Geothermal Energy最新文献

Stimulation techniques to enhance fluid pathways are an important tool to make geothermal projects economically feasible. So far, hydraulic stimulation is used almost exclusively for reservoir-wide improvement of the permeability, but induced seismicity poses a challenge. Chemical stimulation on the other hand has been limited to the close vicinity of the borehole and has barely been considered for the creation of enhanced geothermal reservoirs. However, retardation mechanisms reducing the chemical reaction rate can be used to increase the radius of the chemical stimulation thus enabling a reservoir-wide enhancement of fluid pathways. In this work, we review the technologies of retardation mechanisms for chemical stimulation in geothermal systems and identify five groups of retardation techniques: (i) causing impaired mobility of the acid, e.g., by gelling agents; (ii) causing an impaired dissociation, e.g., by the in-situ generation of the reactive compounds; (iii) blocking the mineral surface area, e.g., by alternating injections of pad fluids and acids; (iv) reducing the reaction rate constant, e.g., by cooling; and (v) changing the chemical equilibrium through chelating agents. We found that most applications are currently based on the use of impaired dissociation, but present research focuses on the development and application of chelating agents. Most of these retardation techniques are adopted from the hydrocarbon industry, but there are several techniques that have not been applied in the geothermal context so far for various reasons. We identify a distinctive lack of in-depth descriptions of the retardation techniques in various studies—mostly to protect intellectual property. However, in the light of public concern regarding fracking techniques and to independently assess potential environmental hazards, scientific examination of proposed techniques is indispensable.

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.

The use of geothermal energy is spreading globally due to its many advantages, especially for heating and cooling. The correct design of a geothermal system requires knowledge of the parameters of the subsoil rocks, and particularly the thermal conductivity (k), which is the intrinsic ability of a material to transfer thermal energy as a result of a temperature gradient. A thermal conductivity map of the geological formations is time-consuming to produce, but can be of great help when selecting the location of a low-enthalpy geothermal installation, resulting in significant savings and an increase in the efficiency of that installation. The preferred option for determining k is an in situ thermal response test, but laboratory methods may be an alternative if it is not available or affordable. In this work, the needle thermal probe method has been used to measure the k of representative outcropping rocks in Oviedo (NW Spain), since it allows to obtain a rapid determination, its cost is comparatively low and it can be implemented in a portable device. 162 measurements have been carried out on a total of 27 samples, ranging from 0.2 (clay) to 5.4 W m⁻¹ K⁻¹ (quartzite). A relationship has been found between the k of the rocks and their characteristics, such as mineralogy, anisotropy or geological age and a thermal conductivity map was created.

The design of well spacing significantly influences the sustainability and economic benefit of geothermal energy extraction. However, most studies have predominantly employed heat production-related parameters as indicators of well spacing, and a comprehensive analysis of well spacing design based on an economic model is necessary for practical implementation. In this study, an economic indicator considering the benefits derived from heat production and operating costs is proposed and applied in the Caofeidian, a typical abandoned oilfield in the Bohai Bay Basin. It offers a refined portrayal of directional wells, moving beyond rudimentary representations, to capture their appropriate degree of complexity and behavior in drilling configurations. First, by integrating thermophysical information and site investigation data from previous oil investigations, a heterogeneous 3D model is constructed to forecast the 30-year temperature and pressure evolution. Then, a modified levelized cost of heat (LCOH-HT) is proposed to perform economic analysis in optimizing the well spacing, revealing an optimal range of 300–600 m for the different selected wells. In comparison with results derived solely from heat production considerations, drilling and pumping costs contribute to a 300 m reduction in the optimal well spacing based on the proposed approach, as a larger well spacing leads to increased hydraulic losses and drilling cost, necessitating greater pumping efforts and costs. This finding underscores the need to balance economic and thermal considerations. In addition, we found the difference in the optimal well spacing in space is also caused by the porosity variations. Porosity affects fluid temperature and pressure, leading to changes in the benefits and costs associated with pressure fluctuations. Notably, this novel economic analysis method is not limited to spacing optimization; it can also be used to optimize operating parameters, such as the flow rate, which could provide practical strategies for geothermal energy extraction.

There are two problems in the prediction of the geothermal field in the PanZ area: (1) the plane scopes have some debates, and (2) the vertical scopes need to be further ascertained. Faced with these two problems, a complete set of methods was developed and summarized, and the details are as follows: a geothermal field can be divided into five elements, i.e., heat source, fault channel, thermal reservoir, cap rock and water; then, they are interpreted and imaged with the help of gravity, magnetic and magnetotelluric (MT) data; and finally, according to the integrity of five elements and the correlation between them, geothermal fields are predicted. In the PanZ area, (1) the normalized vertical derivative of the total horizontal derivative of the Bouguer gravity anomaly was applied to identify the fault channels; (2) the water was recognized using the joint interpretation results from an integrated geophysical profile with gravity and MT data instead of a single MT result; (3) the cap rock was inverted with the Bouguer gravity anomaly, using the Parker–Oldenburg inversion method, and with the help of the MT anomaly in the integrated geophysical profile, the vertical distribution of the geothermal reservoir was further ascertained; and (4) the intermediate acid magmatic rock with radioactivity, i.e., a heat source, was identified with the residual magnetic anomaly, imaged using the magnetic forward formula of the cuboid. Finally, the two geothermal fields were predicted and outlined using the above methods. A comparison of the distributions of the geothermal gradient and the outlet water temperatures of the drill holes indicated that the predicted results are credible. To better understand the effect of the method of predicting the geothermal field, a 3D geological model was constructed from the inverted results using GOCAD software, and the operating mechanism of geothermal system was analyzed based on the migration, storage, heating and insulation of the water element in the other four elements. To determine the reason for the formation of the geothermal field, the geological evolution of four elements was discussed, except the water element.

Only 32 countries in the world have geothermal power plants in operation, with a combined capacity of 16,318 MW installed in 198 geothermal fields with 673 individual power units. Almost 37% of those units are of flash type with a combined capacity of 8598 MW (52.7% of total), followed by binary ORC type units with 25.1% of the installed capacity. The select list of geothermal power countries continues to be headed by the US, followed by Indonesia, the Philippines and Türkiye, and generated 96,552 GWh of electricity, at an average annual capacity factor of 67.5%, which represented 0.34% of the worldwide electric generation. Electricity from geothermal origin represented more than 10% of the total generated in at least seven countries, headed by Kenya, Iceland, and El Salvador. Practically, all geothermal fields in operation are harnessing resources from hydrothermal, conventional reservoirs, through an estimate of 3700 production wells at an annual average production of almost 3 MWh per well. Things could be similar in the next few years if the current trend continues, but all can change due to the world urgency to maintain global warming below the 1.5 °C threshold in the following years.

The Ethiopia Rift System (ERS) is a section of the East African Rift System within Ethiopia extending from the Afar in the northeast to the Kenya border in the southwest. It is apparent that magmatism and magmatic intrusions influence the crustal shape in the ERS resulting in its thinning and the shallowing of magmatic sources at various locations within it. As a consequence, more than 31 volcanoes hosting hydrothermal structures with a conceivable potential to generate massive quantities of geothermal energy have been identified along the ERS. In this study, we map the Curie Point Depth (CDP) over the ERS based on the analysis of aeromagnetic data extracted from the World Digital Magnetic Anomaly Map. Spectral evaluation method was used to estimate the boundaries (top and bottom) of the magnetized crust. Reduced-to-pole (RTP) aeromagnetic records have been divided into 105 (50% overlap) square blocks of 200 × 200 km size. The Curie temperature (580 °C) of magnetite was used to determine the thermal gradient and the heat drift in the area. The depths obtained for the bottom of the magnetized crust are assumed to correspond to the Curie Depths, where the magnetic layer loses all its magnetization. The determined values of Curie Point Depth, geothermal gradient and heat flow for the 50% overlapped 105 blocks, respectively, range from 8.85 to 55.85 km, 10.38 to 65.54 °C/km and 25.96 to 163.84 mW/m². Lower CPD (< 20 km) in the ERS was obtained between Mille and Gewane (southwest Afar), between Adama (Nazret) and Yerer (NMER) and between Wendo Genet and Koti (SMER) localities. These areas, showing low CPD, exhibit excessive geothermal gradient and high heat flow all of which indicate the presence of significant geothermal potential.

Geothermal energy is an abundant natural resource in many regions around the world. However, in some areas, the temperature of the geothermal energy resource is too low to be efficiently harvested. Organic Rankine cycles (ORCs) are known for recovering heat from low-temperature resources and generating electricity. Furthermore, half-effect absorption chillers (HEACs) are designed to produce cooling with low-temperature resources. This study proposes a novel configuration that utilizes an ORC for electricity generation, a HEAC for cooling production, and a PEM electrolysis system to produce hydrogen. The power section consists of two turbines, one driven by the vapor produced from the geothermal flow expansion, which powers the PEM section, while the other turbine in the ORC is used to drive pumps and electricity production. First, the system is thermoeconomically analyzed for an initial set of inputs. Then, various parameters are analyzed to determine their influences on system performance. The analyses reveal that the system can work with geothermal source temperatures as low as 80 °C, but the exergy and energy (thermal) efficiencies decrease to around 17% under the base settings. Furthermore, the system is capable of working with resource temperatures up to 170 °C. Ten parameters are found to affect the system’s efficiency and effectiveness. To optimize the system, the Non-dominated Sorting Genetic Algorithm II (NSGA-II) is implemented to find the optimum conditions. The objective functions are exergy efficiency and unit polygeneration cost (UPGC), which can conflict. The optimization shows that the exergy efficiency of the system can reach 48% in the optimal conditions (for a heat source temperature of 112 °C and a mass flow rate of geothermal fluid of 44 kg/s), with a hydrogen production rate of 1.1 kg/h.