The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Abstract CO 2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO 2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO 2 state is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on the injection, migration, displacement, and storage capacity and integrity of CO 2 processes. In this study, an experimental investigation has been performed to explore the impact of fluid pressure, temperature, and injection rate, as a function of CO 2 phase, on the dynamic pressure evolution and the oil recovery performance of CO 2 during oil displacement in a Berea sandstone core sample. The results reveal a considerable impact of the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO 2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO 2 phase as well as the pressure range for gaseous CO 2–oil displacement. The residual oil saturation was in the range of around 0.44–0.7; liquid CO 2 gave the lowest, and low-fluid-pressure gaseous CO 2 gave the highest. The endpoint CO 2 relative permeability was in the range of about 0.015–0.657; supercritical CO 2 gave the highest, and low-pressure gaseous CO 2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO 2 displacements, while capillary forces were dominant in supercritical CO 2 displacements. As temperature and CO 2 injection rates increase, the viscous forces become more dominant than capillary forces. View Full-Tex