<p>Fluid soaking after hydraulic fracturing of shale reservoirs is generally believed essential for improving oil/gas productivity of wells in shale reservoirs. Factors affecting the effectiveness of post-frac fluid soaking has not been fully explored. The objective of this study was to identify the shut-in pressure maintenance as a factor affecting the post-frac fluid soaking efficiency in shale oil/gas reservoirs. Spontaneous water imbibition was experimentally investigated on cores from the Marcellus Shale, Eagle Ford Shale, Tuscaloosa Marine Shale, and Green River Shale using a Krüss Drop Shape Analyzer. The test data were used to validate Guo-Wortman fluid imbibition model for fluid imbibition in shale cores. A degenerated form of the model for fluid imbibition in cracks was used to investigate the effect of pressure maintenance on fluid soaking efficiency. Model analysis with average parameter values indicates that adding fluid to wellbore to maintain the post-frac soaking pressure during the soaking period can accelerate fluid imbibition and thus increase soaking efficiency. If the soaking pressure is maintained at a level of 30% higher than the reservoir pressure, the fluid imbibition distance is predicted to be approximately doubled. Increasing soaking pressure from1.1 times to 1.5 times the reservoir pressure can reduce the required shut-in time from 25 days to 8 days for soaking water to the mid-point between two fractures with 3&#xa0;m of spacing (imbibition distance 1.5&#xa0;m). The improved efficiency of fluid soaking process should result in enhanced productivity of shale gas/oil wells. This work provides petroleum engineers with a simple tool for determining the maintenance pressure required to improve fluid soaking efficiency and thus well productivity.</p>