Foam properties in porous media and in the bulk phase were evaluated for possible correlation by using two laboratory assessment methods. The foaming ability of surfactant with dense Carbon Dioxide (CO2) and durability of foam in the bulk phase were first tested in a device designed to select surfactants that might be suitable for the stabilization of bubble-films or lamellae at reservoir conditions. The flowing properties of foam were then evaluated in a composite core consisting of two differing permeability sections, which are in capillary contact and arranged in series. The assessment results indicate that effectiveness of mobility reduction of foam in porous media is strongly correlated with the stability of foam in the bulk phase. The mobility reduction factor also increases with the reduction of interfacial tension between CO2 and aqueous phase. Depending on the type of surfactant and its concentrations, some surfactants led to foams having a favorable mobility dependence on rock permeability (selective mobility reduction) whereas others did not.


CO2-foam has been long realized as an effective mobility reducing agent for CO2 flooding in oil recovery process. Recent research indicates that some CO2-foams show an exciting additional characteristic, selective mobility reduction (SMR). SMR in foams reduces the mobility of CO2 by a greater fraction in higher than in lower permeability cores in laboratory experiments. Unlike Darcy flow of ordinary fluids in rocks where the mobility is proportional to rock permeability, the mobility of foam with SMR is less than proportional to core permeability and foam flows through higher permeability rocks at a lower rate than would be expected for the given pressure gradient. With such a property, foam can flow at the same velocity in high and low permeability regions in the reservoir formations, preserving the uniformity of the flood front while propagating through rocks with non-uniform permeability. Presumably, this can reduce the effect of both vertical and horizontal rock heterogeneity in the reservoir formation, and as a consequence, the use of a CO2-foam showing SMR would delay CO2 breakthrough and lead to a high displacement efficiency in heterogeneous reservoirs.

Because of the great potential of using foam to improve oil recovery in CO2 floods, it would be beneficial to identify more surfactants that induce SMR for foam flooding. In the past, most of the reported screening studies for identifying promising foams have employed some forms of foam stability measurements for the initial screening. Maini et al. and Strycker et al. used high pressure, high temperature cell test to screen surfactants in their steam foam work. In a nitrogen-foam study, Khatib et al. proposed measuring the limiting capillary pressure as a way to screen surfactants for IOR processes. Other researchers used high pressure cell tests to examine the stability of foam as a prescreening tool for their CO2-foam studies. All these screening results were later compared with the performance of foam flooding in porous media. It was believed that foam stability derived from screening tests can be used in the prediction of the performance of foam for mobility reduction. However, the prediction was seldom extended to examine the dependence of foam mobility on rock permeability or SMR as observed in the laboratory. It was once reported by Yang et al. that stable foams (as determined by the screening test) give less favorable or even unfavorable permeability effect in separate and small size core samples. In other words, less favorable SMR occurs in the flowing foam when the bulk foams are more stable. This phenomenological correlation is interesting and should be useful in identifying promising surfactants for the foam process, if it can be verified with core samples under conditions that simulate those found in reservoirs.

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