Integrated fracturing-flooding is a key technology to solve the problem of “difficult injection and difficult extraction” in tight oil and gas reservoirs. Focusing on three key physical processes in the fracturing-flooding development of tight reservoirs: fracture propagation during water injection, imbibition displacement during well soaking, and oil recovery during production, taking into account the impacts of osmotic pressure and flooding agents, and integrating continuous damage theory, a mathematical model for fracturing flooding coupling hydro-mechanical-damage (H-M-D) in tight reservoirs was established. Furthermore, numerical simulations of the integrated “fracturing-soaking-production” process were conducted to clarify the impacts of geological parameters and fracturing-flooding engineering parameters on the development effects. The study shows that when matrix permeability is low, the formation's water absorption capacity is weak, and the rock damage degree is high, resulting in the formation of “long and narrow” fracture networks. As matrix permeability increases, the rock damage degree decreases, leading to the formation of “short and wide” fracture networks. The density of natural fractures affects the direction and distance of hydraulic fracture propagation. As the injection volume increases, the length of the fracture network increases, and the overall water absorption capacity of the fracture network improves, making it easier for the fractures to extend in the direction of stress dominance. During the soaking process, formation pressure diffuses, and under the influence of imbibition, the oil phase gradually migrates toward the fractures. Based on the research findings, an integrated “fracturing-soaking-production” stimulation engineering parameter optimization technique was developed, and an optimization chart for stimulation engineering parameters was established. Taking the fracturing-flooding case of the tight reservoirs in eastern China as an example, the optimized injection volume within a single layer for fracturing flooding ranges from 3 × 10⁴ m³ to 3.5 × 10⁴ m³, with injection rates ranging from 1000 m³/d to 1200 m³/d and a soaking duration of 20–30 days, and the development effects of the reservoirs with fracturing flooding are much better than that without fracturing flooding.

The spontaneous capillary imbibition of confined nanopores is investigated using an analytical model that includes the slip effect, wettability and effective viscosity at the water surface interface. The results show that the effective viscosity of confined fluid is larger than that of bulk water and decreases with diameter and wettability. The effective slip length is negative for a contact angle of 0 ${}^{\mathrm{\circ }}$, and the effective slip length is positive and increases with diameter. The results of the presented model show that the capillary imbibition length for nanoconfined water can vary up to 0.389 - 1.033 times that determined by the Lucas-Washburn equation with no-slip boundary conditions for nanopores due to the effective viscosity and slippage with various dimensions and contact angles. The enhancement increases with diameter and contact angle. These results elucidate the confined movement through nanopores, which can be used to understand fracturing-fluid flow in the nanopores of shale reservoir formations.