Oil Recovery and Surfactant Adsorption during CO2-Foam Flooding

Abstract

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. Introduction The idea of using foam for mobility control was first proposed and patented by Bond and Holbrook in 1958.1 Fried2 conducted foam drive experiments and reported a sharp pressure drop across the foam bank and reduced gas mobility through porous media. Since then, there have been extensive reviews on foam research such as Heller and Taber,3 Marsden,4 Hirasaki, 5-6 and Chang and Grigg.7 CO2 foam will increase the apparent viscosity of displacing fluid and improve the oil recovery by decreasing mobility. Several researchers have reported that CO2 foam can selectively reduce mobility of CO2 by a greater fraction in higher than in lower permeability regions. 8-10 Gas frictional flow ratio, fg, can be used to predict foam flow behavior. At a constant gas flow rate, qg, Khatib et al.11 showed that foam mobility decreases slightly with increasing fg ranging from 50% to 98%. But for fg > 98%, foam mobility increases with increasing fg. Also, Patton et al,13 Hirasaki and Lawson,14 Marsden and Khan,4 and Chang and Grigg15 found that foam mobility decreases with increasing fg. On the other hand, Lee and Heller9 reported that foam mobility increases with increasing fg. Yaghoobi and Heller10 found that foam mobility increases slightly as fg increases up to about 85%; thereafter, foam mobility increases rapidly. Persoff et al.16 found that, at a constant gas flow rate (qg), foam mobility decreases with increasing liquid flow rate (ql); The results by Lee et al.9 demonstrated that, foam mobility increases with increasing qt. At a constant total flow rate, qt, De Vries and Wit12 reported that, foam mobility decreases as fg increases until the break point (where the pressure gradient reaches the maximum); beyond that point it increases. Chang and Grigg15 also showed that foam mobility increases with increasing qt, the total mobility decreases with increasing qg.