Impact of Osmotic Pressure on Seepage in Shale Oil Reservoirs

Abstract

Following large-scale volume fracturing in shale oil reservoirs, well shut-in measures are generally employed. Laboratory tests and field trials have underscored the efficacy of fracturing fluid imbibition during the shut-in phase in augmenting shale oil productivity. Unlike conventional reservoirs, shale oil reservoirs exhibit characteristics such as low porosity, low permeability, and rich content of organic matter and clay minerals. Notably, the osmotic pressure effects occurring between high-salinity formation water and low-salinity fracturing fluids are significant. The current understanding of the mobilization patterns of crude oil in micro-pores during the imbibition process remains nebulous, and the mechanisms underpinning osmotic pressure effects are not fully understood. This study introduces a theoretical approach, by which a salt ion migration control equation is derived and a mathematical model for spontaneous imbibition in shale is introduced, which is able to account for both capillary and osmotic pressures. Results indicate that during the spontaneous imbibition of low-salinity fluids, osmotic effects facilitate the migration of external fluids into shale pores, thereby complementing capillary forces in displacing shale oil. When considering both capillary and osmotic pressures, the calculated imbibition depth increases by 12% compared to the case where only capillary forces are present. The salinity difference between the reservoir and the fracturing fluids significantly influences the imbibition depth. Calculations for the shutin phase reveal that the pressure between the matrix and fractures reaches a dynamic equilibrium after 28 days of shut-in. During the production phase, the maximum seepage distance in the target block is approximately 6.02 m.