ABSTRACT:

In January 2021, highly deviated injection well, 16A(78)-32, was drilled to a total depth 10,987 ft at the Frontier Observatory for Research in Geothermal Energy (FORGE) site near Milford, Utah. After a brief hiatus, hydraulic fracturing will be carried out near the toe. The production well, 16B(78)-32, will be drilled with a trajectory designed to intersect the microseismic cloud observed during creation of these stimulated fractures. The stimulation, which aims to connect injection and production wells, was simulated with a distinct element method (DEM) based code, XSiteTM, fully coupled hydro-mechanical model with explicit representation of the discrete fracture network (DFN). The model has been calibrated by a pressure history matching of the injection tests of the pilot well, 58-32. The preliminary simulations for the current interpretation of the DFN show that the formation response to the injection is dominated by the DFN. At a pumping rate of 20 bpm for 15 minutes, sufficient increase in fluid pressure resulted in failure of some area of the DFN both in tension (opening) and shear (slip). The cases with DFN dilatancy indicate lower injection pressure. The case with higher DFN strength has smaller area of slipping fractures but larger area of open fractures. Decreasing the pumping rate to 10 bpm resulted in lower net fluid pressure but a larger stimulated volume. Increasing fluid viscosity 10 times resulted in much higher fluid pressure and more DFN failure.

1. Introduction

The U.S. Department of Energy selected a location in south-central Utah near the rural community of Milford to develop and test techniques for creating, sustaining, and monitoring Enhanced Geothermal System (EGS) reservoirs. This field laboratory is the Frontier Observatory for Research in Geothermal Energy (FORGE). A pilot well, 58-32, was drilled into the low permeability granitic rock that will form the EGS reservoir. In 2017 and 2019, injection testing was carried out in three zones of well 58-32 (Xing et al., 2020). From October 2020 to January 2021, the injection well of the injection-production pair, 16A(78)-32 (refer to Figure 1), was drilled, and injection testing including DFIT (Diagnostic Fracture Injection Test) and flowback test was carried out. Within the next two years, a production well of the pair will also be drilled. Both wells of the pair are highly deviated with bottom-hole temperatures near 230°C. After a brief hiatus to analyze reservoir characterization data from well 16A(78)-32, hydraulic fracturing will be carried out near the toe of that well before drilling the second well. Production well 16B(78)-32 will be drilled with a trajectory designed to intersect the microseismic cloud produced during creation of these hydraulic fractures. A key consideration is the geometry of these "near-toe" fractures in the injection well and the need to ensure effective hydraulic communication between the two wells.

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