Assessment of the CO2 sequestration potential of the Morrow-B Sandstone in the Farnsworth Unit, Northern Texas through numerical modeling and laboratory batch reaction experiments
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The objectives of this study were (1) to investigate the injection and storage of CO2 into the Morrow B Sandstone through numerical non-isothermal reactive transport models, (2) to establish a comparison of storage efficacy based on three reactive transport simulators, and (3) to assess the impact of injected CO2 on the sandstone minerals through laboratory batch reaction experiments. The studies presented are part of ongoing efforts of the Southwest Partnership for CO2 Sequestration (SWP) to evaluate the CO2 sequestration potential of the Morrow B Sandstone reservoir in the western half of the Farnsworth Unit (FWU) in conjunction with enhanced oil recovery. The numerical models incorporate detailed site-specific reservoir properties and fluid injection histories of multi-phase fluids, heat transport, solute transport, and geochemical reaction. The simulations extend for 1000 years. The first 25 years correspond to the anticipated period of the field operations during which CO2 injection occurs. The remaining simulation time is intended to forecast the long-term storage effectiveness of the reservoir. The laboratory experiments involved thin sections of coarse- and fine-grained facies of the Morrow B Sandstone immersed in formation water containing variable concentrations of CO2. A first set of experiments was run for 61 days and a second set of experiments was run for 72 days. Before the experiments were started and after each experimental run, the mineral abundances in the thin sections were analyzed using a scanning electron microscope (SEM) technique called Tescan Integrated Mineral Analyzer (TIMA), and the composition of the formation water was determined using ICP-AES. The numerical simulation results predict increases in reservoir pressure during the initial 25-year period of injection of water and CO2, after which fluid pressure gradually returns to pre-injection levels. The models predict that the largest fraction of the injected CO2 dissolved into oil, followed by dissolution into the formation water, the formation of carbonate minerals, and occurrence as a separate immiscible gas phase. The injected CO2 was generally confined to an approximately 500 m radius around the injection wells. The concentration of CO2 in the formation water and the fraction of CO2 present as an immiscible gas phase decreased over time with the ongoing precipitation of carbonate minerals, principally dolomite. The laboratory batch reaction experiments also showed dolomite to be the principal carbonate mineral precipitated as a result of introduction of CO2 into the Morrow B formation water. The numerical models and laboratory experiments were also consistent with one another in showing calcite, albite, muscovite, kaolinite, and illite to dissolve and silica to precipitate. In neither the numerical models nor the laboratory experiments, changes in mineral abundance, did not lead to significant changes in porosity. The results of the studies are encouraging for the feasibility of large-scale CO2 sequestration in deep sandstone hydrocarbon reservoirs containing moderately saline formation water.
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Ph. D.