Surfactant–Nanoparticle Foam to Increase CO₂ Storage in High-Salinity Carbonate Reservoirs

Abstract

Depleted oil and gas reservoirs are being considered along with aquifers for storage of CO2 produced during industrial activities, including power generation. CO2 injection into carbonate reservoirs often suffers from poor sweep efficiency due to an unfavorable viscosity ratio, gravity segregation, and reservoir heterogeneity. This study aims to evaluate foam flooding as a method to improve CO2 storage in a high-salinity carbonate reservoir. Several surfactants and nanoparticles were examined to identify an effective foam formulation. Foam stability at ambient and reservoir pressure was used to screen suitable foaming agents. The foam mobility was measured through a carbonate rock at 80% purity with selected foaming agents. Finally, CO2 flood and CO2-foam flood experiments were performed in carbonate reservoir cores under the reservoir conditions. Many surfactants and nanoparticles were insoluble in brine under the high salinity and temperature conditions of this study. A combination of the nonionic surfactant Aspiro S 2410 and the nanoparticle enhanced oil recovery (EOR) 12-V3 was found to be the most effective. The addition of nanoparticles significantly increased the half-life of the foam at the reservoir pressure (from 120 to 540 min). The surfactant–nanoparticle foam exhibited a higher apparent viscosity compared to the foam generated by the surfactant alone (from 28.7 to 43.2 cP at 1 ft/d). Core flood experiments demonstrated that CO2-foam flooding with the surfactant–nanoparticle solution achieved higher CO2 storage and oil recovery compared to both continuous CO2 injection and CO2 surfactant-foam flooding. In conclusion, the surfactant–nanoparticle formulation developed in this study shows promise as a CO2 foaming agent for use in high-salinity carbonate reservoirs.