Shale is characterized by a complex mineral composition and a well-developed, multiscale pore network spanning from micropores to nanopores, which gives rise to a highly intricate microscopic imbibition mechanism. Utilizing shale samples from the Jiyang Depression, experiments are conducted to systematically examine the influence of lithofacies, fluid type, fracture density, wettability, and fluid viscosity on the spontaneous imbibition behavior of shale. Low-field nuclear magnetic resonance serves as the principal analytical method for investigating fluid migration dynamics and spatial distribution within the multiscale pore structure of shale. The results indicate that, at the microscopic scale, imbibition-driven oil recovery is primarily controlled by capillary forces, which must overcome various forms of resistance to effectively displace oil with water. For massive cores without fracture, oil recovery is primarily contributed by nanopores within the matrix. In contrast, cores containing laminations and natural fractures preferentially mobilize oil from larger pores, as the flow resistance in nanopores is significantly greater than that in micropores. Transverse relaxation time spectrum from nuclear magnetic resonance further reveals that CO2, compared to water, can mobilize more oil from large pores via molecular diffusion. However, water exhibits superior displacement efficiency in smaller pores. Hydrophilic cores demonstrate the highest imbibition efficiency, and the addition of imbibition enhancers further improves displacement performance. On the other hand, increasing fluid viscosity suppresses both the imbibition-driven displacement process and overall fluid mobility.