Integrated Experimental and Core-Scale Modeling Study of Hybrid Low-Salinity Surfactant EOR in Tight Carbonates

Water-based enhanced oil recovery (EOR) techniques continue to attract interest because of their technical practicality and economic feasibility. Hybrid low-salinity surfactant flooding is a promising EOR strategy for carbonate reservoirs; however, the coupled effects of low-salinity brine, surfactant addition, wettability alteration, electrostatic modification, and capillary pressure reduction remain difficult to isolate. This study investigates hybrid low-salinity surfactant flooding in restored tight carbonate cores using integrated experimental measurements and core-scale numerical modeling. The experimental workflow included oil–water interfacial tension (IFT), zeta potential, contact angle measurements using a custom-designed HPHT imbibition cell, and reservoir-condition HPHT coreflooding under sequential and standalone injection schemes. The sequential flood evaluated the transition from seawater (SW) to 1%diluted seawater (1%dSW) and then to 1%dSW+A-1 surfactant, while standalone floods assessed the direct displacement performance of 1%dSW and 1%dSW+A-1. Dilution from SW to 1%dSW increased IFT from approximately 10.2 to 14.9 mN/m, indicating that the recovery improvement during 1%dSW injection was not caused by IFT reduction. Instead, zeta potential and contact angle results indicated progressive electrostatic modification and wettability alteration toward a less oil-wet state. The contact angle decreased from approximately 123° for SW to 101° for 1%dSW and further to 84° after A-1 addition. In contrast, 1%dSW+A-1 reduced IFT sharply to approximately 0.178 mN/m at 0.2 wt%, lowering the estimated capillary pressure magnitude and weakening capillary trapping. Sequential coreflooding showed that SW recovered 42.65% OOIP, followed by an additional 24.21% OOIP from 1%dSW and 9.11% OOIP from 1%dSW+A-1. Standalone 1%dSW and 1%dSW+A-1 recovered approximately 58.44% and 65.82% OOIP, respectively. Core-scale models reproduced the main recovery and pressure drop trends using zeta potential-guided relative permeability and capillary pressure functions supported by surface complexation modeling concepts. Overall, 1%dSW+A-1 improved oil displacement through a synergistic mechanism in which low-salinity brine stabilized the water film and altered wettability, while A-1 surfactant reduced IFT and weakened capillary trapping. The integrated experimental and modeling workflow provides a mechanistic basis for evaluating hybrid low-salinity surfactant flooding and for linking laboratory-measured interfacial properties to effective core-scale rock–fluid functions.