Subsurface fluid injection stimulates complex hydromechanical interaction, necessitating the integration of geomechanical data across spatial and temporal scales to consider the sophisticated behavior. The induced seismic response is usually associated with reservoir architecture and pre-existing features that are three-dimensional, such as local stratigraphy, fractures, faults, and discontinuities. This study encompasses laboratory characterization of coupled hydromechanical response of rock cores extracted from reservoir - Mt. Simon sandstone, basal seal - Argenta sandstone, and crystalline basement - Precambrian rhyolite - formations in the Illinois Basin. High-resolution numerical modeling allows to consider the three-dimensional complexity of the injection site for Illinois Basin Decatur Project with spatial resolution comparable to one of the active seismic surveys. The laboratory-based porosity-permeability relation is combined with a three-dimensional porosity distribution developed from an inversion of active seismic data resulting in a detailed reconstruction of the evolution of the state of stress in formations where stress measurements are not performed. It appears that the microseismic clusters, mainly observed in the crystalline basement during the injection, are linked to zones experiencing more critically stressed conditions prior to injection. These zones have a potential for reactivation during the injection and are attributed to the specific local stratigraphy of the injection site, as well as transfer of triggering perturbations during the injection.

With the urgent necessity of geo-energy resources to achieve carbon neutrality, fluid injection and production in the fractured media will significantly increase. Applications such as enhanced geothermal systems, geologic carbon storage, and subsurface energy storage involve pressure, temperature, and stress changes that affect fracture stability and may induce microseismicity. To eventually have the ability to control induced seismicity, it is first necessary to understand its triggering mechanisms. To this end, we perform coupled thermo-hydro-mechanical (THM) simulations of cold water injection and production into a rock containing two fracture sets perpendicular between them. The permeability of fractures being four orders of magnitude higher than the one of the rock matrix leads to preferential pressure and cooling advancement, which induce stress changes that affect fracture stability. We find that the fracture set that is oriented favorably to undergo shear slip in the considered stress regime becomes critically stressed, inducing microseismicity. In contrast, the fracture set that is not favorably oriented for shear remains stable. These results contrast with those obtained for an equivalent porous media that does not explicitly include fractures in the model, which fails to reproduce the direction-dependent stability of fractures present in the subsurface. We contend that fractures should be directly embedded in the numerical models when inhomogeneities are of the spatial scale of the reservoir to enable reproducing the THM coupled processes that may lead to induced microseismicity.