Numerical simulation of fluid injection-induced fault slip in heterogeneous shale formations

Abstract

We study the impact of reservoir heterogeneity on fault slip in shale reservoirs subject to hydraulic stimulation. We construct a two-dimensional numerical model representing the horizontal cross-section of a faulted heterogeneous shale formation and simulate coupled hydro-mechanical processes in the system during and after high-pressure fluid injection. We conceptualize the natural fault as a geological composite consisting of a fault core and a damage zone that involves a set of subsidiary fractures parallel to the fault strike. We couple the solid deformation and fault displacement with the Darcy flow based on poro-elasticity principles and hydro-mechanical constitutive relations. The heterogeneous nature of the permeability field of the shale reservoir is mimicked as a random field governed by a log-normal probability density function and prescribed correlation lengths. We elucidate the linkage between fault slip and fluid flow field, permitting the capture of the spatio-temporal evolution of preferential flow channels and their consequences on fault slip and induced seismicity. We report a significant role of reservoir heterogeneity in fault reactivation when the hydraulic fracture is away from the fault but at a distance smaller than the correlation length. The results of our research have important implications for many fluid injection-related geoengineering activities.