No abstract

We report an experimental study of the behavior of CO2 and N2 foams in granular porous media using X-ray computed tomography. In the experiments either CO2 or N2 gas is forced through natural porous media initially saturated with a surfactant solution, a process known as surfactant-alternating-gas or SAG. The CO2 was either under sub- or supercritical conditions, whereas N2 remained under subcritical conditions at all experimental conditions. We found that CO2 injection following a slug of surfactant can considerably reduce its mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require space to develop into foam. The space is longer for N2 (larger entrance effect) and increases with increasing gas velocity. Moreover, the ultimate liquid recovery by CO2 foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases are discussed in detail.

We report the study of flow of CO 2 and N 2 foam in natural sandstone cores containing oil with the aid of X-ray computed tomography. The study is relevant for enhanced oil recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water-oil transition occurring in oil reservoirs. The CO 2 was used either under subcritical conditions (P ) 1 bar) or under supercritical (immiscible (P ) 90 bar) and miscible (P ) 137 bar)) conditions, whereas N 2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In a typical foam experiment water flooding was followed by the injection of 1-2 pore volumes of a surfactant solution with alpha olefin sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil. At low-pressure experiments (P ) 1 bar) in the case of N 2 , weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO 2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above the critical point (P ) 90 bar), CO 2 injection following the slug of surfactant reduces its mobility when there is no oil. Nevertheless, when the foam front meets the oil, the interface between gas and liquid disappears. The presence of the surfactant (when foaming supercritical CO 2 ) did not affect the oil recovery and pressure profile, indicating the detrimental effect of oil on foam stability in the medium. However, at miscible conditions (P ) 137 bar), injection of surfactant prior to CO 2 injection significantly increases the oil recovery.