Spontaneous imbibition has recently received a great deal of research attention for improving hydrocarbon recovery from shale gas and oil reservoirs. It is highly desirable to know the true significance and the role of fluid imbibition in the recovery process. Using a Krüss Drop Shape Analyzer 100S with Krüss’ Advance software, water imbibition depth was measured in this study on dry cores from four shale gas/oil reservoirs namely Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale, and Green River Shale. The initial water-contact angles on the Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale and Green River Shale core surfaces were measured to be 36.62°, 66.68°, 52.78° and 84.73°, respectively. The contact angle and thus volume of liquid droplet changed due to fluid imbibition into the core samples and evaporation. The change in droplet volume, together with the contact area and shale porosity, was used to calculate the imbibition depth. An analytical imbibition model was derived and tuned to upscale the tested fluid imbibition data to field level. The result of time-upscaling using the tuned imbibition models shows that the 1-month water imbibition depths for the Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale and Green River Shale are 2.61, 1.59, 0.89 and 0.16 cm, respectively. These low values suggest that the direct effect of water imbibition into shale matrix on hydrocarbon recovery in shale reservoirs is insignificant in the practical scales of space and time. However, the imbibition-induced shale cracks can increase shale permeability significantly for mass transfer during the hydrocarbon recovery process. Water imbibition in the cracks should be investigated in future studies.

Multi-stage hydraulic-fracturing horizontal wells has revolutionized today's oil and gas industry. Post-frac fluid soaking is essential for improving productivity of shale oil-gas wells. Optimization of soaking time is an open problem to solve in the petroleum industry. Understanding the post-frac soaking process is vitally important for solving the puzzle. Analytical solutions were developed in this study to describe the spontaneous imbibition processes in shale matrix and shale cracks during fluid soaking. Solutions show that the imbibition distance is directly proportional to the square root of imbibition time and the imbibition velocity is inversely proportional to the square root of imbibition time. The rate of spontaneous imbibition in shale cracks is much faster than that in shale matrix. Therefore, the optimum time for post-frac fluid soaking was further analyzed on the basis of the imbibition in shale cracks only. The solution was combined with pressure fall-off data to formulate a mathematical method for predicting the post-frac fluid soaking time required for the fluid to reach the mid-point between two adjacent hydraulic fractures. A case study with Tuscaloosa Marine Shale data suggests that the front of fluid imbibition should propagate 4 meters in 2 weeks and to 6 meters in 4 weeks. These numbers may be considered as the optimum times of post-frac fluid imbibition if the shale swell effect is negligible. Future research should quantify the effects of shale swelling on spontaneous imbibition so that the information can be incorporated in the soaking model to fully describe the imbibition process for better prediction of well productivity.