Fracture aperture evolution in subsurface fractured reservoirs: Insights from thermo-hydro-mechanical simulations and implications for field-scale applications

Abstract

Subsurface energy recovery and storage involves continuous fluid injection into fractured rock formations. The efficiency of these applications highly depends on the evolution of fracture characteristics under thermo-hydro-mechanical (THM) coupled processes induced by fluid injection. In this study, we established a single-fracture THM model to quantitatively analyze the combined and individual contributions of overpressure (OP), poroelastic (PE), and thermoelastic (TE) effects on fracture aperture evolution. The competition among OP, PE and TE effects is examined under various fracture/rock parameters and confining pressure/injection temperature conditions. Core-scale simulations demonstrate that OP, PE, and TE effects reach equilibrium within hours, with PE effect exerting the most dominant influence on fracture aperture. The relative dominance of these effects exhibits strong dependence on injection temperature, Biot coefficient, and rock elastic modulus. Comparative analysis with typical core flow-through experimental data qualitatively reveals the potential effects of water-rock reactions on fracture aperture. We find that under low confining pressures, the TE effect is stronger than the effect of water-rock reactions, leading to fracture aperture increase in response to cold fluid injection, while under high confining pressures, water-rock reactions dominate and cause fracture aperture decrease. Compared with core-scale simulation, field-scale simulations reveal fundamentally different fracture behavior marked by persistent THM disequilibrium and sustained spatial heterogeneity in aperture evolution, and therefore highlight the necessity to explicitly account for scale effect when extrapolating core-scale observations to field conditions.