Session 2B: Enhanced (or Engineered) Geothermal Systems

The heat recovery efficiency of an enhanced geothermal system (EGS) relies on the flow dynamics of the circulating working fluid in the natural and engineered fractures within the reservoir. The use of Ionic liquids (ILs) as geothermal working fluids is a promising alternative to conventional working fluids such as water due to their favorable properties including wide liquid rage, high thermal stability, and shear thinning behavior. ILs are expected to offer enhanced flow hydraulics and address thermal short-circuiting, a prevalent issue in EGS operations. ILs dynamically adjust their rheological properties in response to localized temperature changes, enabling them to selectively traverse higher temperature flow paths with minimal resistance. Consequently, ILs have the potential to eliminate flow shortcuts, thereby, improving the overall heat recovery from the EGS.

This study investigates the flow behavior of ILs and their performance in EGS. Specifically, it examines correlations between flowrates and pressure drops of three ILs, viz., 1-butyl-3-methyl-imidazolium bromide (BMiMBr), 1-hexylpyridinium tetrafluoroborate (HPyBF4) and 1-hexylpyridinium bromide (HPyBr), within idealized micro fractures. Experimental evaluations were conducted using a microfluidic set-up to simulate flow through micro channels in EGS, utilizing a variety of fluid samples, including DI water, 5% solution of HPyBF4, and 5%, 10%, and 25% solutions of BMiMBr and HPyBr. Furthermore, the study also investigated the high temperature flow behavior of BMiMBr at 20 oC, 50 oC and 80 oC, comparing it to the performance of DI water under the same conditions. The reduction in the frictional pressure drops of the IL are compared to that of DI water, revealing significant hydrodynamic improvements with the IL. Particularly, as temperature increased, the IL showed better performance over DI water in terms of reduction in frictional pressure loss within the microchannels with an average reduction approximating four times larger than that of DI water. This research enhances our understanding of IL flow behavior in microchannels, which is crucial for optimizing heat recovery from EGS and advancing sustainable and cost-effective geothermal operations.

Cornell University is pursuing development of an enhanced geothermal system (EGS) for providing heating to its main campus in Upstate New York. A ~10,000 ft (~3 km) deep vertical observation well (“CUBO”) was drilled in 2022 to characterize the subsurface using wellbore logging, borehole imaging, fluid sampling, mini-frac tests, coring, and drill cutting analysis. Down-hole temperatures measured at 3 km depth are about 80°C, sufficiently high for direct-use heating. The well drilled through generally low porosity and low permeability Paleozoic sedimentary formations and into metamorphic basement rock, encountered at about 9,400 ft depth.

Leveraging subsurface data obtained through CUBO, we investigated technical feasibility and design requirements of a doublet well system with horizontal laterals connected to a fracture network created through hydraulic fracturing. The EGS reservoir is sized to provide a nominal heat output in the range 5 to 10 MWth of continuous heating over a 15-year lifetime with limited thermal drawdown. We applied the Gringarten multiple parallel fractures model, the Cornell Discrete Fracture Simulator FOXFEM, and the commercial simulator ResFrac to estimate required heat transfer area and design a potential hydraulic stimulation treatment. Reservoir simulations indicate that, depending on fluid flow rate and injection temperature, 2 to 3 km2 of effective fracture heat transfer area is required to supply the target heat output of 5 to 10 MWth over 15 years.

Conventional geothermal systems rely on production from naturally occurring subsurface hot aquifers, while Hot Dry Rock (HDR) geothermal technology is a method of extracting geothermal energy from deep underground formations where there is hot but dry rock. A downhole heat exchanger is created by water being injected into the rock through one or several wells at high pressure, causing the rock to fracture and creating a network of permeable pathways. Water is then circulated through these artificial or natural fractures, absorbing heat from the hot rock and bringing this heat to the surface.

High impedance in the fracture network and near the wellbore area is a main contributor to high parasitic energy losses in HDR systems and makes commercial-scale implementation very difficult. The Fenton Hill Hot Dry Rock (HDR) tests, from the 1980s and early 1990s, showed that an increased backpressure can reduce markedly the impedance in the system. In so-called doublet (or two-well) Enhanced Geothermal Systems (EGS), horizontal sections of two wells are connected with fractures filled with proppant to prevent these fractures from closing and creating very high resistance to water circulation. This paper provides an alternative solution to the traditional EGS approach and discusses a recently introduced Geopressured Geothermal System (GGS) that keeps the surface and subsurface systems constantly pressurized above fracture opening pressure or, in other words, relying on pressure-propped fractures to keep impedance low.

Focusing on the hydro-mechanical (HM) performance of GGS, and reserving the full thermal-hydro-mechanical (THM) analysis for a later publication, the results show that the single-well pair GGS is superior to other systems in terms of HM performance. The methodology of this single-well pair GGS builds on that of mechanical storage in deep hydraulic fractures as field tested in South Texas in early 2023.

Numerical simulations were performed to demonstrate how properly engineered GGS resolves crucial surface challenges not previously addressed in heat extraction systems and how these geothermal systems experience a lower system impedance while maintaining commercial flow rates. Comparisons are made between GGS with the base case of a doublet EGS whose fractures are proppant-propped. The mathematical modeling of GGS is a natural extension of the recent modeling for mechanical storage that was additionally validated and calibrated against real-time field data.

Enhanced geothermal systems face a significant obstacle: thermal short-circuiting, where fluid flows through only a few fractures, limiting efficiency. This issue is particularly problematic for horizontal wells with multiple fractures. To address this challenge, we introduce a revolutionary temperature-sensitive flow management system. Equipped with real-time sensors and dynamic flow control devices, this innovative system optimizes injection and production across the lateral, effectively preventing thermal shortcuts. Utilizing this flow management system, operation strategies can be designed to determine when and where to adjust the injection and production rates within a twin-horizontal well Enhanced Geothermal System (EGS). Our numerical simulations demonstrate the system's impressive long-term impact. Over a 50-year period, it maintains a produced fluid temperature 40 K higher than uncontrolled systems, and thus the heat extraction efficiency can be increased significantly by simply applying the presented operation strategy. Our innovative approach has the potential to transform horizontal wells into high-performance EGS, unlocking a future of sustainable and efficient energy production.

The solidified and crystallized magma in the earth’s crust forms igneous rocks such as quartzite and granite. Depending on the depth and geological age, the temperature of these formations is relatively high, and thus, they contain a considerable amount of thermal energy. These formations are not permeable nor contain pore fluid. However, they are brittle and can be stimulated by hydraulic fracturing to gain permeability. The stimulated igneous formations that contain a large amount of thermal energy are considered enhanced geothermal reservoirs. Extracting thermal energy from enhanced geothermal reservoirs requires the presence of a geothermal fluid. Water is the most common geothermal fluid with excellent specific heat capacity; however, the hydraulic properties of water can create undesirable fast paths through large fractures from an injection well to a production well. This phenomenon will reduce the enhanced geothermal reservoir’s heat extraction efficiency and sustainability. A large-scale experimental setup of a high-temperature flow loop system was fabricated to simulate the geothermal fluid hydraulics in two different fracture apertures of granite rock slabs. The two fracture systems are equipped with heating jackets and insulated using high-temperature fiberglass insulation, and they can be controlled independently. The inlet and outlet pressures for the small fracture and the fluid temperature were monitored during the tests. Water as a geothermal fluid was tested to investigate the flow behavior in the small fracture. The initial results for water for single fracture tests flowing through the small fracture produced different pressure drop trends and heat transfer characteristics with varying flow rates. This paper presents the results for single fracture under varying temperatures. Preliminary results showed that heat absorption is a function of applied temperature, flow regime, and flow rate.

One of the difficulties in estimating in-situ stress originates from the limitations on the applicability of the idealized models used for data interpretation. Here we focus on injection tests and make use of laboratory-scale block experiments to examine validity and impact of assumptions embedded in the interpretation methods, specifically, the assumptions of simple planar fracture geometry and that the entire fracture face closes simultaneously. In this context, classic interpretation of maximum and minimum horizontal stress from hydraulic fracturing stress tests typically hinges on three components: 1. the breakdown stress (pb), which is the peak value observed in wellbore pressure evolution; 2. the shut-in pressure, equivalent to the fracture closure pressure (pc), indicating the fluid pressure at which the fracture uniformly closes onto itself; 3. the reopening pressure (pr), where the initiation pressure corresponds to zero tensile strength. However, due to the inherent high-temperature characteristics of Enhanced Geothermal Systems (EGS) reservoirs, subsequent wellbore cooldown via injection and circulation can induce changes in the thermal stress field and more complex fracture patterns. These changes will impose additional complexities on this problem and will also significantly influence the borehole pressure history recorded during fracturing tests. To better understand these complexities, we conducted true-triaxial block fracturing experiments under high-temperature conditions on granite blocks, with analogue granite material and experimental conditions inspired by the Utah FORGE geothermal project. Based on these results, we examine existing protocols for analyzing pressure records include laboratory-derived G-function plots, step-rate tests, and fracture reopening measurements. In some cases the stress estimations from these approaches reasonably match the actual stresses applied in the laboratory. However, in other cases, particularly those with complicated fracture patterns and/or substantial cooling of the wellbore prior to testing, the classical interpretations do not provide estimates that are consistent with the applied stresses. Consequently, our work motivates development of a more robust approach for stress estimation in EGS reservoirs that accounts for wellbore cooling and fracture complexity, especially in the near-wellbore region.

Parts of this work were performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DEAC52-07NA27344