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Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate Reservoirs Using Co-injection Technique

AlSumaiti, Ali M., Hashmet, Muhammad R., AlAmeri, Waleed S., Anto-Darkwah, Evans
Energy & fuels 2018 v.32 no.2 pp. 1416-1422
carbon dioxide, floods, foams, fuels, oils, permeability, salinity, surfactants, temperature, viscosity
In this research, an ethoxylated amine surfactant is co-injected with CO₂ in a series of coreflooding experiments at typical Middle Eastern reservoir conditions of high temperature, high salinity, and in situ foam is generated to reduce gas mobility in the absence of oil. The effects of reservoir permeability, injection rates, and foam quality on mobility reduction factor (MRF) and apparent viscosity of foam are discussed. In the absence of oil, an optimum foam quality of 80% is obtained using 1 wt % of surfactant solution. Shear thinning foams with viscosities ranging between 0.9 and 2.4 cP were formed at all velocities tested in this study. MRFs of 50 and 70 were obtained, respectively, in 70 and 240 mD cores at 80% foam quality, confirming that foam strength increases with increasing rock permeability. After determination of optimum foam quality and flow rate, a final coreflooding experiment was conducted in the presence of oil to quantify the effect of oil presence on foam generation and to observe the recovery performances of supercritical CO₂ and CO₂ foam for secondary and tertiary recovery injections. In the presence of oil, relatively weak foams were generated in a 50 mD core having apparent viscosities of 0.66, 1.65, and 3.29 cP at the tested co-injection flow rates of 0.2, 0.5, and 1 mL/min at 80% foam quality. A total recovery factor of 88.32% was obtained, with CO₂ and CO₂ foam floods contributing 79.34% and 8.98%, respectively.