Effects of shut-in time and organic matter content on fracturing fluid imbibition in shale gas reservoirs

During the shut-in stage of shale gas development, fracturing fluid spontaneously imbibes into the reservoir matrix under capillary forces, thereby altering the distribution of fluid saturations. To elucidate this process, this study establishes a coupled pore network and spontaneous imbibition modeling framework that explicitly incorporates mixed wettability and variations in organic pore volume fraction. The model is validated against experimental data to ensure reliability. The results reveal that (1) an increase in organic pore volume fraction (OPVF) enhances water trapping, narrows the two-phase flow region, and reduces both relative permeabilities; (2) under sufficient fluid supply, the imbibition rate exhibits a monotonic decline, with a pronounced reduction observed around 6 days, marking the onset of imbibition slowdown; and (3) a higher OPVF significantly suppresses the imbibition process, reflected by a shorter imbibition distance at the same time. This study provides new pore-scale insights into how mixed wettability and organic pore volume jointly control spontaneous imbibition behavior, offering theoretical guidance for optimizing shut-in duration in shale gas reservoirs.