Abstract

Enhanced Geothermal Systems (EGS) seek to utilize hydraulic fracturing to achieve high flow rates from wells drilled in formations with high temperature but low permeability. Since the 1970s, EGS projects have had limited economic success because of insufficient flow rate. In recent years, EGS projects have achieved dramatically improved performance by utilizing multistage fracturing with proppant. Project Cape in Utah is an ongoing EGS project with planned capacity of 400 MWe. In an initial circulation test, the first production well drilled for the project flowed at more than 100 kg/s (54,000 bbl/day), a record for an EGS project. In this paper, we describe modeling work performed to design the fracturing treatment and spacing for the wells. Simulations were performed with a fully integrated hydraulic fracturing and reservoir simulator. The simulations include fracture propagation, proppant placement, heat and mass transport in the fractures and reservoir, geomechanical effects, and a wellbore model. The simulations included both the fracturing treatments and 30 years of fluid circulation between the injection and production wells. The model was calibrated to data collected at the nearby Utah FORGE project, and it was informed by another recent EGS project utilizing multistage fracturing, Project Red. Sensitivity analysis simulations were performed with a variety of fracturing designs and well spacing choices, and the scenarios were evaluated on the basis of energy production over the short and long-term. Sensitivities were used to generate predictions of flow rate and energy production as a function of well placement and fracturing design. Tighter well spacing values result in higher flow rates and greater energy production over the short-term but result in earlier thermal breakthrough and less energy production over the long-term. Increasing the size of the fracturing treatment results in greater flow rate and delayed thermal breakthrough because of greater flow rate and fracturing surface area. The models also predict long-term fluid loss of significantly less than one percent. Fluid loss is low as long as production wells are placed on the outside of the pattern. Based on the results, the operator chose a specific design and executed it in the field. In the initial flow test, the observed circulation rate was within the range of predicted values. The operator is now drilling and fracturing additional wells, building power plants, and advancing the project. Future work will refine the model based on new data collection from the ongoing project.