Development of a chemically optimized CO2 foam in saline reservoirs: pore-scale visualization, and CFD modeling

Stable carbon dioxide (CO 2 ) foams are essential for enhanced oil recovery (EOR) and carbon capture, utilization, and storage (CCUS) under saline reservoir conditions. Although mixed surfactant systems can improve foam stability, systematic screening of widely used surfactants in binary configurations under combined salinity and oil exposure remains limited, and mechanistic validation at the pore scale is rarely integrated. In this study, four widely used surfactants, alpha olefin sulfonate (AOS), sodium dodecyl sulfate (SDS), sodium dodecylbenzenesulfonate (SDBS), and cetyltrimethylammonium bromide (CTAB), were evaluated between 1000 and 7500 ppm. Optimal single-surfactant concentrations were AOS1000 and CTAB1000 with half-lives of approximately 18–20 min, SDS5000 (∼11 min), and SDBS2500 (∼4.5 min). Binary screening identified AOS:CTAB as the most effective system. Ratio optimization showed that 6:1 minimized bubble size (∼380 µm), reduced drainage (∼41 percent at 120 min), and achieved the longest half-life (∼45 min). Increasing NaCl concentration from 0 to 100,000 ppm enlarged bubbles from ∼ 400 to ∼ 690 µm while maintaining structural coherence. Mechanistic interpretation was supported by hydrophilic–lipophilic balance (HLB) analysis, rheology (1–100 s⁻ 1 ), ultraviolet–visible (UV–Vis) spectroscopy, Fourier-transform infrared (FT-IR) analysis, and scanning electron microscopy (SEM). Pore-scale micromodel experiments demonstrated oil recovery of approximately 85–90 percent for CO 2 foam compared with 55–60 percent for water and 40–45 percent for CO 2 . Computational fluid dynamics (CFD) simulations reproduced improved mobility control. These results demonstrate that optimized binary surfactant systems enhance CO 2 foam stability under salinity and oil exposure, while further high-pressure, high-temperature (HPHT) validation is required before field-scale application.