Abstract: Spontaneous imbibition is an important phenomenon in tight reservoirs. The existence of a large number of fractures and micro-nano pores is the key factor affecting the spontaneous imbibition of tight reservoirs. In this study, based on high-pressure mercury injection and nuclear magnetic resonance experiments, the pore distribution of tight sandstone is described. The influence of fractures, core porosity and permeability, and surfactants on the spontaneous imbibition of tight sandstone are studied by physical fracturing, interfacial tension test, wettability test and imbibition experiments. The results show that: the pore radius of tight sandstone is concentrated in 0.01–1 μm. Fractures can effectively reduce the oil drop adsorption on the core surface, enhancing the imbibition recovery of the tight sandstone with an increase of about 10%. As the number of fractures increases, the number of oil droplets adsorbed on the core surface decrease and the imbibition rate increases. The imbibition recovery increases with the increase in pore connectivity, while the imbibition rate increases with the increases in core porosity and permeability. The surfactant can improve the core water wettability and reduce the oil−water interfacial tension, reducing the adsorption of oil droplets on the core surface, and improving the core imbibition recovery with an increase of about 15%. In a word, the existence of fractures and surfactants can enhance the pore connectivity of the reservoir, reduce the adsorption of oil droplets on the core surface, and improve the imbibition rate and recovery rate of the tight oil reservoir.