Three carbon dioxide (CO 2 ) foam flooding parameters are addressed in this paper: optimum gas fractional flow, surfactant adsorption behavior, and oil recovery versus CO 2 /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 CO 2 foam flooding tests. CO 2 and aqueous phase were co-injected during the test. The CO 2 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, CO 2 foam had higher oil recovery than CO 2 -brine coinjection. Additional oil was recovered with CO 2 foam injection following CO 2 -brine co-injection. However, no additional oil was recovered if CO 2 foam injection was applied first. The surfactant adsorption equilibrium was characterized by the occurrence of foam.

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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.

This document is the Final Report for the project, "Improved Gas Flooding Efficiency," Department of Energy Contract No. DE-FC26-04NT15532. This study focuses on laboratory studies with related analytical and numerical models, as well as work with operators for field tests to enhance our understanding of and capabilities for more efficient enhanced oil recovery (EOR).Much of the work has been performed at reservoir conditions. This includes a bubble chamber and several core flood apparatus developed or modified to measure interfacial tension (IFT), critical micelle concentration (CMC), foam durability, surfactant sorption at reservoir conditions, and pressure and temperature effects on foam systems.Carbon dioxide and N 2 systems have been considered, under both miscible and immiscible conditions. The injection of CO 2 into brine-saturated sandstone and carbonate core results in brine saturation reduction in the range of 62 to 82% brine in the tests presented in this paper. In each test, over 90% of the reduction occurred with less than 0.5 PV of CO 2 injected, with very little additional brine production after 0.5 PV of CO 2 injected.Adsorption of all considered surfactant is a significant problem. Most of the effect is reversible, but the amount required for foaming is large in terms of volume and cost for all considered surfactants. Some foams increase resistance to the value beyond what is practical in the reservoir. Sandstone, limestone, and dolomite core samples were tested.Dissolution of reservoir rock and/or cement, especially carbonates, under acid conditions of CO 2 injection is a potential problem in CO 2 injection into geological formations. Another potential change in reservoir injectivity and productivity will be the precipitation of dissolved carbonates as the brine flows and pressure decreases.The results of this report provide methods for determining surfactant sorption and can be used to aid in the determination of surfactant requirements for reservoir use in a CO 2 -foam flood for mobility control. It also provides data to be used to determine rock permeability changes during CO 2 flooding due to saturation changes, dissolution, and precipitation.v