Stanford Geothermal WorkshopFebruary 9-11, 2026

The energy geosystems that involve fluid injection into geological formations, such as shale oil and gas and enhanced geothermal systems (EGS), are increasing in number and importance every day. To improve efficiency and ensure the sustainability of these geosystems, one must understand the mechanisms and factors that govern the evolution of the induced fracture network in naturally fractured ultra-low-permeability rock masses. Previous studies have demonstrated that natural fracture characteristics strongly influence both the hydraulic and mechanical responses of such formations. In this study, a combined finite–discrete element method (FDEM) is employed to investigate coupled hydromechanical processes during fluid injection, with particular emphasis on the role of natural fracture (NF) density. The results show that NF density significantly influences near-wellbore fracture initiation behavior controlling the breakdown pressure as the NF density increases. Following fracture propagation and crossing of NFs, fluid pressure dissipates along preferential pathways through the viscous drag process, thereby limiting the energy available to create new fractures. We hypothesize that increasing NF density amplifies lateral stress around the wellbore due to rock block interlocking, which leads to higher rock mass shear strength mobilization at lower shear displacements (Barton, et al., 1985). Understanding these phenomena will provide insights into implementing effective strategies for safer, more sustainable fluid injection practices in EGS.

Topic: Enhanced Geothermal Systems