Shale oil reservoirs contain complex pore networks where fluid distribution and displacement are governed by intricate capillary and wettability effects. This study combines pore-scale computational fluid dynamics (CFD) simulations and laboratory-scale experiments to investigate fluid flow and oil recovery behavior in shale formations. Using the Volume of Fluid method, we simulate two-dimensional (2 D) displacement in porous media with varying heterogeneity and wettability. Results show that uniform pore structures exhibit a broader swept region, whereas non-uniform structures promote preferential flow along high-permeability pathways, leading to lower recovery. Experimental validation was performed using high-temperature, high-pressure static imbibition tests on shale core samples from four lithofacies regions, supported by 2 D nuclear magnetic resonance and interfacial tension (IFT) measurements. CO2 and surfactant-enhanced fluids demonstrated superior oil mobilization in organic matter pores, while water-based fluids primarily recovered oil from clay-bound micropores. An energy-based analysis revealed that capillary-driven imbibition accounts for over 70% of total recovery, surpassing elastic expansion and gas dissolution contributions. IFT measurements confirmed the effectiveness of low-IFT fluids in altering wettability and improving pore accessibility. Together, the integrated CFD–experimental approach offers mechanistic insights into pore-scale flow dynamics and recovery processes in heterogeneous shale systems, providing guidance for the design of targeted enhanced oil recovery strategies.
Zhao et al. (Thu,) studied this question.