Coupled imbibition-flowback behavior in shale pore-fractures networks using the lattice Boltzmann method

During fracturing operations, high-pressure injected fluids flow through complex fracture network and micro-nano pores within shale formations. The coupled effects of capillary forces, viscous forces, and rock surface wettability drive forced imbibition processes, ultimately influencing reservoir recovery efficiency. Based on the Shan–Chen multi-relaxation-time lattice Boltzmann model, the study conducts an oil–-water two-phase flow/imbibition simulation in reconstructed shale pore-fracture networks, clarifying flow mechanisms under waterflooding and systematically probing the roles of bedding fractures, wettability, and pressure gradients. The results demonstrate that bedding fractures significantly enhance oil mobilization by connecting blind-end pores and reducing viscous and capillary resistance, leading to an 8.7% increase in recovery. Strongly water-wet conditions produce continuous displacement fronts and improve oil recovery by 6.9% compared to oil-wet cases. Increasing the capillary number, representative of higher injection pressure, accelerates the advancement of the imbibition front and improves sweep efficiency, raising recovery by 7.1%. These findings provide theoretical insight for optimizing shale oil development strategies, including wettability modification, pressure regulation, and fracture design.