Modeling the combined effect of injecting low salinity water and carbon dioxide on oil recovery from carbonate cores

This paper investigates the combined effect of injecting low salinity water (LSWI) and carbon dioxide (CO₂) on oil recovery from carbonate cores. The combined effect of LSWI and CO₂injection on oil recovery was predicted by performing several ID simulations using measured reservoir rock and fluid data. These simulations included the effect of salinity on both miscible and immiscible continuous gas injection (CGI), simultaneous water-alternating-gas (SWAG), constant water-alternating-gas (WAG), and tapered (WAG). For SWAG and constant and tapered WAG, both seawater and its dilutions were simulated. CO₂was injected above its minimum miscibility pressure. Baker's three-phase relative permeability model was modified to account for the effect of salinity on the water/oil relative permeability. The results show that SWAG, whether using seawater or its dilutions, outperformed all other tertiary injection modes in terms of oil recovery. Moreover, the SWAG process has both the highest tertiary recovery factor (TRF) and the lowest utilization factor (UF). This study highlights the advantage of using low salinity water along with miscible CO₂. The miscible CO₂displaces the residual oil saturation whereas the low salinity water boosts the production rate by increasing the oil relative permeability through wettability alteration towards more a water-wet state. The latter finding was supported by comparing our simulations with the two corefloods reported by Chandrasekhar and Mohanty (2014). These corefloods were conducted in SWAG tertiary mode using seawater and its dilutions. Fractional flow analysis shows that SWAG with low salinity water requires less injected solvent compared to SWAG with seawater and miscible CGI.