Nanofluid-Based Foam for Enhanced Oil Recovery in Fractured Carbonates

The ability of nanoparticles (NPs) to stabilize surfactant-based foams has been established in the past and shown to improve oil recovery from conventional porous media; however, their application in fractured tight rocks has been very limited, especially in carbonates, due to the experimental challenges associated with these rocks. In this study, inorganic NPs (silica and alumina) and organic ones (graphene quantum dots, GQDs) were used with an amphoteric surfactant (cocamidopropyl hydroxysultaine) to generate in situ methane/brine foams capable of displacing oil inside proppant-packed fractured carbonate cores (Minnesota Northern Cream). The carbonate samples and proppants were statically aged to alter their wettability to oil-wet with the utilization of high-salinity brine (200,000 ppm). The efficacy of foam flooding was investigated under reservoir conditions (3,500 psi and 115 degrees C) and quantified based on the apparent viscosity of the generated foam, the mobility reduction factor (MRF), and the recovery factor from the tight matrix. The three nanofluids were compared according to their ability to generate stable foams that can reduce gas mobility and increase viscous pressure gradients in high-permeability fractures, resulting in improved sweep efficiency. The negatively charged NPs (i.e., silica and GQDs) showed a better ability to stabilize foam than positively charged NPs (i.e., alumina) owing to the electrostatic repulsion between the former NPs and proppant grains. In addition, GQDs showed a better stabilizing effect than silica due to their structure, which promotes exceptional chemical stability under harsh reservoir conditions and strong adsorption at gas/water interfaces, allowing for the creation of interconnected lamellae films and the generation of smaller and more uniform gas bubbles. The results of this study also demonstrated the impact of rock-fracture permeability contrast on foam performance. More specifically, fractured cores with a lower permeability contrast (i.e., 2,100) produced more oil than tighter samples with a higher permeability contrast (i.e., 63,751). This behavior was attributed to the higher entry capillary pressure experienced in the high-permeability contrast systems, which limited the fracture-matrix interactions and prohibited the diversion of gas from the fracture to the oil-filled pores.