Low salinity water flooding is a new technology for enhancing oil recovery by adjusting the ion composition or concentration of injected water. However, the applicable reservoir conditions and enhanced oil recovery mechanism of low salinity water flooding have not yet reached a consensus. In this paper, a series of laboratory experiments of wettability control-based low salinity flooding are carried out with plunger rock samples from marine carbonate reservoirs in the Middle East as the research object. Based on the theory of Derjaguin-Landau-Verwey-Overbeek theory (DLVO), an interfacial reaction model of a typical crude oil/brine/rock system is established, and the contact angle and total separation pressure are calculated simultaneously with the augmented Young-Laplace formula. The reliability of the model is verified by the literature experimental data, and the effects of ion concentration and ion type on the separation pressure curve and contact angle are clarified. The results show that in low salinity environments, the pore surface of carbonate rock is more water-wet under the action of fluid flushing, the oil displacement efficiency is higher, and the low salinity water improves the crude oil recovery by 3.2%; under the assumption of constant charge, the mathematical model established based on the DLVO theory for the crude oil/brine/rock system can accurately predict the change of contact angle; compared with the ion concentration, ion type has a greater impact on separation pressure and contact angle. Among divalent ions, Mg²⁺ ions exhibit a more pronounced influence on wettability control compared to Ca²⁺ ions. When the water film thickness is minimal, van der Waals force is the main force affecting the separation pressure. As the thickness of water film increases, the electric double layer force gradually becomes the main force. This study contributes to a deeper understanding of the wettability control mechanism of low salinity water flooding for enhanced oil recovery.

Two actual rocks drilled from a typical ultra-deep hydrocarbon reservoir in the Tarim Basin are selected to conduct in-situ stress-loading micro-focus CT scanning experiments. The gray images of rock microstructure at different stress loading stages are obtained. The U-Net fully convolutional neural network is utilized to achieve fine semantic segmentation of rock skeleton, pore space, and micro-fractures based on CT slice images of deep rocks. The three-dimensional digital rock models of deformed multiscale fractured-porous media at different stress loading stages are thereafter reconstructed, and the equivalent fracture-pore network models are finally extracted to explore the underlying mechanisms of gas–water two-phase flow at the pore-scale. Results indicate that, in the process of in-situ stress loading, both the deep rocks have experienced three stages: linear elastic deformation, nonlinear plastic deformation, and shear failure. The micro-mechanical behavior greatly affects the dynamic deformation of rock microstructure and gas–water two-phase flow. In the linear elastic deformation stage, with the increase in in-situ stress, both the deep rocks are gradually compacted, leading to decreases in average pore radius, pore throat ratio, tortuosity, and water-phase relative permeability, while the coordination number nearly remains unchanged. In the plastic deformation stage, the synergistic influence of rock compaction and existence of micro-fractures typically exert a great effect on pore-throat topological properties and gas–water relative permeability. In the shear failure stage, due to the generation and propagation of micro-fractures inside the deep rock, the topological connectivity becomes better, fluid flow paths increase, and flow conductivity is promoted, thus leading to sharp increases in average pore radius and coordination number, rapid decreases in pore throat ratio and tortuosity, as well as remarkable improvement in relative permeability of gas phase and water phase.