Analysis of enhanced geothermal system flowback and circulation test data for fracture and reservoir characterization

Abstract

Geothermal energy has gained increasing attention worldwide, driven by the need for clean energy sources. Evaluation of subsurface properties in geothermal systems is critical for determining resource potential, optimizing energy production, and evaluating the risk of induced seismicity, amongst other applications. However, the thermal and hydraulic properties of geothermal systems are generally unknown or highly uncertain.

This study develops three models to characterize subsurface reservoirs and hydraulic fractures in EGS. A semi-analytical heat transfer model, based on thermal energy balance, and an analytical flow model, derived from material balance, are presented for history matching produced water temperatures and production rates/pressures from an EGS well doublet. Additionally, an analytical flowback model is proposed for analyzing early-time flowback data from the injection well. The models were verified through history matching simulated EGS examples, demonstrating accuracy within a ±5% error range. A geothermal doublet with reservoir heterogeneity was also simulated numerically and history-matched using the semi-analytical model, proving its broader applicability.

To demonstrate practical application of the proposed models, data from the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed. Early time flowback production data from three different stages of hydraulic fracturing of the injection well [Well 16A(78)-32] were evaluated as was data recorded at the production well [Well 16B(78)-32] during circulation testing. The outlet produced water temperatures obtained from the production well were history matched using the semi-analytical heat transfer model to estimate hydraulic fracture (fracture permeability and half-length) and reservoir thermal properties (average subsurface thermal conductivity and specific heat capacity). The early-time flowback data from the injection well were history matched using the analytical flowback model, and the resulting derived fracture properties were compared with microseismic data collected during each stage of hydraulic fracturing. The microseismic data suggest that the half-fracture height for Stage 1, Stage 2 and Stage 3 increased for each subsequent stage. This increasing trend is in agreement with the flowback model-derived fracture heights (205 ft for Stage 1; 315 ft for Stage 2 and 375 ft for Stage 3). These results underscore the need for continued research on analytical models to improve geothermal system characterization and support the advancement of geothermal energy as a sustainable power source.