Early breakthrough and poor sweep efficiency are common problems in CO2 floods. These problems result from the large viscosity contrast between the displaced and injected fluids as well as from the heterogeneity of reservoir rock. Evidence shows the presence of an aqueous surfactant solution will produce a foam with CO2, which not only controls the gas mobility but may also selectively reduce the gas mobility through regions of differing permeabilities. Experiments were conducted to test the CO2 -foam behavior in composite parallel core samples where the two permeability regions are in capillary contact. These composite cores are more characteristic of reservoir conditions. This paper examined the effect of heterogeneity on CO2 -foam in composite cores contained coaxial zones of high and low permeability.
The results from these experiments indicate that the CO2 breakthrough was delayed in the high permeability region during the transient period when surfactant solutions were used. Without surfactant the flowing quality (fraction of CO2 in total injected fluid) was lower in the low permeability region as compared with that in the high permeability region. These results indicated the favorable fluid mobility in heterogeneous core samples when foaming agents were used.