Appropriate shut-in after hydraulic fracturing can enhance shale oil production, but the underlying mechanisms remain unclear. This study investigates three cores from shale oil well Y of Huazhuang (HSY) in southern China. Hydration–imbibition experiments were conducted under simulated reservoir conditions, combined with Computed Tomography scanning and digital rock reconstruction, reveal the microscopic mechanisms of shut-in stimulation, and propose a method to optimize shut-in duration. Results show that fracturing fluid infiltrates the cores, causing clay minerals to swell and exchange ions, disrupting their laminar structure. This inducing propagation and widening of existing fractures as well as the formation of new fractures significantly improve flow pathways and enable effective fluid migration and oil–water contact for subsequent imbibition. The imbibition process is jointly driven by capillary force, osmotic pressure, and wettability, enabling efficient displacement of pore oil. The synergy between hydration-induced permeability enhancement and imbibition displacement constitutes the core mechanism for production increase during shut-in. This effect is jointly controlled by hydrophilic clay content, water wettability, and initial pore–fracture structures. Higher clay content, stronger water wettability, larger matrix porosity, and more complex fracture networks correlate with shorter optimal shut-in times and greater production improvement. The three cores comprehensive performance ranks as core #1 core #2 core #3, with corresponding optimal shut-in times of 14, 18, and 19 days. Field application at well HSY with a 16-day shut-in confirmed the experimental predictions, validating the method's reliability and practical value. This study offers guidance for optimizing shut-in strategies in shale oil reservoirs.
Xu et al. (Mon,) studied this question.