Integrated evaluation of interfacial tension and wettability alteration for surfactant screening under reservoir conditions for geological carbon storage

Surfactant-assisted CO 2 injection has been proposed as a strategy for improving injectivity in geological carbon storage (GCS) by mitigating capillary-controlled flow resistance. In this study, the interfacial behavior of three representative surfactants—an anionic surfactant (SDBS) and two nonionic surfactants (Pluronic L31 and POA-25R2)—was systematically investigated under reservoir-relevant conditions. Critical micelle concentration (CMC), interfacial tension (IFT), and contact angle were evaluated under reservoir conditions, and their combined effects were quantified using the capillary factor. The results demonstrated that surfactant performance under reservoir conditions deviates significantly from observations made under ambient conditions, most notably through a substantial reduction in the CMC. Among the tested surfactants, SDBS exhibited the greatest reduction in IFT, whereas POA-25R2 induced the most pronounced wettability alteration toward intermediate-wet conditions, resulting in the largest reduction in the capillary factor. Quasi-static pore network simulations incorporating these interfacial properties showed that capillary factor reduction lowered capillary entry pressure and increased CO 2 saturation under capillary-dominated conditions. Additional analysis at elevated temperature and salinity showed that POA-25R2 retained measurable interfacial activity in 3.5 wt% NaCl brine, although its effectiveness was attenuated at 80°C. These findings underscore the necessity of integrated evaluations of IFT, wettability, and CMC under reservoir conditions and provide a dosage-aware framework for surfactant screening in injectivity-focused GCS applications.