This paper focuses on the CO2-EOR in fractured tight oil reservoirs after water-flooding treatment. In previous works, few studies were presented about the spontaneous imbibition experiments of CO2-rich brine at formation pressure. We investigated the influence of CO2 injection on spontaneous imbibition, which is an essential mechanism to improve oil recovery in tight reservoir. In this paper, a laboratory equipment was set up to conduct spontaneous imbibition experiments at formation temperature of 65 °C and pressures of 10−22 MPa on different low-permeability core samples from Nugget, Kentucky, Colton, and Crab-Orchard in the United States. Moreover, we proposed a saturation-based dimensionless time model to scale the spontaneous imbibition and a modified Ma model to fit the oil recovery curves of spontaneous imbibition of CO2-rich brine with double peaks of imbibition rate. The results of quantitative imbibition experiments confirm that both the oil production per unit area and the oil recovery have a positive proportional relationship with permeability. A primary reason is that both the capillary pressure and the viscous resistance increase with decreasing of capillary size, but the viscous resistance is more sensitive. The result also quantitatively demonstrates that both the oil production and the oil recovery increase with confining pressure, especially when the pressure exceeds minimum miscibility pressure. However, the pendent drop test illustrates that CO2 decreases the oil−water interfacial tension with the elevating of pressure. CO2 can improve the recovery of tight oil by spontaneous imbibition in two main mechanisms: decreasing oil viscosity to improve flowing ability and oil swelling to enhance the cocurrent imbibition. This work provides theory basis and feasible measure for CO2-EOR in the fractured and water-flooded tight reservoir.