Effect of CO₂ Pressure on Microemulsion Phase Behavior and Displacement Efficiency in Sandstones

Low Tension Gas flooding is an emerging technology that can significantly reduce the carbon footprint of enhanced oil production through geologic carbon sequestration. It utilizes field gas and captured CO2 as a mobility control agent to improve the efficiency of surfactant for generating oil–water microemulsions in situ to enhance oil mobilization. This work extends previous research on the effect of hydrocarbon gas on microemulsion phase behavior to investigate the impact of increasing CO2 pressure from atmospheric to 2000 psi on microemulsion formation. The phase behavior test results reveal a substantial reduction of approximately 10,000 ppm in the optimum salinity for Type III microemulsions at elevated CO2 pressures. Another striking observation is the increase of the salinity limit for Winsor Type I microemulsion and the decrease of minimum salinity required for Winsor Type II microemulsion formation as the CO2 pressure increases. This phenomenon could be related to the observed instability of microemulsions at elevated pressures. These observations also suggest that the selection of injection water salinity and surfactant in an LTG process design must take into account the impact of CO2 pressure on microemulsion formation in situ as this process typically performs best within the Winsor Type III salinity environment. Indeed, core flooding experiments confirmed that an appropriate adjustment of injection salinity for a system pressure of 1200 psi with CO2 could result in more than doubling the oil recovery rate, a 50% increase in ultimate oil recovery, and a 60% decrease in residual oil saturation for tertiary LTG floods. These results offer valuable insights into optimizing carbon sequestration strategies.