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

Abstract

CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO2 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 CO2 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 CO2 phase, on the dynamic pressure evolution and the oil recovery performance of CO2 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 CO2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO2 phase as well as the pressure range for gaseous CO2–oil displacement. The residual oil saturation was in the range of around 0.44–0.7; liquid CO2 gave the lowest, and low-fluid-pressure gaseous CO2 gave the highest. The endpoint CO2 relative permeability was in the range of about 0.015–0.657; supercritical CO2 gave the highest, and low-pressure gaseous CO2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO2 displacements, while capillary forces were dominant in supercritical CO2 displacements. As temperature and CO2 injection rates increase, the viscous forces become more dominant than capillary forces.