Experimental Investigation and Numerical Modeling of Imbibition Behavior in Deep Shale Gas Reservoirs

The imbibition of fracturing fluid into shale matrices is a critical factor controlling gas production and the fracturing fluid flowback in shale gas reservoirs. However, the imbibition behavior in deep shale gas reservoir conditions remains poorly understood, particularly in terms of wettability. In this study, an integrated experimental and numerical modeling investigation was conducted on deep shale samples from the Longmaxi formation. Spontaneous imbibition experiments using NaCl solutions of varying salinities were performed, with fluid uptake and pore-scale distribution monitored by mass measurements and low-field nuclear magnetic resonance. A two-phase flow numerical model, based on the phase-field method and reconstructed pore geometries, was developed in COMSOL Multiphysics to simulate the capillary-driven imbibition process. The model was validated against experimental data. The results show that the imbibition curve exhibits three characteristic stages (rapid self-absorption, transition, and slow diffusion), similar to those observed in shallower shales, but with a lower imbibition capacity coefficient attributed to the predominance of nonswelling Illite, indicating weaker water wettability. Both experiments and simulations demonstrate that increased salinity and the presence of K +, compared with Na +, significantly inhibit imbibition and thus suppress wettability. Furthermore, a nonmonotonic relationship exists between the imbibition mass and both pressure and temperature, with optimal conditions identified for maximum uptake, beyond which pore compression and closure reduce imbibition, reflecting a transition from wettability promotion to inhibition. This work provides quantitative insights into fracturing fluid retention mechanisms and offers guidance for optimizing stimulation strategies in deep shale reservoirs.