The coupling between solute transport and rock's geomechanical processes, for example, flow‐induced fracture activation, has emerged as an important hydrogeological challenge due to its role in applications such as underground waste disposal, carbon sequestration, contaminant remediation, enhanced oil recovery, and tracer‐based reservoir surveillance. Despite recent advances in modeling flow and geomechanics coupling, a holistic approach to capturing the synergy between fluid flow, solute transport, induced stresses, and fracture mechanics is lacking. This study investigates the rich interplay between these processes within a novel computational framework that is proposed to solve the coupled flow, transport, geomechanics, and fracture mechanics problem. The Embedded Discrete Fracture Modeling (EDFM) method is used to model the flow and transport processes in fractured porous media while an improved Bandis model is employed to capture the fracture mechanical response to flow‐induced stress perturbations. The role of transport‐geomechanics coupling in modulating the spreading and miscibility of a solute slug during viscously unstable flows is examined. We investigate how flow‐transport coupling, parameterized through the solute viscosity contrast and the fracture permeability, influences the stress state and fracture stability in the domain. A case study, inspired by a huff‐n‐puff tracer flowback study, is conducted to investigate the applicability of the proposed framework in the field. A sensitivity analysis is performed to evaluate the dependence of global transport characteristics, permeability evolution, and fracture stability on parameters dictating the strength of coupling between geomechanics, flow, and transport.

CO₂ injection in active oil fields is a technology proposed for industrializing carbon storage operations. However, monitoring CO₂ migration, oil recovery, and mechanical deformation within caprock and on faults is a challenging problem in large‐scale storage‐enhanced oil recovery operations due to intersecting faults, multiphase flow effects, and wells with complex production‐injection schedule. We develop and demonstrate a methodology based on our coupled modeling framework to monitor the movement of CO₂, hydrocarbons and water, and the associated evolution in mechanical stability of faults during CO₂ storage‐enhanced oil recovery in the Farnsworth Unit oil field in Texas, United States. The methodology honors geological, geophysical, and production‐injection data acquired in the field over six decades. Differential depletion from hydraulically isolated fault compartments followed by water and CO₂ injection‐induced overpressure causes volumetric contraction and expansion of the reservoir, and changes in the total and effective stresses in the overburden‐reservoir‐underburden complex. CO₂ migrates upward to accumulate near top of the geologic structure, and water migrates downward to pressurize the faults. Three‐dimensional changes in the pressure and stress fields in the system lead to changes in the shear and effective normal tractions on three major faults compartmentalizing the field. Evolution in fault tractions is used to compute the evolution in the Coulomb failure function of the faults to quantify induced‐slip tendency under production and injection. We explain the spatial heterogeneity and time variability of Coulomb failure function in terms of well location heterogeneity and well rate variability.