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.
Highlights
The amounts of oil produced during primary and secondary oil recoveries are around one-third of the original oil in place
The results indicate that fluid pressure, experimental temperature, and injection rate significantly influence the differential pressure profile, cumulative produced volumes, endpoint CO2 relative permeability, and oil recovery
The data indicate that, as fluid pressure increases, the capillary forces have a stronger impact on the differential pressure profile of supercritical CO2 –oil displacements than that on subcritical CO2 –oil displacements
Summary
The amounts of oil produced during primary and secondary oil recoveries are around one-third of the original oil in place. The growing world energy demand, decline in the exploration of new oil reservoirs, and maturity of oil fields that produce most of the hydrocarbons are motivating oil companies to develop new enhanced oil recovery techniques [1]. Enhanced oil recovery techniques are categorized into three main methods: thermal, chemical, and gas recovery methods. Thermal recovery methods have their limitations; they are not suitable for heavy oil reservoirs if the formations are thin (1000 m) due to heat loss to surrounding formations [2]; they are not suitable for reservoirs with low permeability and low oil saturation [3]. Chemical flooding methods are a good candidate, but they are generally not implemented because of their high cost. Application of CO2 for CO2 enhanced oil recovery (CO2 -EOR) has gained much momentum as it can be used to enhance oil recovery with the added benefit of reducing CO2 emissions
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