Abstract: When a shale oil reservoir contains a mass of clay minerals, the salinity of formation water can reach up to 4.786×10³ mol·m^?3 and the formation water and low salinity fracturing fluid create significant osmotic pressure during the fracturing process. To investigate the effect of osmotic pressure on the imbibition effect, a two-dimensional, oil-water, two-phase, discrete fracture network model was established. This model comprehensively considers osmotic pressure and capillary force. Additionally, a series of studies were carried out to explore the influence of osmotic pressure, capillary force, shut-in time, salt concentration, membrane efficiency, and the proportion of branch fracture area on the imbibition effect in shale oil reservoirs during fracturing fluid pumping and shut-in. The results show that: (1) Filtration is mainly influenced by pressure difference, capillary force, and osmotic pressure, and pressure difference is the key control mechanism of filtration. (2) The shut-in time has a great influence on the imbibition effect of fracturing fluid. The imbibition amount in the first 15 d can reach 80% of the total imbibition amount when the well is shut in for 50 d, leading to the shut-in pressure spreading to the fracturing interval on either side. (3) Osmotic pressure takes longer to reach equilibrium than diffusion pressure. Osmotic pressure takes 50 d to shut in the well and make the salinity near the fracture reach 600 mol·m^?3 when the salinity of local layer water is 4.786×10³ mol·m^?3. (4) As pressure difference is the main factor that affects the imbibition effect and the effect of shale film efficiency on seepage pressure diffusion is weak, the extent of imbibition increases by only 4% when the shale film efficiency increases from 5% to 30%. (5) Water saturation is controlled using hydraulic fractures through small spacing during shut-in, and the influence of branch fractures on water saturation is limited in intensive volume fracturing to horizontal wells.