Abstract

Three carbon dioxide (CO₂) foam flooding parameters are addressed in this paper: optimum gas fractional flow, surfactant adsorption behavior, and oil recovery versus CO₂/aqueous phase injection methodologies. Experimental test conditions were selected to simulate some of the reservoirs in west Texas (1540 psig and 110°F). All tests in this study were conducted in fired Berea sandstone cores to minimize core property changes during a series of CO₂ foam flooding tests. CO₂ and aqueous phase were co-injected during the test. The CO₂ foam flow behavior in the absence and presence of oil and the optimum oil recovery methodologies associated with different stages are described in this paper.

This study demonstrates that, with similar residual oil in the core, CO₂ foam had higher oil recovery than CO₂-brine coinjection. Additional oil was recovered with CO₂ foam injection following CO₂-brine co-injection. However, no additional oil was recovered if CO₂ foam injection was applied first. The surfactant adsorption equilibrium was characterized by the occurrence of foam.