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Geothermal energy has emerged as a cornerstone in renewable energy, delivering reliable, low-emission baseload electricity and heating solutions. This review bridges the current knowledge gap by addressing challenges and opportunities for engineers and scientists, especially those transitioning from other professions. It examines deep and shallow geothermal systems and explores the advanced technologies and skills required across various climates and environments. Transferable expertise in drilling, completion, subsurface evaluation, and hydrological assessment is required for geothermal development but must be adapted to meet the demands of high-temperature, high-pressure environments; abrasive rocks; and complex downhole conditions. Emerging technologies like Enhanced Geothermal Systems (EGSs) and closed-loop systems enable sustainable energy extraction from impermeable and dry formations. Shallow systems utilize near-surface thermal gradients, hydrology, and soil conditions for efficient heat pump operations. Sustainable practices, including reinjection, machine learning-driven fracture modeling, and the use of corrosion-resistant alloys, enhance well integrity and long-term performance. Case studies like Utah FORGE and the Geysers in California, US, demonstrate hydraulic stimulation, machine learning, and reservoir management, while Cornell University has advanced integrated hybrid geothermal systems. Government incentives, such as tax credits under the Inflation Reduction Act, and academic initiatives, such as adopting geothermal energy at Cornell and Colorado Mesa Universities, are accelerating geothermal integration. These advancements, combined with transferable expertise, position geothermal energy as a major contributor to the global transition to renewable energy.

Geothermal resources provide green, low‐carbon, and renewable clean energy, with abundant reserves and massive potential for application. The in‐depth analysis of geothermal resources in China, including their distribution and breakdown by shallow, hydrothermal, and hot dry rock (HDR) resources, is made in this study. Using the recent economic reports and state‐of‐the‐art technological solutions, this survey outlines the latest trends in the geothermal power generation in China. The application of geothermal power generation in China is still at an early stage, with the total installed capacity of 27.78 MW. The geothermal power generation technologies, such as dry steam technology, flash technology, binary cycle technology, and enhanced geothermal system (EGS), are briefly discussed and linked to their lucrative implementation sites. In particular, Tibet's Yangbajing is considered to be the most lucrative site for the EGS pilot project. The comparative analysis of low‐cost/large‐scale geothermal power generation technologies, such as low‐ to medium‐temperature one, solar‐geothermal hybrid one, and geothermal power generation in mines, was made, whose results strongly indicated the EGS technical and economical advantages. The concentration of 96% of China's population in the area to the east of Hu line affects the perspectives of high‐cost geothermal projects and has to be accounted in the comprehensive analysis of available data. Based on the revealed trends of geothermal resources’ development in China, the following guidelines are strongly recommended: comprehensive incorporation of geothermal energy generation into China's national energy and climate improvement plans, the rapid implementation of HDR technology, as well as comprehensive adaptation of the geothermal‐related projects to the local conditions/biased distribution of power consumers and state‐of‐the‐art challenges of power consumption. This article discusses the distribution of geothermal resources in China and the assessment of shallow geothermal, hydrothermal geothermal, and HDR resources. The geothermal power generation technologies are briefly discussed and linked to their lucrative implementation sites. Based on the revealed trends of geothermal resources’ development in China, several guidelines are strongly recommended.

With the continuous increase in global greenhouse gas emissions, the impacts of climate change are becoming increasingly severe. In this context, geothermal energy has gained significant attention due to its numerous advantages. Alongside advancements in CO2 geological sequestration technology, the use of CO2 as a working fluid in geothermal systems has emerged as a key research focus. Compared to traditional water-based working fluids, CO2 possesses lower viscosity and higher thermal expansivity, enhancing its mobility in geothermal reservoirs and enabling more efficient heat transfer. Using CO2 as a working fluid not only improves geothermal energy extraction efficiency but also facilitates the long-term sequestration of CO2 within reservoirs. This paper reviews recent research progress on the use of CO2 as a working fluid in Enhanced Geothermal Systems (EGS), with a focus on its potential advantages in improving heat exchange efficiency and power generation capacity. Additionally, the study evaluates the mineralization and sequestration effects of CO2 in reservoirs, as well as its impact on reservoir properties. Finally, the paper discusses the technological developments and economic analyses of integrating CO2 as a working fluid with other technologies. By systematically reviewing the research on CO2 in EGS, this study provides a theoretical foundation for the future development of geothermal energy using CO2 as a working fluid.

This paper, based on a novel hybrid techno-economic model for geothermal power plants with endogenized plant lifetime, investigates the economic feasibility of a sustainable exploitation of geothermal resources for electricity generation. To this end, standard terminology and classifications from the literature are reviewed, such as “sustainability”, “sustainable operation”, “renewability”, “recovery”, “recharge”, and “regeneration”. An illustrative conventional, convective high-enthalpy hydrothermal system is contrasted with an enhanced, conductive low-enthalpy petrothermal system. Furthermore, different (mostly geophysical) sustainable operation criteria for the use of geothermal energy are derived from the literature. The conditions for complying with these criteria are compared with the economic criteria of cost minimization (levelized cost of electricity, LCOE) and profit maximization (net present value, NPV), respectively, revealing differences that vary in intensity, particularly depending on the type of reservoir and their respective properties. For the two case studies, LCOE of 2.9 €-ct/kWh and 16.9 €-ct/kWh are found, which are further scrutinized by a detailed sensitivity analysis. The hydrothermal system, in contrast to the petrothermal system investigated, is found to be able to meet several of the sustainability criteria examined (extraction equals recharge, operating lifetime of 100 to 300 years), whereas economically optimal operation leads to excessive overexploitation in both cases, showing a distinct trade-off between profit maximization and sustainable operation that has not been discussed in the literature so far.

Fracturing a geothermal reservoir of hot dry rock (HDR) by the engineered stimulation is a prerequisite to efficient heat extraction of an enhanced geothermal system (EGS). However, the heat extraction performances of different EGSs employing distinct stimulation strategies remain unclear, resulting in the conundrum that which stimulation mode is optimal for heat extraction. Here, we numerically simulated the reservoir response to different stimulation modes through varying fractures/pipes assemblages, and examined the hydraulic and thermal processes and associated heat extraction performances. We found that the caving‐EGS (C‐EGS) with an adequately fractured reservoir yields the best heat extraction performance. Fractures/pipes in geothermal reservoirs of the fracturing‐EGS and pipe‐EGS inevitably produce preferential flow paths, which accelerate thermal drawdown and shorten the operation lifespan. Increasing connected/unconnected fractures can weaken the effect of preferential flow paths, postpone thermal drawdown, and therefore lead to a more remarkable heat extraction rate. Caving the geothermal reservoir into suitable‐sized blocks is the most effective stimulation in maximizing heat extraction efficiency, and thus, the C‐EGS owns great potential in geothermal energy commercialization. Our key findings facilitate the optimization of geothermal reservoir stimulation for large‐scale HDR exploitation. Thermal responses and heat extraction performances of different enhanced geothermal systems (EGS) with distinct stimulation strategies are examined. Caving‐EGS (C‐EGS) yields the best heat extraction performance with a stable extraction rate over the entire lifespan. Fractures provide preferential flow paths and causes thermal drawdown in fracturing‐ and pipe‐EGS. C‐EGS has great potential in large‐scale deep geothermal energy extraction.

The permeability structure resulting from high fluid pressure stimulation of a geothermal resource is the most important parameter controlling the feasibility and the viability of enhanced geothermal systems (EGS), yet is the most elusive to constrain. Linear diffusion models do a reasonably good job of constraining the front of the stimulated region because of the t1/2 dependence of the perturbation length, but triggering pressures resulting from such models, and the permeability inferred using the diffusivity parameter, drastically underestimate both permeability and pressure changes. This leads to incorrect interpretations about the nature of the system, including the degree of fluid pressures needed to induce seismicity required to enhance the system. Here, I use a minimalist approach to modeling and show that all of the observations from Basel (Switzerland) fluid injection experiment are well matched by a simple model where the dominant control on the system is a large‐scale change in permeability at the onset of slip. The excellent agreement between observations and these simplest of models indicates that these systems may be less complicated than envisaged, thus offering strategies for more sophisticated future modeling to help constrain and exploit these systems. The evolution of the permeability field in the Basel enhanced geothermal system was modelled using a simple non‐linear diffusion model with a step‐wise increase in permeability when the failure condition is reached. This simple model reproduces all the observations obtained during that experiment.

Superhot geothermal environments with temperatures of approximately 400–500 °C at depths of approximately 2–4 km are attracting attention as new kind of geothermal resource. In order to effectively exploit the superhot geothermal resource through the creation of enhanced geothermal systems (superhot EGSs), hydraulic fracturing is a promising technique. Laboratory-scale hydraulic fracturing experiments of granite have recently demonstrated the formation of a dense network of permeable fractures throughout the entire rock body, referred to as a cloud-fracture network, at or near the supercritical temperature for water. Although the process has been presumed to involve continuous infiltration of low-viscosity water into preexisting microfractures followed by creation and merger of the subsequent fractures, a plausible criterion for cloud-fracture network formation is yet to be clarified. The applicability of the Griffith failure criterion is supported by hydraulic fracturing experiments with acoustic emission measurements of granite at 400 °C under true triaxial stress and at 450 °C under conventional triaxial stress. The present study provides, for the first time, a theoretical basis required to establish the procedure for hydraulic fracturing in the superhot EGS.

The objective of this study is to assess the techno-economic potential of the proposed novel energy system, which allows for negative emissions of carbon dioxide (CO2). The analyzed system comprises four main subsystems: a biomass-fired combined heat and power plant integrated with a CO2 capture and compression unit, a CO2 transport pipeline, a CO2-enhanced geothermal system, and a supercritical CO2 Brayton power cycle. For the purpose of the comprehensive techno-economic assessment, the results for the reference biomass-fired combined heat and power plant without CO2 capture are also presented. Based on the proposed framework for energy and economic assessment, the energy efficiencies, the specific primary energy consumption of CO2 avoidance, the cost of CO2 avoidance, and negative CO2 emissions are evaluated based on the results of process simulations. In addition, an overview of the relevant elements of the whole system is provided, taking into account technological progress and technology readiness levels. The specific primary energy consumption per unit of CO2 avoided in the analyzed system is equal to 2.17 MJLHV/kg CO2 for biomass only (and 6.22 MJLHV/kg CO2 when geothermal energy is included) and 3.41 MJLHV/kg CO2 excluding the CO2 utilization in the enhanced geothermal system. Regarding the economic performance of the analyzed system, the levelized cost of electricity and heat are almost two times higher than those of the reference system (239.0 to 127.5 EUR/MWh and 9.4 to 5.0 EUR/GJ), which leads to negative values of the Net Present Value in all analyzed scenarios. The CO2 avoided cost and CO2 negative cost in the business as usual economic scenario are equal to 63.0 and 48.2 EUR/t CO2, respectively, and drop to 27.3 and 20 EUR/t CO2 in the technological development scenario. The analysis proves the economic feasibility of the proposed CO2 utilization and storage option in the enhanced geothermal system integrated with the sCO2 cycle when the cost of CO2 transport and storage is above 10 EUR/t CO2 (at a transport distance of 50 km). The technology readiness level of the proposed technology was assessed as TRL4 (technological development), mainly due to the early stage of the CO2-enhanced geothermal systems development.

Deep borehole heat exchangers (DBHEs) with depths exceeding 500 m have been researched comprehensively in the literature, focusing on both applications and subsurface modelling. This review focuses on conventional (vertical) DBHEs and provides a critical literature survey to analyse (i) methodologies for modelling; (ii) results from heat extraction modelling; (iii) results from modelling deep borehole thermal energy storage; (iv) results from heating and cooling models; and (v) real case studies. Numerical models generally compare well to analytical models whilst maintaining more flexibility, but often with increased computational resources. Whilst in-situ geological parameters cannot be readily modified without resorting to well stimulation techniques (e.g. hydraulic or chemical stimulation), engineering system parameters (such as mass flow rate of the heat transfer fluid) can be optimised to increase thermal yield and overall system performance, and minimise pressure drops. In this active research area, gaps remain, such as limited detailed studies into the effects of geological heterogeneity on heat extraction. Other less studied areas include: DBHE arrays, boundary conditions and modes of operation. A small number of studies have been conducted to investigate the potential for deep borehole thermal energy storage (BTES) and an overview of storage efficiency metrics is provided herein to bring consistency to the reporting of thermal energy storage performance of such systems. The modifications required to accommodate cooling loads are also presented. Finally, the active field of DBHE research is generating a growing number of case studies, particularly in areas with low-cost drilling supply chains or abandoned hydrocarbon or geothermal wells suitable for repurposing. Existing and planned projects are thus presented for conventional (vertical) DBHEs. Despite growing interest in this area of research, further work is needed to explore DBHE systems for cooling and thermal energy storage.

A major challenge in the inversion of subsurface parameters is the ill‐posedness issue caused by the inherent subsurface complexities and the generally spatially sparse data. Appropriate simplifications of inversion models are thus necessary to make the inversion process tractable and meanwhile preserve the predictive ability of the inversion results. In this study, we investigate the effect of model complexity on fracture aperture inversion and thermal performance prediction in a field‐scale EGS model. Principal component analysis was used to map the aperture field to a low‐dimensional latent space. The complexity of the inversion model was quantitatively represented by the percentage of total variance in the original aperture fields preserved by the latent space. Tracer, pressure and flow rate data were used to invert for fracture aperture through an ensemble‐based inversion method, and the inferred aperture field was used to predict thermal performance. With an over‐simplified aperture model, ensemble collapse occurred. The inverted aperture models failed to resolve necessary flow and transport features, leading to a biased thermal performance prediction. A complex aperture model involved excessive features and was prone to overinterpreting the inversion data. Both the tracer/pressure/flow rate data reproduction and thermal prediction showed significant uncertainties, making it difficult to properly estimate long‐term thermal performance. Fortunately, our results indicate that there exists an appropriate model complexity which can simultaneously match inversion data and predict thermal performance with an acceptable uncertainty. The quality of the fit of tracer data appears to be a useful indicator of such an appropriate model complexity. Key Points The effect of model complexity on aperture inversion and thermal prediction in a field‐scale EGS is quantitatively characterized A model preserving only 21% of the variance in the “true” aperture is sufficient to interpret tracer data and predict thermal performance The quality of the fit of tracer data appears to be a reasonable indicator of an appropriate inversion model complexity