Fracture network fracturing combined with oil–water infiltration and replacement is an effective approach to develop tight sandstone reservoirs. How to further improve oil recovery based on imbibition is a problem encountered during production. In this study, the core of the CHANG-7 tight sandstone reservoir in the Changqing oilfield of the China National Petroleum Corporation (CNPC) is studied. Combined with the newly designed core self-imbibition experiment, the mechanisms of salinity action are studied, and the influence of salinity on the process of imbibition oil recovery is quantitatively characterized. Research results show that the influence of salinity on the imbibition process of tight sandstone reservoirs takes place mainly through two ways; one is to reduce the oil–water interfacial tension, and the other is to construct an osmotic pressure displacement model. The salinity has significant influences on interfacial tension. The interfacial tension of low-salinity brine is only 1/5 of that of distilled water, but in the presence of high-efficiency surfactants, the influence of the salinity on the interfacial tension can be ignored; the greater the difference in salt concentration, the higher the core permeability and the greater the influence of salinity on the process of imbibition and oil recovery in tight sandstone reservoirs. At the initial stage of imbibition, the effect of salinity is less important than that of capillary force. On the contrary, the effect of salinity is much more important than that of capillary force in the middle of imbibition, and the imbibition curve shows a downward trend. At the later stage of imbibition, the fluid tends toward imbibition equilibrium, and the effects of capillary force and salinity are not obvious.

A model suitable for evaluating a tight sandstone reservoir is established. The model includes two oil-water replacement modes: capillary force mode and osmotic pressure mode. The relationship between oil-water displacement rate and dimensionless time under different parameters is drawn considering the influence of capillary force, osmotic pressure, production pressure difference, and starting pressure gradient. Results indicate that the higher the relative permeability of the water phase, the lower the relative permeability of the oil phase, the smaller the oil-water viscosity ratio, and the higher the oil-water replacement rate. The relative permeability of the water phase also affects the infiltration stabilization time. Low salinity fracturing fluid infiltration helps to improve the oil-water replacement rate.

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.

“Fracturing network+imbibition oil production” is a new attempt to effectively develop low-permeability tight reservoirs. Fracturing fluid is not only a carrier for sand carrying but also a tool in the process of imbibition. On the basis of imbibition experiments, combined with nuclear magnetic resonance and pseudo-color processing technology, this paper clarified the dominant forces of different types of pore-throat and quantitatively characterized the contribution of different levels of pore-throat to imbibition oil recovery. The results show that gravity is the main controlling force of imbibition for reservoirs with higher permeability. Fluid replacement mainly occurs in the early period of imbibition. Macropores contribute most of the imbibition recovery, mesopores have a weak contribution, and the contribution of micropores and pinholes can be ignored. For the reservoirs with low permeability, capillary force is the main controlling force of imbibition. Fluid replacement mainly occurs in the later period of imbibition. Macropores contribute most of the imbibition recovery rate, mesopores contribute a small part of the imbibition recovery factor, and the contribution of micropores and pinholes can be ignored. This paper clarified that macropores and mesopores are the main sources of the contribution of imbibition recovery efficiency, and oil content and connectivity are key factors for the imbibition recovery efficiency.

In the development of carbonate reservoirs via water flooding huff-n-puff, the osmotic pressure effect is frequently overlooked, and existing models inadequately quantify the matrix imbibition and oil expulsion driven by salinity gradients. To address this issue, this study establishes a coupled oil–water two-phase huff-n-puff flow model for carbonate reservoirs that incorporates the interplay between salt concentration and osmotic pressure, which, for the first time, fully couples the van ’t Hoff osmotic pressure equation with solute transport equations for fractured-vuggy carbonate huff-n-puff, filling the gap that prior tight/shale reservoir low-salinity flow models fail to adapt to cyclic injection-soaking production regimes of carbonates. Based on the IMPES (implicit pressure–explicit saturation) numerical simulation method, an equivalent single-nucleus model is adopted to characterize the fractured-vuggy reservoir architecture. The model integrates the osmotic pressure formula, solute transport equation, and two-phase seepage governing equations, enabling a systematic analysis of the mechanisms by which osmotic pressure affects the multi-stage seepage process and the influence of key parameters on development performance. Quantitative simulation reveals three core laws controlled by salinity-induced osmosis: first, osmotic pressure drives water molecules to spontaneously migrate from the high-permeability fracture inner core toward the tight matrix pores, thereby modifying the water saturation distribution, expanding the water sweep region, and smoothing the saturation gradient between the inner and outer cores, which effectively mitigates water channeling in fractured reservoirs. Under the base case (injected water salinity = 1000 mg/L, inner-core permeability = 1000 mD, shut-in time = 80 d), the oil recovery factor with osmotic pressure considered reaches 13.46%, representing a 3.50% increment over the case without osmotic pressure. The recovery factor decreases monotonically with increasing injected water salinity, while it increases with longer shut-in time and higher inner-core permeability, both exhibiting pronounced diminishing marginal returns; the optimal shut-in time is approximately 80 d under the simulated conditions. This work delivers a fully coupled numerical tool and quantitative evaluation standard for osmotic imbibition mechanisms in fractured-vuggy carbonates. The quantified recovery increment and optimal soaking window established herein can directly guide field parameter optimization of injection water salinity, shut-in cycle and fracture reconstruction scale, balancing oil increment revenue and water treatment/well shutdown operation costs for on-site low-salinity huff-n-puff design.