An injection/production well doublet was recently drilled at the Utah FORGE site in order to test emerging EGS concepts. During the hydrofracture of the injection well (16A-32), a distinctive tracer was dosed into each of three fracture stages near the toe of the well. While drilling an offset production well (16B-32) the following winter, drill mud was sampled and analyzed for the three tracers injected during the previous year’s hydrofracturing process. All three tracers were subsequently measured in the mud samples, suggesting that well 16B-32 had intersected the fractures created during the hydrofracturing of the first well. Samples of core that were retrieved during the drilling of 16B-32 were also analyzed for the presence of tracer. These samples were obtained by rinsing core-fracture surfaces with deionized water. Laboratory analyses of the rinsate from those cores showed that tracer from the 2022 injection had absorbed onto some of the open fractures, further substantiating the notion that the 16B-32 trajectory had successfully intersected the fractures extending from well 16A-32. Whereas these initial studies at the Utah FORGE site were focused on the use of conservative (i.e., nonreactive) tracers, future investigations will focus on field-wide, interwell flow using combinations of conservative tracers in combination with reactive (e.g., reversibly adsorbing) tracers. In a 10-well hydrofracture experiment in a hot, shale-gas reservoir at Dilly Creek, British Columbia, various combinations of conservative and reactive tracers were continuously dosed into wells during the hydrofracturing process. Measured tracer concentrations in the flowback fluids revealed a correlation between fracture surface area and subsequent gas production rate. In a future research project at Utah FORGE, the approach used to characterize fracture surface area in shale-gas reservoirs will be extended to characterize heat-exchange area in an EGS reservoir. The tracers that we used in both of the above studies were the well-characterized naphthalene sulfonates, which had been developed for use in geothermal reservoirs under mandate from DOE/EERE at EGI two decades previously and which have subsequently been used in a variety of settings including petroleum reservoirs and groundwater aquifers. In this paper, we show how these tracers can be used to characterize reservoir fluid volume, fracture surface area, inter-well flow patterns, and flow through discrete fractures.

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