We review ten historical Enhanced Geothermal Systems (EGS) projects and find that typically, during injection: (1) flow from the wellbore is from preexisting fractures, (2) bottomhole pressure exceeds the minimum principal stress, and (3) pressure-limiting behavior occurs. These observations are apparently contradictory because (1) is consistent with shear stimulation, but (2) and (3) suggest propagation of new fractures. To reconcile these observations, we propose that, in many cases, new fractures do not form at the wellbore, but away from the wellbore, and new fractures initiate from open and/or sliding natural fractures and propagate through the formation. Fracture initiation from natural fractures is aided by concentrations of stress caused by the fractures' opening and sliding. The propagating fractures may terminate against natural fractures, forming a complex network of both new and preexisting fractures. We perform computational modeling with a discrete fracture network simulator that couples fluid flow with the stresses induced by fracture deformation. The modeling results demonstrate that several geological conditions must be in place for stimulation to occur only through induced slip on preexisting fractures and to avoid significant opening of new or preexisting fractures. These conditions cannot be expected to be present at every EGS project, and our review of the literature shows that they typically are not. The simulation results indicate that pure shear stimulation is more likely to be possible in locations with thick faults present, and our review of the literature shows that EGS field experience is consistent with this hypothesis. We discuss field experiences from several EGS projects and describe how they are consistent with the idea that significant propagation of new fractures has occurred.
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