Multiscale Numerical Simulation of Fracturing Fluid Invasion and Its Impact on Field-Scale Permeability in Unconventional Reservoirs

Summary Hydraulic fracturing is widely used in the development of unconventional resources, but the fracturing fluid can invade the formation and induce clay swelling in the rock matrix, which can affect the rock permeability dramatically. The aim of this study is to quantify field-scale permeability changes induced by fracturing fluid invasion. Therefore, we developed a multiscale model by integrating a field-scale model with a laboratory-scale model that explicitly accounts for pore-throat clogging and microcrack generation, thereby linking invasion effects to field-scale permeability changes. Simulation results indicate that the changes in permeability induced by fracturing fluid invasion vary significantly under different conditions. Specifically, microcracks are induced when swelling force, clay content, and stress difference jointly exceed critical thresholds, leading to matrix permeability enhancements of approximately two to five times in the x-direction and four to eight times in the y-direction. In contrast, under low stress difference or weak swelling conditions, pore-throat clogging effect dominates, resulting in matrix permeability reduction. In addition, a criterion is proposed to predict microcrack generation potential across formations. For clay contents of 25–55%, the critical stress difference and swelling force for microcracks generation are approximately 2.5–22.5 MPa and 0.5–9 MPa, respectively. Based on this criterion, extended shut-in is recommended for formations with strong microcrack generation potential, whereas early or staged flowback is preferable if clogging dominates.