We report an experimental study of CO2 and N2 foam flows 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 CO2 was used either under sub- or under super-critical (immiscible and miscible) conditions, whereas N2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In each 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 N2, 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. CO2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above critical point (P=90 bar), CO2 injection following the slug of surfactant reduces its mobility in absence oil. Nevertheless, when the foam front meets the oil it becomes highly diffuse. The presence of the surfactant (when foaming super-critical CO2) hardly improves oil recovery and or modifies the pressure drop profile, indicating the detrimental effect of oil on foam stability in the medium in this specific case. However, at miscible conditions, injection of surfactant prior to CO2 injection significantly increases the oil recovery.

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