capture cost.   Figure 6.3 Economic analysis of CO2 storage. Applying the CO2 storage economic estimation (total cost, 20 USD/t; storage profit, 30 USD/t) to the LIEGE field reservoir mentioned in 6.1, the net profit of the CO2 storage using hydrate technology is calculated as follows 106  Net profit of CO2 storage in the reservoir= (Net profit of CO2 storage1 tonne of CO2× CO2 capacity in reservoir )− (Land use, air and water emission permits costsite× 1 site) = $ 10 USD/t × 373 kt − $ 100 k USD = $ 3.63 m USD                    (6.1) In addition, the net profit of the CO2 storage using hydrate technology in the investigated 121 depleted natural gas reservoirs in Alberta is as follows Net profit of CO2 storage in Alberta depelted natural gas reservoir = (Net profit of CO2 storage1 tonne of CO2× Toal CO2 capacity in reservoirs )− (Land use, air and water emission permits costsite× 121 site) = $ 10 USD/t × 71.2 Gt −$ 100 k USDsite × 121 site = $ 7.12 × 102 b USD                                                                                   (6.2)      107  7 Conclusions and Recommendations 7.1 Conclusions CO2 hydrate formation and corresponding estimation of CO2 storage were conducted in a laboratory scale partially water saturated reservoir simulating a typical Alberta depleted natural gas reservoir. The effect of gas injection method, the presence of additives (PVP, tapioca starch), salinity (NaCl) and residual natural gas (CH4) in the reservoir were investigated. In addition, the presence of N2 in the injection gas mixture on CO2 storage density was also assessed. It was found that multiple (spiral tubing) gas injection experiments result in more CO2 gas uptake than gas cap mode gas injection experiments. More hydrate formed in the experiments under constant flow rate followed by constant pressure gas injection compared to the experiments under constant pressure gas injection. The addition of 3 wt % of PVP (molecular weight = 3.5 kDa) and 1 wt % of tapioca starch (molecular weight = 3 mDa) solution in the reservoir prolonged the hydrate nucleation at early stage then improved hydrate formation and resulted in 6.5 % and 4.6 % more CO2 stored in hydrate form respectively compared to the CO2 stored in pure water reservoir in the experiment period of 120 h. It can be considered a positive factor for the CO2 gas injection into the reservoirs due to a decreased risk to plug the injection system arising from the formation of the hydrate. After 120 h, 90 % of the amount of water initially added in the reservoir formed hydrate and the combination of CO2 stored in hydrate, gas and dissolved in water arrived 147 kg/m3. The presence of NaCl in the reservoir reduced the amount of hydrate formation as less hydrate formed in the reservoir containing higher salinity. 108  CO2/N2 (90 /10 mol %) gas mixture and 500 kPa CH4 were also utilized to simulate the injection gas and the residual gas in the reservoir to determine the CO2 storage density taking into account the fact that the captured flue gas is about 90 mol % of CO2 and also that the reservoir has residual natural gas. The presence of 10 mol % N2 in the CO2/N2 injection gas mixture into a CH4 free reservoir postponed the hydrate formation and reduced the stored amount of CO2 as gas hydrate by 5 % compared to the pure CO2 injection into a CH4 free reservoir. The injection of CO2 into a 500 kPa CH4 reservoir also found to postpone the hydrate formation and reduced the stored amount of CO2 as gas hydrate by 9 % compared to the pure CO2 injection into a CH4 free reservoir. The presence of 10 mol % N2 in the CO2/N2 injection gas mixture into a 500 kPa CH4 reservoir postponed the hydrate formation and reduced the stored amount of CO2 as gas hydrate by 10 % compared to the pure CO2 injection into a CH4 free reservoir. The addition of 1 wt % tapioca starch in the reservoir delayed the onset of hydrate nucleation then improved the hydrate formation process and resulted in higher total CO2 storage density (in hydrate, gas and dissolved in water). It was found the total CO2 storage density reached 121 kg/m3 after 120 h experiment. The equilibria of hydrate forming systems [CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %) and CO2/N2/CH4 (78/16/6 mol %)] relevant to storage of CO2 in depleted natural gas reservoirs was determined by following the isothermal pressure search method in a stirred autoclave and high pressure calorimetry containing deionized water and saline water. The incipient hydrate equilibrium pressures measured in the stirred autoclave are in a good agreement with the calculated values (within ± 40 kPa). The hydrate dissociation temperatures determined by the calorimeter using a droplet and a porous media (reservoir) sample holder also show good agreement with the calculated values (within ± 0.2 K). The salinity shifts hydrate equilibrium to 109  higher pressure at constant temperature or lower dissociation temperature region at constant pressure as expected. Correspondingly the amount of formed hydrate is reduced. 7.2 Recommendations for future work Based on the study and understanding obtained from this thesis, the following recommendations are made for future work. 1. The number of depleted natural gas reservoirs in Alberta with suitable conditions for CO2 storage in hydrate form increased from 61 in 2010 to 121 in 2013. It is necessary to ascertain the substances in the reservoir in addition to natural gas and salinity and assess the effect of these substances on the hydrate formation and corresponding CO2 storage.  2. The effect of porosity and pore size of the sand or stone on hydrate formation has been reported recently104-106.  Further study of these parameters similar to the depleted natural gas reservoirs on hydrate formation kinetics is required. 3. In this study the CO2/N2 (90/10 mol %) was simulated as the flue gas captured for the gas injection experiments. 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Industrial & Engineering Chemistry Research 2015, 54, 12217-12232. [109] Englezos, P., Kalogerakis, N., Dholabhai, P. D., Bishnoi, P. R. Kinetics of formation of methane and ethane gas hydrates. Chemical Engineering Science 1987, 42, 2647-2658. 126  [110] Uddin, M., Coombe, D., Law, D., Gunter, B. Numerical studies of gas hydrate formation and decomposition in a geological reservoir. Journal of Energy Resources Technology 2008, 130, 032501.  [111] Clarke, M., Bishnoi, P. R. Determination of the intrinsic rate of ethane gas hydrate decomposition. Chemical Engineering Science 2000, 55, 4869-4883.             127  Appendices Appendix A: Mass balance and energy balance To establish a simulation of the CO2 hydrate formation in the reservoir the mass balance and energy balance were discussed. The following assumptions were made for formulating the equations in the process of CO2 gas injection and hydrate formation in the reservoir. 1. Four components were considered as CO2, water, hydrate and silica sand. 2. Three phases were considered as gas, aqueous and solid. 3. The porosity of the sand is constant. 4. The density of the CO2 hydrate is constant. 5. The boundary temperature is constant. 6. The intrinsic permeability is isotropy. 7. The gas and aqueous viscosity is isotropy. During the CO2 injection the mass change of the CO2 with time is equal to the injection rate of CO2 to the reservoir – the consumption rate of CO2 in the reservoir + the CO2 flow from the surrounding volumes. Thus the governing equation of CO2 mass balance in block n is in the form 𝑑𝑀𝑛𝐶𝑂2𝑑𝑡= (𝑞𝑛𝐶𝑂2,𝑖𝑛𝑗 − 𝑞𝑛𝐶𝑂2,𝑐𝑜𝑛) + 𝐴𝑛𝐺−𝐿𝐹𝑛𝐶𝑂2                                                                               (A.1) where 𝑀𝑛𝐶𝑂2  is the mass change of CO2 per unit volume of block n, 𝑞𝑛𝐶𝑂2,𝑖𝑛𝑗  and 𝑞𝑛𝐶𝑂2,𝑐𝑜𝑛 indicates the injection rate and consumption rate of CO2 per unit volume of block n, 𝐴𝑛𝐺−𝐿 is the gas-liquid surface area per unit volume in the block n and 𝐹𝑛𝐶𝑂2  is the mass flux of CO2 transported through the gas-water surface in block n. 128  During the CO2 injection the mass change of the water with time is equal to the consumption rate of water + the water flow from the surrounding volumes. Thus the mass balance of water in the reservoir is in the form 𝑑𝑀𝑛𝑊𝑑𝑡= −𝑞𝑛𝑊,𝑐𝑜𝑛 + 𝐴𝑛𝐺−𝐿𝐹𝑛𝑊                                                                                                       (A.2) where 𝑀𝑛𝑊  is the mass change of water and 𝑞𝑛𝑊,𝑐𝑜𝑛 is the consumption rate of water per unit volume of block n, 𝐹𝑛𝑊 is the mass flux of water transported through the gas-liquid surface in block n. During the CO2 injection the mass change of the hydrate with time is equal to the hydrate formation rate. Thus the mass balance of hydrate in the reservoir is in the form 𝑑𝑀𝑛𝐻𝑑𝑡= 𝑞𝑛𝐻,𝑓𝑜𝑟                                                                                                                              (A.3) where 𝑀𝑛𝐻  is the mass change of hydrate and 𝑞𝑛𝐻,𝑓𝑜𝑟 is the formation rate of hydrate per unit volume in the block n.  Englezos et al.109 and Uddin et al.110 wrote the rate of hydrate growth per particle as (𝑑𝑁𝑑𝑡)𝑛= 𝐾𝑓𝐴𝑛𝐻(𝑓𝑛 − 𝑓𝑒𝑞)                                                                                                           (A.4) where 𝑁 is the number of moles of hydrate per volume of block n, 𝑘𝑓 is the hydrate formation rate constant, 𝐴𝑛𝐻  is the hydrate surface area per volume of block n, 𝑓𝑛  and 𝑓𝑒𝑞  indicate the fugacity of CO2 at the pressure of block n and the hydrate equilibrium pressure. 129  According to the equitation for 𝐾𝑓  wrote by Clark and Bishnoi111 to describe the hydrate decomposition, the equitation for 𝐾𝑓 in the hydrate formation process is in the form  𝐾𝑓 = 𝐾𝑓0𝑒𝑥𝑝 (∆𝐸𝑅𝑇)                                                                                                                       (A.5) where 𝐾𝑓0 is the intrinsic formation rate constant, ∆𝐸 is the activation energy, 𝑅 is the universal gas constant and 𝑇 is the temperature. Thus the mass balance of hydrate in the reservoir can be described as the form combing equations (A.3), (A.4) and (A.5) 𝑑𝑀𝑛𝐻𝑑𝑡= 𝐾𝑓0𝑒𝑥𝑝 (∆𝐸𝑅𝑇) 𝐴𝑛(𝑓𝑛 − 𝑓𝑒𝑞)𝑀𝐻                                                                                          (A.6) where 𝑀𝐻 is the molecular weight of the hydrate. Hydrate formation is an exothermic reaction. In the energy balance equation, the conduction, convection and heat flow to the surrounding is considered. During the hydrate formation the energy change of the CO2, water, hydrate and silica sand is equal to - the source of heat (hydrate formation) - the heat transferred to the surrounding volume. Thus the energy balance is in the form 𝑑𝑈𝑛𝑑𝑡= −𝑄𝑛𝐻 − 𝐴𝑛𝐻𝐹𝑛ℎ                                                                                                                   (A.7) where 𝑈𝑛 is the total internal energy per unit volume of block n, 𝑄𝑛𝐻 is the enthalpy of  hydrate per unit volume of block n, 𝐹𝑛ℎ is the heat flux flowed to the surrounding. Assuming there is no heat resistance between gas, water, hydrate and sand, the equation (A.7) can be written in terms of enthalpy as 𝑑𝑑𝑡[∅𝑆𝐶𝑂2𝜌𝐶𝑂2𝐻𝐶𝑂2 + ∅𝑆𝑊𝜌𝑊𝐻𝑊 + ∅𝑆𝐻𝜌𝐻𝐻𝐻 + (1 − ∅)𝑆𝑆𝜌𝑆𝐻𝑆] = −𝑄𝑛𝐻 − 𝐴𝑛𝐻𝐹𝑛ℎ              (A.8) 130  where ∅ is the porosity of the reservoir, 𝑆𝐶𝑂2, 𝑆𝑊, 𝑆𝐻 and 𝑆𝑆 indicate the saturation of CO2 gas, water, hydrate and silica sand, 𝜌𝐶𝑂2 , 𝜌𝑊 , 𝜌𝐻  and 𝜌𝑆  indicate the density of CO2 gas, water, hydrate and silica sand, 𝐻𝐶𝑂2, 𝐻𝑊, 𝐻𝐻 and 𝐻𝑆 indicate the enthalpy of CO2 gas, water, hydrate and silica sand.             131  Appendix B: Apparatus of the experiments of hydrate equilibria measurement using high pressure crystallizers Figure B.1 shows the high pressure crystallizer, which was reported in a previous work61 and also applied in the experiments of hydrate equilibria measurement in Chapter 5. In details, two stainless steel vessels (crystallizers) for two sets of apparatus with the inner volume of 211 mL were fitted with two circular polycarbonate winders for each on the front and back side to have a visual observation. Baffles were located in the vessels to control vortex formation during the stirring operation. The vessels were submerged in an insulated temperature controlled circulating bath to have desired temperature. The bath was filled with a propylene glycol solution, which contained propylene glycol and water as the volume ratio of 1:1. Two stainless steel supply vessels with the inner volume of 300 mL were also immersed in the bath to provide the gas to the crystallizers. The temperature of the bath was regulated by using an external refrigerating/heating programmable circulator obtained from VWR Scientific. A gas induce impeller coupled with a hollow shaft was located in each crystallizer and was controlled by a universal motor controller obtained from Autoclave Engineers. The pressure of the crystallizers and supply vessels were measured by using Rosemount smart pressure transmitters (model 3051, maximum uncertainty of 0.075 percent of the span of 1-15000 kPa). Three copper-constantan thermocouples obtained from Omega Engineering (uncertainty of 0.1 K) were used to measure the temperatures in gas, liquid and the liquid-gas interface. A high pressure and low flow control valve obtained from Fisher (Baumann 5100, NPS 1/4) coupled to a proportional, integral, derivative controller was installed between the crystallizer and supply vessel to regulate the crystallizer pressure for each set of the apparatus. The data acquisition system obtained from National Instruments was connected to a computer to record the pressure and temperature data. 132  A LabView software obtained from National Instruments was installed in the computer to communicate with the control valves and log the data into a Microsoft Excel file.  Figure B.1 Apparatus of the experiments of hydrate equilibria measurement using high pressure crystallizers. (Adapted from Sharifi et al., 201461)   

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