Saline aquifer carbon sequestration is a key strategy for mitigating greenhouse gas emissions and supporting energy sustainability. However, salt precipitation induced by CO2 injection can substantially impair storage efficiency. A clear understanding of salt precipitation dynamics is therefore essential for predicting crystal distribution and assessing pore-scale structural damage. In this study, microfluidic technology combined with image-based quantitative pore-scale analysis was used to systematically investigate salt precipitation behavior. Molecular dynamics (MD) simulations were performed to complement microfluidic experiments and to elucidate the molecular mechanisms underlying ion interaction and salt crystallization. The results indicate that salt precipitation proceeds through five stages: nucleation, migration, growth, retention, and blockage. Nucleation occurs in two distinct structural forms at four characteristic locations, including bulk crystals in high-saturation regions and porous aggregated crystals in low-saturation areas. Crystal migration is governed by the availability of brine as a transport medium and by weak crystal–surface adhesion. Retention and blockage develop through both in-situ and ex-situ modes, with hygroscopicity, concentration gradients, and capillary backflow playing critical roles in ex-situ precipitation. MD simulations revealed salt precipitation features consistent with those observed in the microfluidic experiments and confirmed that nucleation preferentially occurs at gas-liquid interfaces and three-phase contact regions, driven by ion aggregation and surface interactions. In porous media, both brine evaporation and salt crystallization follow a three-stage process, which significantly impacts pore structure and permeability. This study provides new mechanistic insights into salt-induced pore blockage and offers guidance for optimizing CO2 injection strategies, thereby advancing the understanding of salt precipitation processes in subsurface gas storage and related engineering applications.

Janus nanoparticles (JNPs) exhibit significant promise for enhancing oil recovery (EOR). However, their large-scale field deployment remains challenging. A key challenge lies in the insufficient understanding of how the physical characteristics of JNPs influence their transport behavior and microscopic oil displacement mechanisms in porous media. In this study, molecular dynamics (MD) simulations are employed to systematically investigate the displacement dynamics of oil trapped on rough surfaces mediated by JNPs of various geometries. The results reveal that particle shape critically affects both the pinning resistance encountered at groove edges and the accumulation patterns along lateral walls. These shape-dependent adsorption configurations in turn modulate local wettability and ultimately dictate the efficiency of oil removal from nanoscale grooves. Spherical and ellipsoidal JNPs demonstrate superior displacement performance when the groove surface is coated with a thin oil film. However, under conditions involving thick oil films, spherical JNPs exhibit limited penetration into narrow grooves due to their stable orientation at the oil-water interface, which reflects strong interfacial stability. In contrast, disc, rod, and ellipsoidal JNPs effectively disrupt thick oil films via a cooperative mechanism termed "aggregation and flipping". Among all evaluated geometries, ellipsoidal JNPs consistently deliver optimal EOR performance across various oil film conditions. These findings provide molecular-level insights into shape-governed JNP performance in EOR, offering valuable guidance for the rational design and application of shape-optimized JNPs in oilfield operations. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

Carbon dioxide (CO2) geological sequestration represents a critical strategy to achieving carbon neutrality and mitigating anthropogenic greenhouse gas emissions. However, salt precipitation during CO2 injection induces pore-scale clogging, thereby threatening long-term storage integrity. Existing pore-scale investigations have predominantly idealized homogeneous models, which limit the understanding of salt precipitation dynamics in realistic heterogeneous and fractured systems. In this study, six microfluidic models-covering homogeneous, heterogeneous, and fractured networks-were developed using a self-designed visualization platform integrated with an image-recognition algorithm. This approach enabled direct observation and quantitative characterization of the coupled processes of brine evaporation, salt precipitation, and pore blockage. The results demonstrate that pore geometry and structural heterogeneity exert dominant control over salt precipitation behavior. Smaller pores promote brine retention and accelerate localized evaporation, whereas enhanced heterogeneity facilitates preferential CO2 migration pathways, intensifying residual brine entrapment and promoting heterogeneous salt precipitation. In fractured networks, early drying and precipitation trigger capillary-induced brine backflow from the matrix, resulting in secondary precipitation and a self-enhanced clogging mechanism. These findings elucidate the fundamental pore-scale mechanisms governing salt precipitation dynamics and provide a mechanistic foundation for improving predictive models and optimizing CO2 injection strategies.

The Chang 7 member of the Ordos Basin hosts abundant shale oil and gas resources and plays a vital role in the development of unconventional energy. This study investigates differences in damage evolution and underlying mechanisms between representative shale oil and shale gas reservoir cores from the Chang 7 member under fracturing fluid hydration. A combination of high-temperature expansion tests, nuclear magnetic resonance (NMR), and micro-computed tomography (Micro-CT) was used to systematically characterize macroscopic expansion behavior and microscopic pore structure evolution. Results indicate that shale gas cores undergo faster expansion and higher imbibition rates during hydration (reaching stability in 10 h vs. 23 h for shale oil cores), making them more vulnerable to water-lock damage, while shale oil cores exhibit slower hydration but more pronounced pore structure reconstruction. After 72 h of immersion in fracturing fluid, both core types experienced reduced pore volumes and structural reorganization; however, shale oil cores demonstrated greater capacity for pore reconstruction, with a newly formed pore volume fraction of 34.5% compared to 24.6% for shale gas cores. NMR and Micro-CT analyses reveal that hydration is not merely a destructive process but a dynamic “damage–reconstruction” evolution. Furthermore, the addition of clay stabilizers effectively mitigates water sensitivity and preserves pore structure, with 0.7% identified as the optimal concentration. The research results not only reveal the differential response law of fracturing fluid damage in the Chang 7 shale reservoir but also provide a theoretical basis and technical support for optimizing fracturing fluid systems and achieving differential production increases.

High temperature and short-term subsurface heat storage using BTES is a promising option and an emerging technology for increasing the fraction of renewable energy in the heat sector and supplying stored heat at high and directly usable temperatures. Investigation of thermal interactions of multiple BHEs employed for high-temperature cyclic storage operations is required to understand the system behavior and the relevant thermal processes involved. This work therefore presents highly controlled meso-scale experiments for high temperature borehole thermal energy storage. The experiment is set up at Kiel University, using a sand pit with two-meter depth and a volume of 37 m³ filled with partially saturated fine sand. Five BHEs are constructed, with four positioned at the edges of a square of 0.7 m side length and the fifth one in the center. The temperatures are measured at 224 locations at varying distances and depths from the center BHE. For the tests, inflow temperatures of the BHEs were set to represent a high temperature storage system for both stationary and cyclic heat loads by using 70°C and 10-15°C inflow temperature for heating and cooling cycles, respectively. The range of the cycles was changed from 12 to 120 hours. All BHEs were jointly operated using the same inflow temperatures, to determine the effect of their thermal interactions on the recovery factor of cyclic storage operations. Thermal interaction due to the simultaneous operation of the BHEs reduced the heat transfer rate by about 30% after 12 hours of continuous heating in the center BHE, while for the outer BHEs the heat transfer rate was reduced by approximately 24%. After about three days of continuous heating, heat transfer rates have stabilized at about 60% in the outer and 40% in the center BHE. Based on these values, a thermal recovery factor of 55% is obtained. For the cyclic heat storage experiments, similar utilization ratios were found, although average heat transfer rates for the individual BHEs increase with decreasing cycle time. Furthermore, although heat transfer rates are lower in the joint operation of the BHEs, temperatures in the sand are higher. Temperatures in the sand at 0.2 m from the center BHE increase from 30°C for individual BHE operation to 57 °C in the joint operation, thus providing higher storage temperatures.

CO2 geo-storage in saline aquifers offers significant potential for reducing greenhouse gas emissions. However, salt precipitation resulting from mineral crystallization during gas-liquid percolation affects CO2 injectivity and storage efficiency. This review synthesizes recent field data, experiments, numerical simulations, and theoretical studies to identify knowledge gaps and improve understanding. It provides insights into the dynamics, mechanisms, factors, and mitigation strategies of salt precipitation for COQ geo-storage in saline aquifers. Field data indicate that salt precipitation mainly occurs within 10-30 m of the wellbore, reducing absolute permeability by 60-70 %. Experimental and numerical studies suggest that capillary-driven drying leads to significant pore blockage near the wellbore, while diffusion- or evaporation-driven mechanisms cause more evenly distributed precipitation. Despite a decrease in absolute permeability, CO2 relative permeability may increase by 5-6 times. Two major challenges contribute to discrepancies between theoretical models and field data: the migration behavior of salt crystallization and dynamic evaporation of the brine. Addressing these challenges requires hightemperature, high-pressure microchip experiments to visualize and quantify brine evaporation dynamics and salt precipitation at the pore scale. Additionally, core flooding tests, coupled with real-time CT/MRI imaging and particle flow simulations, are essential for investigating the interaction between salt precipitation and pore structure damage. Despite the significant impact of reservoir characteristics, brine properties, and injection strategies on salt precipitation dynamics, systematic studies remain limited, and current research is fragmented. This review proposes a comprehensive evaluation framework incorporating multi-factor coupling to better assess salt precipitation risks and improve COQ storage efficiency. These findings provide a foundation for managing salt precipitation in subsurface engineering, with broader implications for energy extraction and carbon storage.

In response to the development challenges caused by the high initial water saturation, low porosity, low permeability, and strong heterogeneity in C tight sandstone reservoirs, a comprehensive study was conducted on the optimization of development methods using a fuzzy model, core flooding experiments, and reservoir numerical simulations. The initial evaluation indicates the good adaptability of CO2 flooding for improving oil recovery in a C reservoir; the experimental result of the CO2 displacement method also performs the best, with a recovery rate of 68.38% at a connate water saturation of about 30%, compared with surfactant flooding and water flooding. However, higher water saturation inhibits the CO2 development effect. The oil recovery factor of pure CO2 huff-n-puff is 32.24% lower than the CO2 displacement method, while surfactant-assisted CO2 huff-n-puff can increase the recovery rate by 0.85% compared to pure CO2. Based on actual geological models, numerical simulations were conducted on Well Block A and B. The results showed that the optimized production pressure is above the Minimum Miscibility Pressure (16.44 MPa); with consideration of the fracture pressure limitation, the CO2 injection rate in Block A should be less than 3000 m3/d, and the recovery rate after 10 years is only 0.48% (oil change ratio is 0.07 t/t), while the CO2 displacement rate of Block B should not exceed 7500 m3/d, and the recovery rate after 10 years can reach 27.39% (oil change ratio is 0.2 t/t). CO2 displacement is an effective development method for a C reservoir, but due to a high water content the oil change ratio is very low, indicating a low potential for further development. The research provides important references for the development of similar oil reservoirs.

Salt precipitation occurs during CO2 geo-sequestration injection, especially within 10 m of injection wells, affecting injection efficiency and storage capacity. While most studies focus on NaCl solutions, few investigate other salts, such as CaCl2. This study first compared the evaporation and crystallization behaviors of NaCl, KCl, CaCl2, and MgCl2 through droplet evaporation tests. NaCl and CaCl2, which showed distinct drying characteristics and are common in formation brine, were then selected as representative monovalent and divalent salts for further investigation in porous media using a self-developed microfluidic platform, creating a database for single salt solutions. Additionally, a mixed NaCl-CaCl2 solution was tested to study the dynamics of mixed salts. Results reveal significant differences between NaCl and CaCl2: NaCl forms both bulk and porous aggregated crystals with ex situ precipitation, while CaCl2 forms a dense hydrated salt layer due to its low deliquescence relative humidity and strong lattice hydration tendency. The mixed NaCl-CaCl2 system exhibits precipitation dynamics similar to CaCl2, with the formation of a hydrated salt layer (e.g., CaCl2.6H2O, CaCl2.2H2O) that hinders further brine evaporation and solute diffusion, thereby promoting NaCl bulk crystallization while suppressing the development of porous structures. This study challenges the NaCl model and provides a new framework for salt precipitation in multi-salt systems, with implications for chemical engineering, desalination, and geothermal energy.

High-temperature borehole thermal energy storage in the subsurface offers a promising solution to balance the seasonal mismatch between heat demand and supply from renewable sources. For most borehole thermal energy storage systems, a considerable fraction of the storage volume close to the ground surface will be in unsaturated conditions, characterized by comparably low thermal conductivity and heat capacity. This affects the achievable heat transfer rates of the borehole heat exchangers as well as the thermal interaction of neighboring borehole heat exchangers and thus influences the overall borehole thermal energy storage performance. In order to investigate the heat transfer behavior of individual borehole heat exchangers and the thermal interactions between these borehole heat exchangers at high storage temperatures, a series of experiments with up to five borehole heat exchangers in unsaturated low-permeable sandy soil is performed under well controlled conditions with extensive in-situ temperature monitoring. First, a high-temperature thermal response test at inlet temperatures close to 70 degrees C was performed for each borehole heat exchanger individually. The thermal conductivity of the unsaturated soil derived from the thermal response test was approximately 30 % higher than values obtained in the laboratory or reported in the literature for standard temperature conditions. This demonstrates that hightemperature borehole thermal energy storage can be as effective for partially saturated conditions as for fully saturated conditions. In a second step, the high-temperature thermal response test were repeated using different numbers, spatial combinations and separation distances of the active borehole heat exchangers. Notably, there was a significant reduction of up to 50 % in the thermal performance of an individual borehole heat exchanger due to thermal interactions with neighboring BHEs, particularly for smaller separation distances or higher active borehole heat exchanger numbers. Finally, a geometrically detailed numerical heat transport model was developed, which accurately predicts the individual and combined borehole heat exchanger operations in terms of the achieved heat transfer rates and cumulative energy input with a precision of +/- 3 %, as well as the measured soil temperatures with mean absolute errors on the order of 0.6 to 3.4 degrees C, if the thermal conductivity derived from the high-temperature thermal response tests is used. The numerical model thus is capable of assessing the energy balance, storage operation, and induced thermal impacts of high-temperature borehole thermal energy storage in the unsaturated subsurface. This study for the first time demonstrates that dedicated high-temperature thermal response tests at the scheduled temperature level of a high-temperature borehole thermal energy storage are required for a reliable characterization of unsaturated soil thermal properties and the parametrization of simulation models used to design and operate such a storage site. The combined experimental and numerical work shown here substantially improves the process understanding of heat transport and thermal interactions of borehole heat exchangers in unsaturated porous media and therefore benefits the design and operation of future large-scale high-temperature borehole thermal energy storage systems.

Thermally induced convection in the vicinity of borehole heat exchangers (BHE) in porous media affects the heat transfer behaviour between the BHE and the surrounding ground and thereby their performance for building climatization, heat extraction and heat storage. This study presents a combined experimental-numerical analysis of the qualitative and quantitative impacts of convection on heat transfer for a laboratory-scale BHE analogue over a wide temperature range. For this purpose, a grouted coaxial high-temperature BHE was installed within a fully saturated porous sand medium in a cylindrical container of 1.4 m3 volume under spatially extensive temperature monitoring. Four transient heat charging/discharging experiments were performed at different charging temperatures of 30, 50, 70, and 90 & DEG;C and analysed for the onset and magnitude of convection. After minimal calibration, a numerical model accurately reproduced the experimental data of all experiments and helped quantify the contribution of convection to the total heat transfer at each temperature level. For heat charging at 30 & DEG;C, the heat transfer was dominated by conduction. At higher temperatures, convection increased the total heat-transfer rate by up to 35% in the experimental setup. In contrast, for heat discharge, due to thermal stratification in the sand medium, convection reduced the heat transfer rate and heat recovery by up to-30% and-35%, respectively. Rayleigh numbers, buoyant flow velocities, and the centre of heat were derived from the monitoring and simulation data and consistently indicated the onset of convection for the experimental setup at a BHE operating temperature of 50 & DEG;C. The Rayleigh number was found to be closely correlated with the magnitude of the convective flow. Overall, the results suggest that the performance of BHEs in cooling applications may benefit from thermal convection, while the performance of BHEs for thermal energy storage may deteriorate markedly at high operating temperatures.

In order to compensate for the variable mismatch between heat demand and heat production from renewable sources or waste heat, high-temperature aquifer thermal energy storage (HT-ATES) is a promising option. A reliable prediction of the energetic performance as well as thermal and hydraulic impacts of a HT-ATES requires a suitable model parameterization regarding the subsurface properties. In order to identify the subsurface parameters on which investigation efforts should be focused, we carried out an extensive sensitivity analysis of the thermal and hydraulic parameters for a high-temperature heat injection test (HIT) using numerical modeling of the governing coupled thermo-hydraulic processes. The heat injection test was carried out in a quaternary shallow aquifer using injection temperatures of about 75 °C over 5 days, accompanied by an extensive temperature monitoring. The sensitivity analysis is conducted for parameter ranges based on literature values, based on site investigation at the HIT site and based on a model calibrated to the measured temperature distribution following the heat injection. Comparing the parameter ranges thus obtained in this three-step approach allows to identify those parameters, for which model prediction uncertainty decreased most, which are also the parameters, that strongly affect the thermal behavior. The highest sensitivity is found for vertical and horizontal hydraulic conductivity as well as for groundwater flow velocity, indicating that investigation efforts for HT-ATES projects should focus on these parameters. Heat capacity and thermal conductivity have a smaller impact on the temperature distribution. Our work thus yields a consistent approach to identifying the parameters which can be best restricted by field investigations and subsequent model calibration. Focusing on these during field investigations thus enable improved model predictions of both HT-ATES operation and induced impacts.

Saline aquifer has become the preferred storage location of carbon capture, and storage (CCS) technology because of its wide distribution, large storage capacity and high safety factor. According to IPCC statistics, the storage capacity of saline aquifers worldwide is 400 – 10000 Gt, which is dozens of times that of oil and gas reservoirs and hundreds of times that of coal seams. Therefore, the carbon storage in saline aquifer has the most potential for CO2 storage. Carbon sequestration in saline aquifers includes four trapping mechanisms: short-term geological and hydrodynamic capture and long-term geochemical (solubility and mineral) capture. Moreover, the solubility of CO2 in saline aquifer and the mechanism of mineral capture (salt precipitation) depends on the injected CO2 and the water-rock characteristics of saline aquifer. However, current knowledge on geochemical capture is still at an early stage compared to other capture theories. Recent researches indicate that although temperature, pressure, salinity of formation water and mineral composition of formation rocks are important factors affecting mineral storage, other reservoir parameters, such as reservoir thickness, dip angle, anisotropy, and bedding distribution, may also significantly affect salt precipitation, mineral storage, and geo-chemical storage. In this paper, we would like to present a comprehensive review on the solubility model of CO2 in saline aquifers, the phase permeability change of CO2 and saline aquifers, the mechanism of CO2-water -rock interaction, the dissolution and precipitation model of inorganic salt minerals, and the influencing factors for CO2 sequestration in saline aquifers. We believe that this review lays a foundation for future study of carbon storage technology in saline aquifer.

High temperature and short-term subsurface heat storage using BTES is a promising option and emerging technology for increasing the fraction of renewable energy in the heat sector and supplying stored heat at high and directly usable temperatures. For this, investigation of thermal interactions of multiple BHEs employed for high-temperature cyclic storage operations is required to understand the system behavior and the relevant thermal processes involved. This work therefore presents highly controlled meso-scale experiments for high temperature borehole thermal energy storage. The experiment is set up at Kiel University, using a sand pit with two meters depth and a volume of 30 m³ filled with partially saturated fine sand. Five BHEs are constructed, with four positioned at the edges of a square of 0.7 m side length and the fifth one in the center. Temperatures were measured at 224 locations at varying distances and depths to the center BHE. For the tests, inflow temperatures of the BHEs were set to mimic a high temperature storage system for both stationary and cyclic heat loads by using 70°C and 10-15°C inflow temperature for heating and cooling cycles, respectively. Cycles ranged from 12 to 120 hours. Thermal characteristics of the boreholes and the sand medium have been determined using constant temperature Thermal Response Tests for the individual boreholes, yielding an average thermal conductivity of about 1.8 W/m/K and typical heat injection/extraction rates of 0.2 kW per meter of BHE length. Subsequently, all BHEs were jointly operated using the same inflow temperatures, in order to determine their thermal interactions in a storage operation. Thermal interaction due to the simultaneous operation of the other BHEs reduced the heat transfer rate by about 30% after 12 hours of continuous heating in the center BHE, while for the outer BHEs the heat transfer rate was reduced by approximately 24%. After about three days of continuous heating, heat transfer rates have stabilized at about 60% in the outer and 40% in the center BHE. Based on these values, a thermal recovery factor of 55% is obtained. For the cyclic heat storage experiments, similar utilization ratios were found, although average heat transfer rates for the individual BHEs increase with decreasing cycle time. Furthermore, although heat transfer rates are lower in the joint operation of the BHEs, temperatures in the sand are actually higher. Temperatures in the sand at 0.2 m from the center BHE increase from 30°C for individual BHE operation to 57 °C in the joint operation, thus providing higher storage temperatures.

High Temperature-Aquifer Thermal Energy Storage (HT-ATES) is a promising option to compensate for the seasonal mismatch between heating supply and demand in the heating sector based on renewable energies. To test and verify numerical and experimental methods for predicting HT-ATES thermo-hydraulic impacts, a smallscale heat injection test with injection temperatures of >70 degrees C was conducted in a shallow aquifer and monitored using a dense temperature sensor network. Prior to the heat injection test, the hydraulic and thermal properties of the field site were investigated and a predictive high-resolution numerical simulation model of the coupled thermo-hydraulic processes was derived based only on this a priori information. The comparison of measured and predicted temperature breakthrough curves showed a good correspondence, suggesting that the model is able to predict the overall thermal behavior. The model predictions were most accurate for long-term and far-field temperature evolution, with lower accuracy for temperature peaks closer to the injection well. Density-driven buoyancy flow was identified as an active heat transport process, due to the relatively high vertical hydraulic conductivity. The numerical model, parameterized based only on a priori site investigation data, is shown suitable for predicting heat transport processes due to a high temperature heat injection, as well as the induced thermal impacts of an HT-ATES system.

This document compiles the data related to a high temperature heat injection test, which was carried out at an injection temperature of 74 °C in a shallow aquifer and is presented by Heldt et al. [1]. The data set contains transient measurements of temperatures at 18 wells in 10 depths and measurements of the experimental boundary conditions (injection temperature and flow rate) at a temporal resolution of up to 1 min. The spatial configuration and the technical details about where and how the data have been measured are provided. In addition, data of a multilevel multi well pumping test are shown. The presented data is useful to gain insights into the thermohydraulic processes induced by a high temperature heat injection test and can furthermore be used for the development and verification of numerical models of the presented experiment and similar applications like high temperature aquifer thermal energy storage.

High-temperature aquifer thermal energy storage (HT-ATES) in the geological subsurface will affect the temperature distribution in and close to the storage site, with potential impacts on groundwater flow and biogeochemistry. Quantification of the subsurface space affected by a HT-ATES operation is thus required as one basis for urban subsurface space planning, which would allow to address potential competitive and conflicting uses of the urban subsurface. Therefore, this study shows a quantitative evaluation of induced thermal impacts and subsurface space required for a synthetic ATES operated at varying temperature levels. A hypothetic seasonal HT-ATES operation is simulated using the coupled groundwater flow and heat transport code OpenGeoSys. A well doublet system consisting of fully screened “warm” and “cold” wells 500 m apart is used for the storage operation. A sandy aquifer typical for the North German Basin at a depth of 110 m and with a thickness of 20 m in between two confining impermeable layers is used as storage formation. Seasonal cyclic storage is simulated for 20 years, assuming charging and discharging for six months each. During charging, water with the aquifer background temperature of 13°C is extracted at the "cold" well, heated to 70°C and reinjected at the “warm” well using a pumping rate of 30 m³/h. During discharging, the stored hot water is retrieved at the "warm" well using the same pumping rate and reinjected at the “cold” well after heat extraction at aquifer background temperature. The simulation results show that during a single storage cycle using a storage temperature of 70°C 7.51 GWh of thermal energy is injected, of which 4.79 GWh can be retrieved. This corresponds to a thermal recovery factor of 63.8% and thus an effective storage capacity of 0.43 kWh/m3/K can be deduced in relation to the heat capacity of the storage medium. For storage temperatures of 18°C, 30°C and 50°C, the effective storage capacity is 0.56 kWh/m3/K, 0.55 kWh/m3/K and 0.49 kWh/m3/K, respectively. By delineating the subsurface volume with a temperature increase larger than 1°C, the subsurface space used for and affected by the storage operation at the storage temperature of 70 °C is determined to be 10.56 million m³. In relation to the retrieved thermal energy, a subsurface volume of 2.2 m3 is thus required to retrieve one kWh of heat energy at 70 °C injection temperature. At lower temperatures of 18°C, 30°C and 50°C, the subsurface space required is 1.77 m3/kWh, 1.54 m3/kWh and 1.76 m3/kWh, respectively. The lower effective storage capacity and the relatively larger required space, which correspond to a lower thermal recovery factor, are caused by induced thermal convection and higher heat losses by conduction at higher temperatures.

Borehole thermal energy storage is a well-established technology for seasonal geological heat storage, where arrays of borehole heat exchangers (BHE) are installed in low permeability geological media dominated by conductive heat transfer. Increasing storage temperatures would increase storage capacities and rates and would thus allow for a better inclusion of BTES in the energy system. When using storage temperatures of up 90°C, however, highly permeable zones or intermediate layers may allow for thermally induced fluid migration and convective heat transport in the storage medium, which may increase heat losses from the storage and thus limit the thermal performance of the BTES system. Therefore, we present results from experimental work and subsequent numerical modelling aimed at quantifying thermally induced convection for a lab-scale BHE in a water saturated porous medium for a temperature range of 20°C to 70°C. The experimental heat storage unit consists of a fully water saturated coarse sand within a cylindrical polypropylene barrel of 1.23 m height and 0.6 m radius and a vertical coaxial BHE, which is grouted by a thermally enhanced cement. The barrel is cooled from the outside using ventilators and laboratory air. A grid of 68 thermocouples is emplaced in the storage medium for monitoring the temperature distribution. For the stationary experiment, heat is transferred to the storage unit using a supply temperature of 70°C for 6 days until a steady state temperature distribution is achieved, followed by 3 days of heat recovery. The dynamic experiment begins with 3 days of heating with 70°C followed by 6 cycles of alternating heating at 70°C and cooling at approximately 18°C for 12 hours each. The stationary experiment reveals a vertical temperature stratification, with temperatures increasing up to 48°C towards the top of the porous medium, as well as a horizontal temperature gradient along the top of the sand, while the lower part of the barrel and the outer wall remain at the laboratory temperature of approximately 18°C. This temperature distribution has stabilized after about 90 hours and represents a clear tilted thermal front, suggesting a significant contribution of induced thermal convection to the overall heat transport. The cyclic experiment shows a decrease of storage temperatures relative to the stationary experiment, with temperatures near to the BHE at the top of the porous lower by 2.5°C and 4.75°C, respectively, because the heating phase is not long enough to reach the stationary temperature distribution. This lower horizontal temperature gradient indicates a weakened thermal convection, however the thermal stratification is conserved. This shows that even under the cyclic loading conditions thermal convection may impair high temperature BTES operation and efficiency. Numerical process simulation of coupled flow and heat transport accounting for variable density and the experimental boundary conditions reproduces the spatial and temporal temperature distribution of both experiments with good accuracy. This shows that induced thermal is causing the observed temperature distributions.

With the transition of the heating sector towards renewable energy sources technologies are needed to compensate for the seasonal mismatch between heat supply and demand. Aquifer thermal energy storage (ATES) is considered a promising candidate for that purpose. Especially high temperature ATES (HT-ATES) with temperatures up to 90 °C has the advantage of higher storage capacities and allows for the direct use of the stored heat without intermediate heat pumps. In order to improve the understanding of processes induced by HT-ATES and to validate numerical tools for the prediction of storage capacities, storage rates as well as thermal impacts, a heat injection field test with an injection temperature of 75 °C was conducted, densely monitored and numerically simulated. This work presents a sensitivity analysis of the governing processes and parameters, from which the parameters on which the simulation results are most dependent are derived and thus identified for future site characterization and monitoring studies. The heat injection test took place at a shallow aquifer with a low natural groundwater flow velocity of 0.07 m/d. Hot water was injected at a borehole using flow rates of 14 l/min for 4.5 days and the resulting thermal plume was monitored by a dense arrangement of thermocouples. Previous to the experiment, the field site was thoroughly investigated for the thermal and hydraulic parameters by standard hydrogeological methods, such as pumping tests, hydraulic head measurements, Hydraulic Profiling Tool (HTP) employment, liner sampling and laboratory measurements. A coupled heat transport and fluid flow model was set up and the heat injection test was simulated using high resolution numerical modelling of the coupled thermo-hydraulic processes using the OpenGeoSys (OGS) simulation code. The comparison of measured and simulated temperature breakthrough curves showed a good correspondence, indicating the capability of the model to predict the general thermal behaviour of the heat injection test. The accuracy was higher for larger distances to the injection well and at the longer time scale, while the largest deviations occurred close to the injection well and shortly after the injection. The model was then used to estimate the sensitivity of the simulated temperature distribution on thermal and hydraulic aquifer parameters, which were varied according to the span of measurements. The thermal plume development is most sensitive on the hydraulic conductivity, since this parameter influences the intensity of buoyancy driven flow and was measured in the large range 3.00E-05 to 7.15 E-04 m/s. The dispersivity and the anisotropy in hydraulic conductivity effect the same process and show a significant impact on the result as well, together with the thermal conductivity. The sensitivity of the simulated temperature distribution on the groundwater flow velocity and the specific heat capacity is a little lower compared to the previously mentioned parameters, while the result is insensitive to the specific storage. It is shown, that a heat injection test in combination with numerical simulations is suitable for identifying parameter sensitivities also on small scales, thus showing the investigation needs for HT-ATES projects.

基于一台增压直喷米勒循环发动机,加装低压废气再循环系统(LP-EGR),通过改变EGR率,研究LP-EGR对汽油机燃烧和油耗的影响.研究结果表明:在中小负荷工况下,EGR通过降低泵气损失来减小发动机油耗,油耗最高能减小8.41％;在大负荷工况下,EGR通过抑制爆震,修正点火时刻来降低油耗,油耗最高能减小5.67％;在近全负荷工况下,EGR通过降低排气温度,减少"过喷油"来降低油耗,油耗可减小20.4％.在燃烧方面,EGR会导致燃烧放缓,燃烧循环变动增大.随着EGR率的增大,着火时刻推迟,燃烧持续期增大,最大放热率降低,缸内最高温度降低;由于优化了点火提前角,缸内最高压力增大.