Nanomodel visualization of fluid injections in tight formations

The transport and phase change of a complex fluid mixture under nanoconfinement is of fundamental importance in nanoscience, and limits the recovery efficiency from tight oil reservoirs (<10%). Herein, through experiments and supporting theory we characterize the transport and phase change of a nanoconfined complex fluid mixture. Our nanofluidic platform, nanomodel, replicates shale reservoirs in terms of mean pore size (approximate to 100 nm), permeability (approximate to D) and porosity (approximate to 10%). We screen conditions for the most promising shale EOR strategies, directly quantifying their pore-scale efficiency and underlying mechanisms. We find that immiscible gas (N-2) flooding presents a prohibitively large capillary pressure threshold (approximate to 2 MPa). Miscible (CO2) gas flooding eliminates this threshold leading to film-wise stable oil displacement with high recovery efficiency. Strong capillary forces present barriers as well as opportunities for recovery strategies unique to nanoporous reservoirs by transitioning from a miscible to an immiscible condition locally within the reservoir. These results quantify the fundamental transport and phase change mechanisms applicable to nanoconfined complex fluids, with direct implications in unconventional oil as well as nanoporous media more broadly.