Recent studies indicate that there is a great potential for enhanced oil recovery in shale oil reservoirs by altering the matrix wetness to induce spontaneous imbibition. The most common method is to add surfactant additives in fracturing fluid during multistage hydraulic fracturing operation. This imbibition process has complex pressure systems involved such as reservoir pore pressure, wellbore hydrostatic pressure, and surface pumping pressure. Without the wells being soaked intentionally, this pressurized state may be sustained for more than a month before flowback. Therefore, it is important to study the effect of pressure on the imbibition-induced oil recovery enhancement and its mechanism. In this study, we conducted forced imbibition tests on core plugs of unconventional sandstone, carbonate, and shale with different wettabilities. The applied pressures were 1000, 2000, 3000, 4000, and 5000 psi, and the results were compared to those of spontaneous imbibition under atmospheric pressure. Experimental results were used further in the numerical simulation study. The results manifested that a more water-wet state is still essential to improve the oil recovery regardless of the soaking pressure. When the rock is oil-wet, higher soaking pressure does not further worsen imbibition because of the minimal negative capillary pressure when oil saturation is high. However, when the rock is water-wet, the soaking pressures can be adverse to the imbibition in shale formations because of a longer pressure transient time which is against the capillary force. Dimensionless pressure (p(D)) is defined in this study to quantitatively determine the extent of imbibition inhibition during the forced imbibition. This observation indicated that in tight reservoirs, a higher soaking pressure will obtain less oil recovery from imbibition than that of lower soaking pressure cases at a given time.