The Effects of Brine Salinity and Surfactant Concentration on Foam Performance in Fractured Media

Hydrocarbon foam performance in oil-wet fractured carbonate systems was experimentally evaluated using multiphase core flooding, surface tension measurements, micromodel flow tests, and fluorescence microscopy. The macro-scale tests were conducted at conditions of an unconventional reservoir (3500 psi and 115 °C) using two foaming chemicals with anionic and amphoteric natures. We investigated the effects of varying surfactant concentrations and brine salinities on in situ foam behavior. The foam performance was quantified in terms of the foam’s apparent viscosity, mobility reduction factor (MRF), and oil recovery from the matrix. The results from the macro-scale foam flooding indicated that the optimal concentrations for the anionic and amphoteric surfactants, leading to maximum oil recovery, were 4000 and 6000 ppm, respectively. Surface tension measurements revealed that low salinity brine has a detrimental effect on the performance of the selected foaming agents, particularly at low shear rates and high foam quality. These findings were supported by the results from micromodel investigations, which demonstrated that the smaller bubble sizes were generated at a higher brine salinity of 200,000 ppm than those formed at lower brine salinities. Furthermore, fluorescence microscopy showed the alteration of proppant wettability from oil-wet to water-wet due to the injection of foam using low brine salinity. This revealed the challenges in generating foam in such environments due to surfactant adsorption onto the surfaces of porous media. By combining the key findings from these multiscale investigations, we were able to draw robust conclusions about the effectiveness and mechanisms of surfactant-based foams in gas-injection processes.