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The hydrodynamic behavior of carbon dioxide (CO2) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO2 plume stabilization. A numerical model of the subsurface at a proposed power plant with CO2 capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO2 is injected over a 4-year period, and the subsequent evolution of the CO2 plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO2 between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO2 plume is effectively immobilized at 25 years. At that time, 38% of the CO2 is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO2 saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.

Investigation of CO2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation