Core-Scale Experimental Evaluation of Low-Salinity Waterflooding, AOS Surfactant Flooding and N2-WAG for Controlling Capillary Hysteresis and Enhancing Oil Displacement in Porous Media

Capillary hysteresis significantly affects oil displacement efficiency in porous media by influencing residual oil trapping, relative permeability scanning behavior, and saturation history-dependent flow resistance. This paper evaluates core-scale EOR strategies designed to influence capillary trapping and saturation-history-dependent displacement behavior, with the aim of increasing displacement efficiency using sandstone core samples representing seven parent-core materials. Reservoir conditions were simulated through conventional high-salinity brine flooding, low-salinity waterflooding (LSWF), chemical EOR using alpha olefin sulfonate (AOS) surfactant, and low-salinity water-alternating-gas (WAG) flooding with nitrogen. After LSWF, separate batches of core samples were retrieved from the remaining material of the respective parent cores C1 to C7. Thus, the CEOR and N2-WAG operations were conducted on different core samples that were separately processed and initialized. HSWF recovered an average of 53.15 ± 5.42% of OOIP at 56,300 ppm salinity and left a residual oil saturation of 34.57 ± 2.99% pore volume (PV). Among the brines examined, 7600 ppm provided the highest recovery of 61.31 ± 5.69% OOIP and left a residual oil saturation of 28.52 ± 3.36% PV. With further dilution of the brine solutions, performance decreased to 54.50 ± 5.96% OOIP recovery at 3000 ppm and 49.00 ± 6.24% OOIP at 1000 ppm. Further tests showed even worse results due to increasing solid content in the effluent, permeability impairment, and swelling of cores. Volume-weighted mean effluent solids content was 13.99 mg/L at 7600 ppm, 95.01 mg/L at 3000 ppm, and 225.00 mg/L at 1000 ppm. Micro-CT imaging of C1 for 3000 ppm pre- and post-flood cores indicated localized restriction of the resolved pore space. These results show that swelling and migration of fines contributed to the adverse responses at the lowest salinity. In contrast, a 0.5 wt% AOS formulation on a commercial-product basis (0.195 wt% active AOS) recovered 69.30 ± 6.32% OOIP with a residual oil saturation of 22.60 ± 4.00% PV, while N2-WAG recovered 73.06 ± 6.23% OOIP with a residual oil saturation of 19.82 ± 4.01% PV. Consequently, the overall outcomes correlate with less residual trapping and better displacement under salinity control, interfacial-tension reduction, and cyclic gas–water saturation changes.