Enhanced Geothermal Systems Research Articles

A review of advances and applications of geothermal energy extraction using a gravity-assisted heat pipe

Enhanced geothermal system (EGS) provides a feasible way for extracting geothermal energy from hot dry rock (HDR) reservoirs, whereas seismic risk it might induce and enormous cost impair its prospects. For sustainability, circulating fluid in a closed loop to extract thermal energy from a deep geothermal reservoir seems more reasonable and receives increasing attention. With this aim, using a super long gravity heat pipe (SLGHP) to extract geothermal energy from HDR reservoirs was tried by several researchers due to its extremely extraordinary heat transport ability. Jiang et al. designed a SLGHP, by which a thermal power as high as 200 kW was achieved from a 3000 m depth HDR reservoir successfully. The pioneering work proves the feasibility of a safer way for harvesting geothermal energy other than EGS, more importantly, it does not consume power and avoids the toughest issue of pipe scaling in a conventional geothermal production system. The article reviews the latest advances in SLGHPs for geothermal energy extraction. Laboratory experiments and representative in-situ tests are thoroughly analyzed with respect to technologies employing natural circulation inclusive of gravity-assisted heat pipe (GHP) to harvest geothermal energy. Theoretical and numerical work is also reviewed as significant supplements to experimental investigation. Key factors involved are discussed to clarify the challenges of GHPs in engineering for geothermal energy extraction. Low thermal extraction power and economic benefits as well as lack of highly efficient technology to convert heat to electricity are the main barriers of the application of SLGHPs in geothermal energy extraction and utilization. Nonetheless, previous investigation on SLGHPs offers new insights into geothermal energy exploitation from HDR reservoirs.

Heat Production Performance from an Enhanced Geothermal System (EGS) Using CO2 as the Working Fluid

CO2-based enhanced geothermal systems (CO2-EGS) are greatly attractive in geothermal energy production due to their high flow rates and the additional benefit of CO2 geological storage. In this work, a CO2-EGS model is built based on the available geological data in the Gonghe Basin, Northwest China. In our model, the wellbore flow is considered and coupled with a geothermal reservoir to better simulate the complex CO2 flow and heat production behavior. Based on the fractured geothermal reservoir at depths between 2900 m and 3300 m, the long-term (30-year) heat production performance is predicted using CO2 as the working fluid with fixed wellhead pressure. The results indicate that the proposed CO2-EGS will obtain an ascending heat extraction rate in the first 9 years, followed by a slight decrease in the following 21 years. Due to the significant natural convection of CO2 (e.g., low viscosity and density) in the geothermal reservoir, the mass production rate of the CO2-EGS will reach 150 kg/s. The heat extraction rates will be greater than 32 MW throughout the 30-year production period, showing a significant production performance. However, the Joule–Thomson effect in the wellbore will result in a drastic decrease in production temperature (e.g., a 62.6 °C decrease in the production well). This means that the pre-optimization analyses and physical material treatments are required during geothermal production using CO2 as the working fluid.

Rock damage evolution in the production process of the enhanced geothermal systems considering thermal-hydrological-mechanical and damage (THM-D)

Hot dry rocks (HDRs) geothermal relies mainly on enhanced geothermal systems (EGS) for production. During production, the evolution of rock stress distribution will cause damage to the rock, especially near fractures. The application of damage mechanics in the geothermal field has mostly focused on the process of hydraulic fracturing, with limited reports on damage research related to long-term water injection development. According to previous experimental studies, the effect of rock damage is significant and cannot be ignored. Therefore, based on a thermal-hydrological-mechanical and damage (THM-D) coupling model, it studies the rock damage evolution features and its role in changes in rock physical properties. It also analyzed the effects of the initial temperature, injection flow, fracture curvature/number, and stress difference on damage evolution. Results indicate that the damage area and degree continue to increase with time, but the growth rate becomes slower. There are two methods of damage evolution: the new damage caused by the expansion of the low-temperature region is throughout the process, and the original damage is aggravated in the later stages. Damage will cause changes such as reduced Young's modulus (negative feedback) and increased permeability (positive feedback) of the rock matrix, which in turn affect the damage evolution. More, damage increases with the initial rock temperature, injection mass flow, and stress difference increase, and the impact of the fracture curvature is small. The damage of complex fracture reservoirs is more pronounced than that of single fracture reservoirs. This study provides a tool for analyzing the impact of damage on the production performance of HDRs. The investigation of relevant patterns is expected to offer guidance for production strategies.

Thermal‒hydraulic‒mechanical‒chemical coupling analysis of enhanced geothermal systems based on an embedded discrete fracture model

Enhanced geothermal system (EGS) is subject to the comprehensive effects of multiple physical fields during the long-term heat extraction process, including hydraulic (H), thermal (T), mechanical (M) and chemical (C) fields. The embedded discrete fracture model (EDFM) can effectively simulate the variations of flow, temperature, mechanical and concentration fields in fractured reservoirs. At present, however, the thermo-hydro-mechanical-chemical (THMC) coupling model based on EDFM is less researched. In this paper, the THMC coupling model of fractured reservoir is established based on EDFM by considering the changes in reservoir heterogeneity and physical properties as well as water–rock reactions. Then, the spatiotemporal evolution of flow, temperature, displacement and concentration fields in the operation process of EGS is simulated and analyzed. And the following research results are obtained. First, when the permeability of the basement rock is low, the production temperature decrease during exploitation is gradual, allowing EGS to maintain a high exploitation temperature for an extended period. However, lower permeability may result in a decrease in the quality flow rate from production wells, thereby affecting net heat extraction power. Second, when fracture permeability or fracture opening changes, EGS can output higher temperature stably for a certain period and then the temperature decreases at different amplitudes. When the fracture permeability increases to a certain value or the fracture opening decreases to a certain value, the influence of the change in fracture parameters on production temperature gets weak. Third, After 40 years of EGS operation, considering variable property fluids results in a 22 °C lower exploitation temperature compared to using constant property fluids, and considering water–rock reactions results in a 15 °C lower exploitation temperature, with a 12.5 % increase in reservoir average porosity. In conclusion, when researching a long-term operating EGS, it is necessary to comprehensively consider the influences of reservoir rock parameters, physical properties of injected fluid, water–rock reaction and other factors. And in the future, attention shall be paid to the two-way coupling of chemical reaction and mechanical deformation of other mineral compositions in the reservoir to the hydro-thermo-chemical field influence, so as to provide more accurate and reliable prediction for the engineering development and utilization of EGS reservoirs.

Spatial Characterization of Channeling in Sheared Rough‐Walled Fractures in the Transition to Nonlinear Fluid Flow

AbstractAccurate quantification of spatially resolved fluid flow within fractures is crucial for successful reservoir development, such as Enhanced Geothermal Systems. This study presents an innovative workflow designed to model and characterize preferential flow paths (channels) within rough‐walled shear fractures. A set of 30 rough‐walled self‐affine fractures, all possessing identical roughness characteristics, is stochastically generated. By solving the nonlinear Navier‐Stokes equations in 420 individual realizations, the transition from linear to nonlinear flow regimes and the two extreme flow directions perpendicular and parallel to the shearing are numerically captured. A distinguishing feature of this approach is its comprehensive statistical analysis, which encompasses both the geometric and transport properties of flow paths in the non‐simplified three‐dimensional fractured void space under typical geothermal flow conditions. In a perpendicular orientation of flow and shearing, fluid flow exhibits pronounced localization, with more than one‐third of the volumetric flow concentrated within 15% of the fracture volume. In contrast, parallel to the shearing, a complex pattern of individual tortuous channels emerges, with flow occurring in 22% of the void space. Nonlinear effects primarily manifest outside these channels, suggesting that complex flow phenomena may dominate irregular fracture structures, such as contact zones or asperities. In the parallel case, increased flow rates lead to an amplification of channeling processes resulting in less affected volume and diminished tortuosity of the main flow path, while in perpendicular orientation nonlinear effects are only of minor importance. The small‐scale flow regime of both extreme cases tends to converge with increasing flow rates.

The role of temperature‐enhanced fault closure in promoting postinjection pressure diffusion and seismicity in enhanced geothermal systems

AbstractPost shut‐in seismic events in enhanced geothermal systems (EGSs) occur predominantly at the outer rim of the co‐injection seismic cloud. The concept of postinjection fracture and fault closure near the injection well has been proposed and validated as a mechanism for enhancing post shut‐in pressure diffusion that promotes seismic hazard. This phenomenon is primarily attributed to the poro‐elastic closure of fractures resulting from the reduction of wellbore pressure after injection termination. However, the thermal effects in EGSs, mainly including heat transfer and thermal stress, may not be trivial and their role in postinjection fault closure and pressure evolution needs to be explored. In this study, we performed numerical simulations to analyze the relative importance of poro‐elasticity, heat transfer, and thermo‐elasticity in promoting postinjection fault closure and pressure diffusion. The numerical model was first validated against analytical solutions in terms of fluid pressure diffusion and against heated flow‐through experiments in terms of thermal processes. We then quantified and distinguished the contribution of each individual mechanism by comparing four different shut‐in scenarios simulated under different coupled conditions. Our results highlight the importance of poro‐elastic fault closure in promoting postinjection pressure buildup and seismicity, and suggest that heat transfer can further augment the fault closure‐induced pressure increase and thus potentially intensify the postinjection seismic hazard, with minimal contribution from thermo‐elasticity.

Production performance optimization of water-enhanced geothermal system based on effective time-averaged volume

Enhanced geothermal systems (EGS) hold great promise for geothermal energy extraction. However, accurately evaluating reservoirs and fractures remains a primary challenge in optimizing the production performance of EGS. This study addresses this gap by introducing a novel index, the effective time-averaged volume. It assesses the effectiveness of reservoirs and fractures, and system economy, making it a valuable tool for determining effective utilization times. Through establishing a triple-well fractured model, parametric studies are innovatively conducted. Results indicate that a reduced effective time-averaged volume leads to a higher thermal recovery rate and greater power generation. The optimized parameters of the model are a reservoir permeability of 0.5 mD, a primary fracture permeability of 50 D, an injection flow rate of 45 kg/s, an injection temperature of 20 °C, and a well spacing of 200 m. The cumulative power generation and effective time-averaged volume of the reservoir for 45 years are 4.89 × 106 GJ and 4.78 × 108 m3, respectively. Furthermore, we quantify the contributions of influencing factors to production performance, highlighting the significant impact of injection flow rate on system economy. These insights provide valuable guidance for the efficient design, operation, and optimization of EGS.

Test Shows Fracturing Can Also Create Underground Water Heating Systems

Fervo Energy has shown that fracturing can be used to build a geothermal heating system in hot, hard rock. During a 37-day test at its Project Red test site, the Houston company produced as much as 63 L/s (998 gal/min) of water heated to 336°F. By pumping water from an injection well through fractured hot rock to a producing well, it heated enough water to generate up to 3.5 MW of power, according to a company release. In a world where demand is commonly measured in gigawatts, that’s not much, but it is more than double the highest flow rate from tests going back decades. And unlike those earlier tests, the company has a clear path to heating higher volumes and lowering the cost. “I think this is just a big moment for both our company, but also the industry at large, to finally have this proof point where we can deliver commercial levels of permeability and flow rates for these wells,” said Jack Norbeck, co-founder and chief technical officer for Fervo. The idea of injecting water through hot rock has been around for decades as a way to create enhanced geothermal systems (EGS), but this is the first time someone has achieved this level of flow and is moving next to create a group of geothermal wells for commercial generation. Fervo has taken methods developed to extract oil and gas from ultratight rock and shown they can be used to do something quite different. “Overall, there’s nothing really surprising here—they used a pretty standard shale frac design and observed pretty similar performance from what you would see in a shale play. Or at least, what you’d expect if you used a shale well as a long-term water injector and circulated fluid over to a neighboring production well,” said Mark McClure, chief executive of ResFrac, a reservoir modeling and consulting firm, in a blog post. This fracturing-based option poses a challenge to EGS researchers who live in countries where completions using oil industry fracturing techniques are not an option. “The EGS community has conventionally been focused on ‘stimulating natural fractures,’ and this has led them to use fracture designs that would be considered suboptimal, from the perspective of oil and gas field experience,” McClure said. What Fervo has done is show that fracturing can be used to get past a barrier blocking EGS development using current fracturing technology. “The breakthrough is that someone actually had the guts and organization to go out and do it,” McClure said. Those at Fervo, though, have little time to celebrate the milestone as they focus on improving those methods to economically produce geothermal energy. “In successfully completing this project, we have demonstrated that no major technical barriers exist to deploying horizontal EGS in similar meta-sedimentary or igneous formations to temperatures of approximately 400°F,” according to a Fervo paper. That feat was recognized by a leader at the FORGE test site, which is also doing EGS research and development with substantial financial support from the US Department of Energy.

Reactive Transport Modeling of Chemical Stimulation Processes for an Enhanced Geothermal System (EGS)

An enhanced geothermal system is a kind of artificial geothermal system, which can economically exploit geothermal energy from deep thermal rock mass with low permeability by artificially created geothermal reservoirs. Chemical stimulation refers to a reservoir permeability enhancement method that injects a chemical stimulant into the fractured geothermal reservoir to improve the formation permeability by dissolving minerals. In this study, a reactive solute transport model was established based on TOUGHREACT to find out the effect of chemical stimulation on the reconstruction of a granite-hosted enhanced geothermal system reservoir. The results show that chemical stimulation with mud acid as a stimulant can effectively improve the permeability of fractures near the injection well, the effective penetration distance can reach more than 20 m after 5 days. The improvement of porosity and permeability was mainly caused by the dissolution of feldspar and chlorite. The permeability enhancement increased with the injection flow rate and HF concentration in the stimulant, which was weakly affected by the change in injection temperature. The method of chemical enhancement processes can provide a reference for subsequent enhanced geothermal system engineering designs.

Influence of fracture pattern between Hot Sedimentary Aquifer (HSA) and Enhanced Geothermal Systems (EGS) on thermal production and permeability evolution

Thermal energy extraction relies on the fluid circulation and heat transfer between fluids and rock matrix. The conductive fracture channel provides effective conduits for fluid circulation, while absorbing heat energy from adjacent blocks depending on heat transfer length. The vertical depth variation not only leads to the quality of heat reservoir, but also brings substantial influence on fracture pattern due to stress state and chronological tectonic evolution. Consequently, it is vital to explore the influence of fracture pattern on the model of thermal energy production and subsequent permeability evolution. The induced thermal stress plays an important role in the stress state and fractures and therefore permeability development. It is hypothesized that the two-stage evolution of permeability and porosity: shrinkage effect from thermal cooling is strong sufficient with the highest drawdown gradient, which leads to significant minimum horizontal stress reduction and permeability enhancement. The second stage when rock temperature completely drained allows permeability and porosity reduce to the initial magnitude, with the thermal stress diminishes. The shallow geothermal extraction with less consolidation induces less thermal stress to change rock permeability and porosity. Therefore, the thermal stress needs to be taken into account in evaluating the formation properties evolution and stress state.

Physics-Based Modeling to Understand and to Propose Forecasting Methods of Induced Seismicity

Abstract Induced seismicity compromises the widespread deployment of geoenergy applications that contribute to mitigate climate change. In particular, the development of Enhanced Geothermal Systems (EGS) has been hindered by the risk of induced seismicity, mostly caused by hydraulic stimulation aimed at enhancing the permeability of deep hot crystalline rocks. Injection-induced seismicity has been traditionally attributed to fluid pressure buildup, which destabilizes fractures and faults. However, the largest seismic events commonly occur after the stop of injection, when pore pressure drops and both the magnitude and frequency of induced seismicity is expected to decrease. This counterintuitive phenomenon is not well understood. Yet, understanding the triggering mechanisms is the key to reliably forecast and manage induced seismicity. Here, we investigate the triggering mechanisms of co- and post-injection seismicity using coupled hydromechanical models, considering both a homogeneous and a fault-crossed domain, based on the case of Basel EGS (Switzerland). We find that the combination of pressure diffusion, poroelastic stressing, and static stress transfer explains the occurrence of induced seismicity, especially after the stop of injection, significantly better than the pore pressure alone. Considering a fault zone, which is more permeable and deformable than the surrounding rock, amplifies pressure diffusion along the fault and causes anisotropic variations of the stress field that lead to an increase in the seismicity rate that is orders of magnitude larger than for the homogeneous domain. These results point out that identifying the main geological structures through subsurface characterization is key to improve physics-based induced seismicity forecasting.

Embedded discrete fracture network method for numerical estimation of long-term performance of CO2-EGS under THM coupled framework

In enhanced geothermal system (EGS), the artificial fracture networks created by hydraulic fracturing provide highly conductive channel for heat extraction. Very complicated thermo-hydro-mechanical (THM) coupled processes will be involved during cold CO2 injection into the hot fractured reservoir. In this work, a new THM coupled approach is proposed for simulating the long-term performance of CO2-EGS based on embedded discrete fracture networks (DFNs). Due to significant temperature difference between the injection fluid and surrounding, the heat flow in fractures is governed by local thermal non-equilibrium theory. The THM coupling process is achieved by coupling the mechanical simulator FLAC3D and hydraulic-thermal simulator TOUGH2MP. The feasibility of proposed approach is verified and validated through comparing it with analytical solution and other method. The CO2 injection into a reservoir with stochastically generated DFNs is simulated for a period of 20 years, to study the flow behavior, fracture deformation, and thermal performance. The channeling flow is observed by streamlines of fluid and heat flow. The thermal stress due to temperature drop will enhance the fracture width, further decreasing the injection pressure, which shows the significance of incorporating the THM coupling effect in such high temperature reservoirs. This approach also enriches the tools for CO2-EGS simulation.

Effects of fracture aperture distribution on the performances of the enhanced geothermal system using supercritical CO2 as working fluid

Enhanced Geothermal Systems (EGS) technology has the potential to be a significant source of clean, renewable energy worldwide. A promising alternative to water as the working fluid in EGS is the supercritical carbon dioxide (scCO2), which simultaneously contributes to reducing the atmospheric greenhouse gas emissions. The existing thermal-hydraulic coupled numerical models for non-isothermal two-phase flow in fractured porous media overlook the fracture aperture distributions, which significantly affects EGS performance. This study employs a discrete fracture model with a normal distribution of fracture apertures to investigate the EGS energy performance and carbon sequestration ability. The Monte Carlo method is applied to ensure the simulation results reach a statistical equilibrium from multiple realizations. Results show that the aperture distribution significantly affects EGS performances. The cumulative energy output and total sequestered scCO2 mass can be roughly divided into three stages based on fracture aperture distributions. On the other hand, the effects of aperture distribution become more important as the increase of mean fracture aperture and the reduction of injection pressures. Furthermore, comparing the performances of the EGS using scCO2 and H2O as working fluid, the study found that scCO2-EGS performs better with larger injection pressure, but it is more sensitive to aperture distribution.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

Study on the effect of fracture morphology on fracture deformation based on the thermal-hydraulic-chemical-deformation coupling model

The chemical reaction in the reservoir causes fracture deformation during the heat extraction of enhanced geothermal systems (EGS), affecting thermal performance. The reaction rate is sensitive to temperature, concentration, and reaction-specific surface area. While previous research mainly focuses on the influence of temperature and concentration on fracture deformation, conversely, the effect of fracture morphology(aperture and tortuosity) is ignored. In this study, the deformation characteristics of rough and flat fractures are compared, and the influences of aperture and tortuosity on fracture deformation are analyzed. According to the influence law, the fracture deformation relationship equation between the aperture deformation rate with tortuosity and aperture is fitted. Results show that the deformation of rough fracture is significantly higher than that of flat fracture, and the variations of fracture aperture increase with the aperture and tortuosity. Furthermore, the influence of tortuosity (the variation of aperture increased by 47.97% when the tortuosity increased from 1 to 1.5) is greater than the aperture (that increased by 4.8% when the aperture increased from 0.2 to 1). The rate of aperture change is a logarithmic function of tortuosity and a power function of the aperture. These results provide significant references for the study of EGS, subsurface karst et al.

Monitoring seismicity triggered by geothermal site shutdown with a surface DAS array at Brady Hot Springs

SUMMARY Seismicity induced by fluid injection including wastewater injection, hydrofracking and enhanced geothermal system (EGS) site production draws public attention. Dense arrays have been deployed to improve monitoring capability. In 2016 March, the PoroTomo experiment deployed an 8.6-km-long fibre-optic cable for distributed acoustic sensing (DAS) in the geothermal field at Brady Hot Springs, Nevada, covering an area of 1.5 by 0.5 km. The goal was to assess an integrated technology for characterizing and monitoring temporal changes in the rock mechanical properties of an EGS reservoir in three dimensions. We applied a neural network designed for earthquake detection called ADE-Net2 to the DAS data set to detect seismic events in continuous records. We were able to detect a total of 90 earthquakes, which included 21 events that had not been reported by a previous template-matching study. Additionally, we were able to successfully detect almost all of the active source signals, with only seven events being missed. We used the STA/LTA (short-/long-term average) method to pick arrivals and a clustering method to remove outliers. We initially tried a standard event location algorithm, but the low signal-to-noise ratio resulted in significant picking uncertainty that is up to ∼0.5 s, leading to large location uncertainty. Therefore, we developed a new location method based on the similarity between the theoretical traveltime curve and picked moveout. A grid search scheme was adopted to find the optimal point at which the traveltime curve is most similar to the picked one. Most newly detected earthquakes locate southwest of the DAS array, where five earthquakes were reported by a local seismic network. The plant began shutting down at 19:15 UTC on the March 13, and most earthquakes occurred on the March 14, indicating a relationship between the seismicity and the pressure changes caused by the shutdown of the plant. The pressure changes at epicentres obtained from a simplified model range from 71 to 157 kPa, exceeding a typical earthquake trigger threshold of 10 kPa.

Improving enhanced geothermal systems performance using adaptive fracture conductivity

Maximizing heat extraction from enhanced geothermal systems (EGS) depends heavily on an efficient heat sweeping or basically an effective circulation of water through fracture networks. Fracture hydraulic conductivity can play a critical role in controlling potential thermal breakthroughs; however, the exact geometry and properties of these fractures cannot be determined in practice. Thermal breakthrough remains a main challenge for maintaining efficient heat extraction throughout the lifespan of an EGS project. In this work, we explore the concept of fracture conductivity tuning using temperature-sensitive proppants to extract more heat and delay thermal breakthrough from the particle scale to the reservoir scale. We derive an empirical equation to describe fracture conductivity as a function of proppant properties and in-situ conditions including closure stress and temperature. Sensitivity analysis are performed to determine which parameters are the most crucial in determining the temperature-sensitive proppant permeability. Temperature and thermal expansion coefficient are the main contributing factors to the change in proppant permeability. Poisson’s ratio is found to have negligible impact on the proppant permeability. The derived equation is used to quantify the improvement in heat extraction from EGS at the field scale. The outcome shows that using temperature-sensitive proppant can increase the heat extracted by 47.8% compared to using typical proppant. This work assesses the feasibility of using temperature-sensitive proppants to effectively delay thermal breakthrough and sweep larger amounts of heat from EGS. In addition, this paper provides a quick and robust method to determine the required properties of such temperature-sensitive proppants to achieve uniform thermal gradient along different flow paths in the subsurface autonomously.

A deep-learning based model for fracture network characterization constrained by induced micro-seismicity and tracer test data in enhanced geothermal system

Fracture network developed in hot dry rock (HDR) primarily controls the flow and heat transport in enhanced geothermal system (EGS). Characterization of fracture network in deep geothermal reservoir is among the most challenging tasks. An interpretation framework for explicit delineating complex fracture network is proposed based on induced micro-seismic events, hydraulic stimulation and tracer test data, which are often available in EGS sites. It is processed by (1) the spatial distribution of fracture intensity, size and hydraulic aperture constrained by the hydraulic diffusivity derived from the spatio-temporal distribution of micro-seismic events, (2) numerical models and long short-term memory (LSTM) neural network models for the hydraulic stimulation and tracer test, and (3) parameter inversion model based on the multi-objective Harris hawks optimization (MOHHO) algorithm searching for optimal fracture network parameters minimizing the deviations between model predictions and field observations. This method has been applied to the Habanero EGS site, Australia. The prediction accuracy of the injection wellhead pressure and produced tracer concentration of the inversed micro-seismicity mapping DFN model is improved by 61.16% and 67.35%, respectively, compared with the stochastic DFN model. These results emphasize the importance to integrate induced micro-seismicity monitoring data for the characterization of hydraulically stimulated fracture network.

Elemental dissolution characteristics of granite and gabbro under high-temperature water-rock interactions

In the process of developing hot dry rock (HDR) through enhanced geothermal systems (EGS), it is necessary to inject circulating water to complete thermal energy extraction. However, the injected water will react with the high-temperature rock and produce mineral dissolution, which can destroy the artificial reservoir and affect the development of geothermal energy. To explore the influence of temperature on the solution composition and mineral dissolution after water-rock reaction, this study conducted water-rock interaction experiments on gabbro and granite at different heat treatment temperatures. Subsequently, the changes of solution composition and mineral dissolution with temperature after the reaction were analyzed by inductively coupled plasma mass spectrometry (ICP-MS) and XRD. The results demonstrated that Si, Na, Ca, K, Al, and Mg did not enter the aqueous solution at the same dissolution rate. Si was the primary solute in the solution, mainly resulting from the dissolution of quartz, and the dissolution rates of metallic elements were lower. In the granite-water interaction system, metallic elements such as Na, K, Ca, and Al showed a tendency to enter the solution at low temperatures, i.e., 150–180 °C, and the dissolution rate of Si reached its peak when the water was close to the supercritical state. With the increase in temperature, the dissolution rates of Si and metallic elements showed an initial increasing trend followed by a decrease. When water is in the subcritical to the supercritical state, abrupt fluctuations in the physical properties of water can strongly affect the dissolution of minerals or rocks. The results of this study provide insights into rock corrosion fatigue and mineral scaling in EGS water environment.

Effect of fracture geometry, topology and connectivity on energy recovery from enhanced geothermal systems

A combination of hydraulic fracturing and horizontal wells is now being used to tap geothermal energy from naturally fractured reservoirs. Fully grid-based numerical models are currently used to simulate heat recovery from enhanced geothermal systems (EGS). Such models require a fine unstructured mesh and are computationally expensive. In this paper we present a computationally efficient model that allows us to accurately simulate fracture propagation, fluid flow, and heat transfer in networks of natural fractures that may be created in naturally fractured geothermal reservoirs.The integrated simulator is developed by combining the displacement discontinuity method (DDM) for fracture propagation in naturally fractured reservoirs with a general Green's function solution for fluid and heat flow from the matrix to the fracture. This eliminates the need to discretize the matrix domain resulting in a very computationally efficient solution. A discrete fracture network (DFN) approach is used to represent the pre-existing natural fractures.The model is first validated against an analytical solution for fluid flow and heat transfer in a rock matrix with a single fracture. The computation time with and without discretizing the rock matrix shows a 100-fold reduction in computation cost with very little loss in accuracy. Parametric studies are conducted to investigate the effect of the distribution of natural fracture density, length, and orientation. The results show that the efficiency of tapping geothermal energy is impacted by geometrical and topological complexities of the fracture network and in particular the connectivity of backbone fractures. It is, therefore, important to optimize (not maximize) the connectivity and complexity of the backbone fracture network. The computationally efficient model presented here provides a practical tool for optimizing operational parameters for efficient geothermal production.