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Gravity-Assisted Immisicble Co2 for Enhanced Oil Recovery and Storage

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Gravity-Assisted Immisicble Co2 for Enhanced Oil Recovery and Storage GRAVITY-ASSISTED IMMISICBLE CO2 FOR ENHANCED OIL RECOVERY AND STORAGE A REPORT SUBMITTED TO THE DEPARTMENT OF ENERGY RESOURCES ENGINEERING OF STANFORD UNIVERSITY IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE By Daniel C. Hatchell June 2017 I certify that I have read this report and that in my opinion it is fully adequate, in scope and in quality, as partial fulfillment of the degree of Master of Science in Energy Resources Engineering. __________________________________ Prof. Sally M. Benson (Principal Advisor) iii Abstract The combination of CO2 enhanced oil recovery and CO2 storage is a promising technology to produce oil while simultaneously reducing net carbon emissions. Joint EOR and CO2 storage processes are often considered under conditions in which the oil phase and gas phase are miscible, leading to a near perfect displacement efficiency. Beneath a threshold minimum miscibility pressure, however, CO2-oil miscibility cannot develop. Immiscible cases are not well examined in literature but frequently occur in shallow reservoirs and heavy-oil reservoirs. Highly efficient miscible CO2, while ideal, would be unattainable in such reservoirs. This paper presents the results of reservoir simulations investigating the use of immiscible CO2 for combined EOR and carbon storage under gravity-assisted conditions. Immiscible CO2 is injected at a constant rate into the top of a water-flooded reservoir via horizontal wells. The downward motion of the expanding CO2 plume flows against gravity and is partially stabilized by buoyant forces against the heavier water phase, reducing viscous instability and improving sweep efficiency. Three-phase simulations were performed in a three dimensional, heterogeneous reservoir using ECLIPSE 300 with CO2SOL. Several key variables – CO2 injection rate, injection strategy, oil viscosity, and oil zone thickness - were systematically modified across simulation runs to determine the effectiveness of gravity-assisted immiscible CO2 injection under varying degrees of plume instability. Lower CO2 injection rates were observed to more generate very high sweep efficiencies, producing more oil per quantity of CO2 injected than higher injection rates. The most successful injection rate by economic analysis was found to be 2 million standard 3 m /day of CO2, balancing the beneficial effects of slower injection with the financial returns of faster injection. Shutting off the oil production wells was a viable strategy under the appropriate economic conditions. A novel injection strategy was considered in which periods of CO2 injection were interchanged with periods of well inactivity; the inactive periods allowed the gas plume to stabilize under buoyant forces, leading to a greater efficiency of stored CO2 per unit CO2 injected than a strategy of constant CO2 injection. Higher frequency alternations were observed to sweep with CO2 even more efficiently; the highest frequency simulation was more successful than the best continuous injection scheme under a variety of economic conditions. Gravity-assisted drainage with immiscible CO2 was found to be effective in 40° API and 30° API oil, but far less so in 20° API oil. The process was also far more successful when applied to thicker oil banks. The results as a whole demonstrate that immiscible CO2 injection can be an effective solvent for enhanced oil recovery and CO2 storage under the proper conditions. v Acknowledgments I want to thank my advisor, Sally Benson, for the assistance and guidance that she has provided me over the last two years. I could not have completed this work without her kindness and support throughout my time at Stanford. I would also like to thank my girlfriend, Hanbi Liu, for her constant encouragement and frequent visits to California. She has helped me struggle through difficult times in my research while keeping me focused on the important things in life. I want to thank my parents, who have helped me from a young age to be engaged in science and have been a constant positive influence in my life. I would not have aspired to go to graduate school without their support. I would finally like to acknowledge my funding, both from the Global Climate and Energy Project (GCEP) and from the National Science Foundation under grant no. DGE-1656518. This research would not have been possible without their assistance. vii Contents Abstract ............................................................................................................................... v Acknowledgments............................................................................................................. vii Contents ............................................................................................................................. ix List of Tables ..................................................................................................................... xi List of Figures .................................................................................................................. xiii 1. Introduction ..................................................................................................................... 1 1.1. Problem Statement ............................................................................................... 2 1.2. Research Approach .............................................................................................. 2 1.3. Organization of the Report ................................................................................... 2 2. Literature Review............................................................................................................ 4 2.1. CO2 Miscibility .................................................................................................... 4 2.2. Water Alternating Gas vs Gas Assisted Gravity Drainage .................................. 6 2.3. Combined CO2 Enhanced Oil Recovery and Storage .......................................... 8 3. Reservoir Simulation Model and Procedure ................................................................. 10 3.1. Simulation Grid ...................................................................................................... 10 3.2. Compositional Properties ....................................................................................... 12 3.3. Initial Conditions and Simulation Method ............................................................. 14 4. Simulation Results ........................................................................................................ 17 4.1. Effect of CO2 Injection Rate .................................................................................. 17 4.1.1. Motivation and Simulation Procedure ........................................................ 17 4.1.2. Simulation Results ...................................................................................... 17 4.2. Effect of CO2 Injection Strategy ............................................................................ 20 4.2.1. Motivation and Simulation Procedure .......................................................... 20 4.2.2. Simulation Results ........................................................................................ 21 4.3. Effect of Oil Viscosity ........................................................................................... 25 4.3.1. Motivation and Simulation Procedure .......................................................... 25 4.2.2. Simulation Results ........................................................................................ 26 4.4. Effect of Oil Zone Thickness ................................................................................. 27 4.4.1. Motivation and Simulation Procedure .......................................................... 27 4.4.2. Simulation Results ........................................................................................ 28 4.5. Summary ................................................................................................................ 29 ix 5. Analysis of Simulation Results using an Objective Function Based on Economic Conditions ......................................................................................................................... 30 5.1. Objective Function to Quantify Economic Success of a Simulation ..................... 30 5.2. Economic Analysis of Modifying the CO2 Injection Rate..................................... 31 5.3. Economic Analysis of Modifying the CO2 Injection Strategy............................... 33 5.4. Economic Analysis of Modifying the Oil Type ..................................................... 37 5.5. Economic Analysis of Modifying the Oil Bank Thickness ................................... 39 5.6. Summary ................................................................................................................ 41 6. Conclusions ................................................................................................................... 43 6.1. Summary of Results ............................................................................................... 43 6.2. Future Work ........................................................................................................... 43 Nomenclature .................................................................................................................... 45 References ........................................................................................................................
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