Increase of CO2 Storage in High-Salinity Carbonate Reservoirs by Foam Injection

Abstract

Abstract Oil and gas reservoirs are being considered for CO2 storage for reducing greenhouse gas emission from industrial activities. CO2 flooding in carbonate reservoirs often suffers from poor sweep efficiency due to unfavorable mobility ratio, gravity segregation, and reservoir heterogeneity. This study aims to evaluate foam flooding as a method to improve CO2 storage in a high temperature, high salinity carbonate reservoir. Several surfactants and nanoparticles were examined to identify the most effective foam formulation. Foam stability at the reservoir temperature and ambient pressure was used first to screen suitable foaming agents. The chosen foaming agents were then foamed at the reservoir temperature and pressure and their stability was observed in both the absence and presence of crude oil. Next, the foam mobility was measured through a core at 80% quality with selected foaming agents. Finally, CO2 flood and CO2-foam flood experiments were performed in carbonate reservoir cores under reservoir conditions. Many surfactants and nanoparticles exhibited instability at the high salinity and temperature conditions of this study. Based on the results of foam stability tests at the ambient pressure, a nonionic surfactant and two zwitterionic surfactants were chosen for further study. Through foam stability tests and rheology tests at the reservoir pressure, the most effective foam formulation was identified to be a combination of the nonionic surfactant Aspiro S 2410 and the nanoparticle EOR 12-V3. The addition of nanoparticles significantly increased the half-life of the foam at reservoir pressure. The presence of crude oil had a detrimental effect on CO2-foam stability. The apparent viscosity of the CO2-foam decreased as the flow rate increased, and the surfactant-nanoparticle foam exhibited higher apparent viscosity compared to the foam generated by the surfactant alone. Furthermore, core flood experiments demonstrated that foam flooding with surfactant-nanoparticle solution achieved higher incremental oil recovery and CO2 storage capacity compared to both CO−2 flooding and foam flooding with surfactant alone. In conclusion, the surfactant-nanoparticle formulation developed in this study shows promise as a CO2 foaming agent for use in high-salinity, carbonate reservoirs.