Evaluating the Roles of Thermoelastic and Poroelastic Stress Changes in the Desert Peak EGS Stimulation

摘要

Hydroshearing is used to improve well injectivity in Engineered Geothermal Systems (EGS). During hydroshearing, cold water is injected at bottom-hole pressures less than the minimum principal stress to promote permeability enhancement through self-propping shear failure of pre-existing fractures. By interacting with the typically complex natural fracture network, a tortuous flow path with high surface area is promoted to allow for efficient heat exchange. Using the Mohr-Coulomb failure criterion, we consider three mechanisms that directly influence shear failure during injection: (1) Fluid pressurization, decreasing the effective normal stress (i.e., normal stress minus pore pressure) on fractures amenable to slip and promoting failure. (2) Cooling of the rock matrix, leading to a thermoelastic decrease in normal stress on these fractures. (3) Pressurization within the rock matrix, leading to a poroelastic increase in normal stress on these fractures. Recently, we have implemented stress-permeability relationships to describe hydroshearing in the thermo-hydro-mechanical simulator FEHM. We have previously shown that this model is capable of reproducing the response of the Desert Peak EGS well 27-15 to shear stimulation. In this work, we analyze the relative importance of processes (1)-(3), including their non-local implications, to provide a deeper understanding of hydroshearing physics. In addition to the direct effect of fluid pressure (process 1), we show that thermoelastic stresses exert a strong influence on fracture failure during hydroshearing. The magnitude of these thermoelastic stresses is sensitive to the product of Young's modulus and the thermal expansion coefficient, as well as the difference between injection fluid temperature and ambient formation temperature. Increasing the injection wellhead pressure (WHP) amplifies injectivity gains due to the thermoelastic effect, and can dominate over the direct fluid pressure effect when the contrast between injection fluid temperature and formation temperature is large. Even when the surface temperature of the injection fluid is constant, increasing WHP delivers a greater volume of water to the formation at a lower temperature (by minimizing heating in the wellbore), thereby increasing both the rate and magnitude of thermoelastic stressing. We also present evidence that remote stress changes induced by thermoelastic cooling near a well can play an important role in propagating the front of permeability enhancement at long elapsed times. This effect is anisotropic, promoting activation of shear fractures in a direction parallel to the minimum horizontal principal stress, which in a normal faulting setting would be perpendicular to the expected strike of highly stressed fractures. This provides a new mechanism for widening the stimulated volume created during hydroshearing, promoting the creation of a more efficient and sustainable heat exchange fracture network.