Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.

Water flooding technology is widely used to improve oil recovery efficiency in oilfields. The capillary barrier effect induced by the complex pore structures in the reservoir rocks is a crucial reason for the trapping of a great deal of residual oil in oil reservoirs after water flooding. However, the formation condition along with the effect on the recovery rate of the capillary barrier under different wettability conditions should be investigated further. To bridge the gap between the microscopic mechanism of the capillary barrier effect and the macroscopic mechanism of oil displacement efficiency, a simple conceptual capillary model is constructed to obtain the formation conditions of the capillary barrier using the analysis method, and its influence on macroscopic oil displacement efficiency in the porous media model with an opening angle of 45° is systematically investigated in this study using direct numerical simulations (DNS) coupled with the volume of fluid method. The results showed that the capillary barrier effect plays a significant role in the formation of the residual oil in the reservoir rock and the contact angle and the opening angle are the primary factors for the formation of the capillary barrier. The capillary force is the driving force when the oil–water interface advances in the throat channel under water-wet conditions, while the capillary force hinders the movement of oil–water movement when the liquid flows out of the throat channel and when θ + β > 90^o. Furthermore, the highest oil displacement efficiency is achieved at the intermediate capillary number and in the case that the minimum conditions of occurrence of the capillary barrier phenomenon are satisfied. This is of great significance for controlling the optimized contact angle to further enhance the oil recovery rate of current oil reservoirs using waterflooding technology.

The importance of phase change heat storage (PCHS) in solar thermal applications is limited by the low thermal conductivity of phase change materials (PCMs) and the uneven temperature distribution during heat transfer. This study proposes to use composite fins for heat exchange in the PCHS module and integrate them into a hot-water production system (HWPS) for building heating. The effectiveness of the novel fin structure is assessed through thorough numerical simulations and experimental validation. An examination of melting fractions, temperature distribution, and flow characteristics of the molten PCMs across various fin structures indicates that increasing the lengths and quantities of the cross fins can alleviate the challenge of incomplete melting at the end of the charging process. Notably, expanding the surface area of the cross fins results in a 7.37-fold increase in the average thermal storage rate and a 781.25% enhancement in the average temperature response compared to the original design. These findings show that the new composite fin design greatly improves the heat storage performance of an HWPS, which is of great significance for building energy conservation.

Water flooding is a commonly used method in oilfield development, and the water flooding process is essentially the process of oil-water movement in porous media. Pore-scale flow law in water flooding process can guide the oilfield development plan, to improve the oil recovery efficiency. In this paper, the computational domain is constructed from the CT scan images of real cores. The oil-water flow process of the water flooding in the pore structure is simulated using the interFoam solver in OpenFOAM. The influence of the displacement process and the distribution of the remaining oil is analyzed in three aspects: the water cut curve, the state of the same water injection amount, and the final displacement state. The flow rate velocity affects the water flooding swept range, and the recovery factor increases gradually with the increase of the flow rate. With different injection velocity, the sweeping sequence of pores is different, and the location and shape of remaining oil are very different. Due to the different dominant forces under different wettability states, the swept patterns of the core are also different.