Shale reservoirs contain abundant micro/nanoscale pores, which facilitate capillarity-dominated imbibition as an effective mechanism for enhancing hydrocarbon recovery. During hydraulic fracturing, the penetration of low salinity fracturing fluids can induce clay hydration and swelling, leading to pore structure alterations. However, the effects on imbibition behavior remain insufficiently understood. In this study, high temperature and high pressure imbibition experiments coupled with nuclear magnetic resonance are performed on continental shale. Furthermore, the structural and mineralogical evolution of shale following interaction with deionized water is evaluated by scanning electron microscope. Finally, the pore fracture structure model incorporating clay swelling is constructed and the flow of fracturing fluids is simulated by the lattice Boltzmann method. The results indicate that cores exhibit greater imbibition recovery at higher salinity. The recovery shows a strong positive correlation with pore structure, with denser and less connected pores leading to reduced recovery. Exposed to deionized water, clay is observed to swell and compress both pore space and fracture. After swelling, the flow channels in the two-dimensional model are narrowed or even closed, resulting in fewer effective flow pathways and a reduced swept zone of the oil phase. Meanwhile, the oil phase is prone to snap-off, producing discontinuous droplets that disperse within the pore space. This ultimately leads to a reduction in imbibition recovery after swelling. High salinity effectively suppresses clay mineral swelling and preserves the original pore structure, thereby resulting in higher imbibition recovery. Understanding the imbibition mechanisms under different salinity provides valuable insights for the design of hydraulic fracturing in oilfield applications.