Abstract
In 2017 and 2019, injection testing was carried out in three zones in a vertical well in granite at the Frontier Observatory for Research in Geothermal Energy site near Milford, Utah, USA. In several injection cycles, flowback was implemented rather than shut-in. The goal was to explore an alternative to prolonged shut-in periods for inferring closure stress, formation compressibility, and formation permeability (permeability thickness product). The flowback procedures involved a cyclic flowback/shut-in, while pressure decreased. The flowback data are presented, and analyses are shown. The inferred closure stress(es) from flowback analyses are lower than for equivalent injection cycles that were strictly shut-in. Relatively high formation compressibility obtained from the flowback analyses indicates an extensive, fractured system. This study also includes numerical simulation of the flowback events. The numerical model shows that the rebound pressure is not necessarily the lower bound of the minimum principal stress. The signature of stiffness change can be identified as the process when the depletion mainly transitions from hydraulic fracture to natural fractures from numerical analysis. Overall, flowback potentially has advantages over shut-in because of the reduced time to closure.
Highlights
Enhanced geothermal systems (EGS) offer the potential to bring low-cost geothermal energy to locations that lack natural permeability through hydraulic stimulation (Moore et al 2019)
We can see that the permeability thickness product is around 32.9 md ⋅ m and there is no obvious trend change in this plot for Zone 2, Cycle 7, which could be due to starting flowback late
From the analyses of the three cases, the closure stress gradient is estimated at 14.3–14.9 MPa/km, the formation permeability thickness product at 5.5–36.5 md⋅ m, and the formation compressibility is bracketed between 1.0×10−8 and 2.5×10−8 1/Pa for Zone 2
Summary
Enhanced geothermal systems (EGS) offer the potential to bring low-cost geothermal energy to locations that lack natural permeability through hydraulic stimulation (Moore et al 2019). In 2017 and 2019, multiple injections were carried out in Well 58-32 at the Utah FORGE site (see Xing et al 2020b). Flowback closure stress measurement has been used in the petroleum sector for in-situ stress inference. In addition to inferring in-situ stresses, pump-in/flowback methods can be used to assess formation permeability (permeability thickness product), formation compressibility, and reservoir pressure (Zanganeh et al 2020). This study presented pump-in/flowback data for Well 58-32 at the FORGE site. Various analytical methods have been applied to infer the closure stress (often treated as minimum in-situ stress), permeability (permeability thickness product), and formation compressibility. A distinct element method simulator, 3DEC, is used to create the numerical model. That, FORGE pump-in/flowback data are evaluated to infer the relevant in-situ properties. Numerical flowback simulations are presented and the results are discussed
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