The Effects\nof Brine Salinity and Surfactant Concentration\non Foam Performance in Fractured Media

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