Wettability determines the spreading or adherence behavior of fluids at the solid surface and significantly influences the displacement and entrapment of multiphase fluids in porous media. The present study sets out to determine how wettability controls the imbibition physics of oil and water in a matrix–fracture medium. The displacement and distribution characteristics of fluids, the types of flow regimes, and the fluid morphology under various conditions were revealed in depth. The influences of wettability on oil recovery and energy conversion were analyzed. Finally, the application of the conventional scaling model to simulated imbibition data was also discussed. Results show that the imbibition front is complete and stable in a water-wet medium with the one-end open boundary condition. There are three flow regimes occurring in countercurrent imbibition, depending on the wettability and Ca (capillary number) situations. Increasing θ (contact angle, the affinity of wetting phase to the solid) or Ca can shift the flow pattern from the capillary regime to the capillary-viscous regime to the viscous regime. Additionally, the imbibition oil recovery is greatly affected by wettability, and a more water-wet state does not signify a larger oil recovery. There is a power-law relationship between the oil recovery and the fractal dimension of the nonwetting phase. On the other hand, we performed the energy conversion analysis in the strongly water-wet condition. The external work is positive for both the capillary-viscous and viscous regimes and declines with the decreased Ca. Oil recovery could be linked to the surface energy ratio to some degree, which is relevant to Ca. For the capillary regime, oil recovery is proportional to the final reduced surface energy and does not have an evident relationship with the dissipation energy ratio. Through scaling the recovery factor data vs time via the linear, the power-law, and the conventional models, we find that the conventional scaling model can be used to fit the data point, and the fitting performance is good when Ca is relatively high. However, the linear model is more appropriate when scaling the data in low Ca. Overall, our pore-scale simulation study could pave the way for a further step toward investigating other influencing factors on imbibition behaviors of fluids in more complex media like natural rock materials, which exhibit strong heterogeneity of wettability and pore structure.

Nanopores with various shapes are well developed in unconventional reservoirs, and the transport phenomena of solutions in these reservoir rocks are ubiquitous but have not yet been fully understood. This article investigates the flow characteristics of solutions in hydrophilic slit nanopores through the combination of a modified Poisson–Boltzmann (MPB) model and the modified Navier–Stokes (NS) equation. To account for the nanoconfinement effects on ion concentration and fluid viscosity, an electrochemical potential term is used in the MPB model and a varying viscosity model (VVM) is introduced in the NS equation. The model rationality is first confirmed, and then the influences of ion concentration and pore size on the transport capacities of solutions in nanopores are illuminated. In addition, the hydrodynamic features of liquids in nanopores and the limitations of this coupled model are discussed as well. The results show that the dimensionless apparent permeability of the slit increases with an increase in ion concentration and pore size. The relative contributions of the electroviscous effect (EVE) and VVM to the total flow resistance reveal different varying trends as ion concentration or pore size increases, which is greatly related to the surface charge density and the sign of the charged wall. Additionally, although the effects of EVE and VVM resulting from the nanoconfinement are considered, average velocities of fluids in nanopores exhibit a linear correlation with the pressure gradient, which cannot be used to explain the nonlinear flow mechanism occurring in tight reservoirs. Furthermore, we also compare the velocity difference between the classical PB and MPB models. We hope that the findings in this work can help improve our understanding of the characteristics of liquid flow in tight reservoirs and provide vital practical implications for diverse engineering applications.