Osmotic pressure-facilitated spontaneous imbibition in shale reservoirs for recovery enhancement

The spontaneous imbibition (SI) process within shale reservoirs is influenced by both capillary force and the osmotic pressure differential existing between formation water and fracturing fluid. To delve into this intricate mechanism, a numerical simulation study on shale SI is conducted, utilizing seepage theory, the osmotic pressure equation, and solute transport theory. A notable innovation of this research is the derivation of a control equation governing salt ion transport under oil–water two-phase flow conditions. Subsequently, a comprehensive mathematical model for shale SI, accounting for both capillary force and osmotic pressure, is established and solved through numerical simulation methods. The findings reveal that the osmotic pressure between high-salinity formation water and low-salinity fracturing fluid exerts a substantial influence on the imbibition process. It not only accelerates the advancing speed of the imbibition front but also augments the volume of imbibed fluid, thereby significantly enhancing the imbibition recovery ratio. Consequently, optimizing membrane efficiency and increasing the salinity difference emerge as an effective strategy to boost imbibition recovery. Conversely, the impact of hydrodynamic dispersion on salt concentration distribution and imbibition recovery ratio is found to be relatively modest. Overall, this study systematically elucidates the underlying mechanisms of osmotic pressure in the context of the imbibition process. The insights gleaned from this research are anticipated to provide crucial theoretical guidance for enhancing SI efficiency in shale oil reservoirs.