Dependence of Transient Foam Behavior on Enriched Gas Flood Maturity in Sandstone

This work evaluated the effect of enriched gas flood maturity and mobile water on transient foam behavior and oil recovery under high-pressure (2000 psi), moderate-temperature (38 °C) and salinity (20,000 ppm NaCl) conditions in high-permeability Bentheimer sandstone. A synthetic gas mixture containing relatively high contents of CO2 (20%) and propane (26%) was used to simulate the enriched field gas. Screening of foaming surfactants including alpha olefin sulfonates and a betaine for good foamability and stability as well as low adsorption on the sandstone indicates that the alpha olefin sulfonate with a longer chain length was the best candidate for foaming the enriched gas in the presence of oil. Core flooding experiments conducted with this surfactant showed a strong impact of gas flood maturity and injection foam quality on both the transient foam behavior and oil displacement efficiency. Foam injection at residual oil saturation (about 14%) to a gas–brine flood exhibited robust foam propagation. The presence of mobile oil before foam injection due to the immaturity of the gas–brine flood (e.g., oil saturations above 50%) posed a detrimental effect on the rate of foam viscosity buildup. However, water injection during the pre-foam flood strongly supported foam generation even at relatively high oil saturations. A further evaluation of water contribution to enhancing foam propagation by adjusting foam quality showed that the water injection strategy before and during foam flooding should be optimized to improve both transient foam behavior and gas–oil contact for enhanced oil sweep efficiency.