Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate (APGSHS) and zwitterionic surfactant octadecyl betaine (BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile, the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt% while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO₂ huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO₂ huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO₂ injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO₂ and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO₂ injection volume and soaking time. The lower oil recoveries under excess CO₂ injection and soaking time were attributed to limited CO₂ dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO₂ huff-n-puff in tight reservoirs with high formation pressure.