The work presented in this paper evaluates the potential of Low-Tension Gas (LTG) as an alternative to polymer flood for displacing the surfactant slug in a chemical EOR process in ultra-high salinity (above 189,000 ppm TDS), high temperature (above 85°C) sandstone reservoirs. The LTG process involves the use of surfactant and gas to achieve the mobility control required to displace the micro-emulsions and the crude oil. The optimal formulation of surfactants is identified to obtain good oil/water microemulsion phase behavior and desirable high optimum salinity. The latter feature allows the LTG process to work with a wide variation of injection brine salinity or in-situ salinity gradient. The optimal injection strategies are then determined through a series of oil recovery core floods with co-injection of gas and the surfactant solution. Tertiary recovery of up to 90% of the residual OIP was achieved for cores with 150–400md air permeability. The high optimum salinity that is closest to the formation brine salinity was found to give the highest incremental oil recoveries. Macroscopic stability of displacement fronts was studied via pressure derived mobility ratios. Approximate parity of relative mobility of injected fluids was observed with respect to relative mobility of displaced water at true residual oil saturation and interpreted relative mobility of a formed oil bank. These results indicate that in-situ foam propagation was present which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding. By replacing polymer with foam, chemical EOR methods can be expanded into formations where the use of polymer is impractical.

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