Aiming at the unclear mechanisms of fluid migration in nanopore-throat systems within tight oil reservoirs, this study focuses on the microscopic interactions at the oil–water interface in nanoconfined spaces. Based on molecular dynamics simulation, water-flooding models within nanopores of tight oil reservoirs under varying salinity conditions were constructed. The microscopic flow behaviors of oil and water in the pores were investigated, and the mechanism by which interfacial hydrogen bonding influences displacement efficiency under nanoconfinement was elucidated. The results demonstrate that due to the strong hydrogen bonding interactions between acetic acid and water, it is impossible to establish an effective displacement process or form stable displacement pathways within the pores. The extensive hydrogen-bonding network formed by acetic acid molecules at the oil–water interface severely restricts the transport capacity of water. Salinity exerts a nonlinear regulatory effect on hydrogen bonding. High-salinity (246.5 g/L) waterflooding shortens hydrogen bond lengths, enhances local bonding strength, and restricts the expansion of water channels; low-salinity (21.9 g/L) waterflooding mitigates ionic interference, resulting in the highest diffusion capacity of alkanes. The diffusion coefficient increases by 1.4 times compared to that under high-salinity conditions, leading to the highest degree of crude oil mobility. The research findings provide important guidance for enhanced oil recovery in tight oil reservoirs.

To address the unclear microscopic mechanisms of water huff-n-puff in tight reservoirs under the influence of salinity, a visual physical model for microscopic flow in fracturing fluid displacement was constructed. It was clarified that the fluid displacement mechanism during fracturing fluid displacement is jointly governed by three mechanisms: pressure differential displacement, capillary force imbibition, and ion osmosis, which breaks through the traditional understanding only considering “fracturing fluid displacement and imbibition for energy supplementation.” Through multi-method and multi-scale approaches, the microscopic mobilization mechanism of fracturing fluid displacement under the influence of salinity was elucidated, and the main controlling factors were analyzed. The results indicate that reducing the salinity of injected water can enhance oil recovery, and the recovery factor increases with reservoir permeability, shut-in time, and injection pressure. Reservoir permeability and injected water salinity have a greater impact on the performance of water huff-n-puff, followed by shut-in time and injection pressure. Although low-salinity water flooding tends to induce viscous fingering, which reduces the sweep efficiency of the injected water, it enhances capillary imbibition, effectively stripping residual oil from low-permeability matrices and dead-end pores, thereby ultimately improving oil recovery. This study provides theoretical support for enhancing recovery in tight oil reservoirs using fracturing fluid displacement.

Water retention after imbibition and the recovery response to low-salinity injection suggest that capillarity alone does not describe all fluid exchange in tight formations. How osmotic forces influence successive injection, soaking, and production stages in a fractured reservoir therefore requires further examination. We constructed a simulator that combines aqueous salt transport with two-phase flow and represents hydraulic fractures by assigning equivalent properties to the intersected grid cells. A comparison with an independent simulator was used to assess the computed saturation response. Sensitivity cases varied in brine salinity, shut-in duration, injection rate, branch position, and network geometry; pressure, aqueous saturation, salt distribution, and produced oil were examined together. With 4800 m³ injected at 80 m³/d and a subsequent 40 d soak, the 1000 mg/L case produced 13,741.24 m³ of oil and recovered 17.28% of the initial oil volume. The corresponding values at 50,000 mg/L were 9507.86 m³ and 11.95%. Thus, reducing salinity added 4233.38 m³ of oil and 5.33 percentage points of recovery, equivalent to a 44.60% increase relative to the reported high-salinity recovery factor. Extending shut-in beyond 40 d provided progressively smaller benefits. A faster injection schedule reduced the operating time at a fixed water volume but also favored early water return; 80 m³/d provided a useful compromise within the tested range. Placing branches close to the well raised recovery to 22.35%, versus 17.28% for the unbranched fracture. This improvement was 5.07 percentage points, or 29.34% relative to the baseline. In the network cases, matrix blocks enclosed by fractures supplied most of the recovered oil, while more isolated rock retained substantial oil. Taken together, the simulations link the benefit of dilute injection water to fracture access and the time available for matrix exchange. For the assumptions and cases examined, a 1000 mg/L brine, an 80 m³/d injection schedule, a 40 d soak, and branches close to the well provide a favorable operating combination.