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Supercritical carbon dioxide (CO2) flooding is a widely used method in tertiary oil recovery; however, there are many challenges such as inefficient gas utilization, poor sweep efficiency and low oil recovery due to viscous fingering and gravity segregation. One recent development is the application of CO2 foam in order to reduce the CO2 mobility, especially in high permeability zones of the reservoir. However, the efficiency of the CO2 foam often decreases sharply during flooding as a result of contact with crude, adsorption of surfactants, high salinity in formation water and high reservoir temperature. Surfactant formulations which have better tolerance to these factors can greatly enhance the CO2 utilization, reduce the cost of surfactant, and improve the oil recovery. A series of formulations, including various surfactants and corresponding micro-emulsions, were evaluated as CO2 foaming agents in lab-based heterogeneous sandstone equipment at reservoir temperatures and pressures. This paper describes formulating high temperature CO2 foaming agent with co-surfactants and in a micro-emulsion system to improve crude, salt and temperature tolerance and minimize adsorption in order to place the foamer further into the formation.

The objective was to identify surfactants for Enhanced Oil Recovery by brine-oil interfacial tension reduction for a carbonate reservoir at ~ 25ºC and salinity of ~11,000ppm TDS; thus, Alkyl Propoxy Sulfates and their blends with sulfonates were evaluated to determine optimal salinity and solubilization parameters with dead crude. Imbibition experiments were performed in reservoir and dolomite outcrop cores to determine the oil recovery efficiency of surfactant systems, selected from their phase behavior test results, with potential to recover oil. Tridecyl alcohol 13 propoxy sulfate (TDS-13A) with an oil solubilization parameter of ~8 at reservoir salinity was found to recover greater than 75% oil in imbibition experiments, at a concentration as low as 0.5wt%. The adsorption of surfactants on dolomite was measured at static and dynamic conditions; the adosprtion of TDS-13A was found to be ~ 0.26-0.34 mg/g reservoir rock. The effect of solution gas on surfactant phase behavior, up to 600-psi, was evaluated for methane, ethane, carbon-dioxide, and separator gas at 30ºC. Methane had minimal effect on surfacatant optimal salinity, lowering it by ~2%/100psi solution gas, followed by carbon-dioxide which reduced it by ~11%/100psi. Ethane had a much more pronounced effect, reducing optimal salinity by ~46%/100psi solution gas.

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