Effect of temperature and surfactant concentration on CO2 foam strength in Bentheimer sandstone at reservoir conditions

Surfactant-stabilized CO 2 foams reduce CO 2 mobility and improve CO 2 sweep efficiency during CO 2 enhanced oil recovery (EOR) and storage processes. However, the behavior of nonionic surfactant-stabilized CO 2 foams near their cloud-point regions remain under-documented at reservoir conditions. Cloud-point proximity impacts nonionic solubility and interfacial activity, which controls lamellae and foam strength at reservoir conditions. Foam generation and strength was evaluated in steady-state corefloods using Bentheimer sandstone at 180 bar and 40 °C and 60 °C. A water-soluble nonionic alcohol-ethoxylate (Surfonic L24-22), at concentrations of 0.10 wt% and 1.0 wt%, were co-injected with supercritical CO 2 . Foam quality scans measured apparent foam viscosity ( µ app ) as a function of gas fraction ( f g ) whereas foam rate scans evaluated µ app as a function of injection velocity. With surfactant solution (0.10 wt%), strong foam with µ app = 125 cP and 81 cP was generated at 40 °C and 60 °C, respectively. Weaker foam at higher temperatures was related to faster film drainage from lower CO 2 density/viscosity and reduced interfacial activity near the cloud-point region. Increasing surfactant concentration generated stronger and more stable foams and shifted the optimal gas fraction (highest µ app ) from f g = 0.80 (0.10 wt%) to f g = 0.50 (1.0 wt%). Foam rate-scans at f g = 0.70 exhibited shear-thinning behavior and apparent viscosity decreased by ~ 35% (40 °C) and ~ 67% (60 °C) between injection velocities of 16 and 4 ft/day. Overall, the results verify CO 2 mobility control by Surfonic L24-22 up to 60 °C and isolate cloud-point proximity as a primary control of foam strength. The data set reported provides simulator-ready inputs for upscaling and optimizing CO 2 -foam EOR and storage processes, as improved CO 2 -foam parameters directly enhance model calibration and upscaling reliability.