High-temperature aquifer thermal energy storage (HT-ATES) systems have significant potential to balance the seasonal mismatch between energy supply and demand. Ambient groundwater flow can lead to substantial system energy loss. Thus, the design of injection/production well configurations require particular attention to mitigate the negative impacts of groundwater flow. This study investigates the impacts of well layouts on the system heat efficiency under varying ambient groundwater flow velocities. Based on the results of numerical simulation, a multi-variable regression function was proposed to estimate the system heat efficiency. The functions respecting different parameters are integrated by transforming them into consistent forms. The parameters are optimized for the highly non-linear integrated function. Results indicate that positioning the hot well up-gradient yields the highest energy recovery in a doublet system. Moreover, the relationships between the heat efficiency, well spacing and flow rate follow the exponential decay function, while the efficiency correlates highly linearly with the ambient groundwater flow and deviation angle. Based on the regression function, the well spacing for the well-doublet system should be at least 235 m to obtain a satisfactory heat efficiency for the target geothermal reservoir, reaching more than 82.52 % after 10 operational cycles, with the flow rate of 40 l/s, ambient groundwater flow of 0.1 m/d and the deviation angle of 0 degrees.

High-temperature aquifer thermal energy storage (HT-ATES) systems have significant potential to balance the seasonal mismatch between the energy supply and demand. Due to the monthly global temperature variation, the energy supply and requirement may vary during summer and winter. However, the current investigation rarely discusses the fluctuation of the ATES flow rate (injection and production rates). In this study, a thermal-hydraulic model is employed to investigate the performance of HT-ATES systems under variable operational flow conditions. Specifically, the injection and production rates are assumed to follow a normal distribution, or alternatively, water is injected or produced only during a defined portion of the injection period. Results show that the injection strategy significantly impacts the HT-ATES performances when the ambient groundwater flow velocity is considerable. The energy recovery rate is proportional to the timely water injection ratio, defined as the volume of water injected during the second half of the injection period over the total injected volume. The maximum discrepancy in energy recovery rate reaches nearly 5 % between different injection strategies when the groundwater flow is 0.2 m/d. The production strategy presents an opposite influence on the injection strategies. Furthermore, the HT-ATES demonstrate the capability to deliver higher peak power output in winter while maintaining the energy recovery rate.

Supercritical CO₂–brine relative permeability is a fundamental control on multiphase flow, plume migration, injectivity, and trapping efficiency in geological CO₂ storage. This study presents an integrated, full-cycle SCAL-based modeling framework that explicitly quantifies uncertainty in primary drainage and imbibition CO₂–brine relative permeability and systematically propagates this uncertainty into long-term dynamic reservoir simulations. The workflow combines physics-driven trend models, analogue experimental datasets, and Corey-type parameterization to generate optimistic, base-case, and pessimistic relative permeability scenarios, with all Corey parameters expressed as functions of initial water saturation ( S wi ). Primary drainage relative permeability trends were derived from 37 coreflood experiments spanning sandstone, carbonate, and basalt samples compiled from the NETL–CO2BRA database, while imbibition and residual trapping behavior were assembled from published experimental studies. The resulting uncertainty-bounded drainage and imbibition curves were implemented in a three-dimensional compositional reservoir simulation using the CO2STORE framework to evaluate CO₂ injectivity, plume evolution, dissolution, and trapping mechanisms over a 2-year injection period and a 1,000-year post-injection period. Simulation results demonstrate that relative permeability uncertainty is not a secondary modeling detail but a first-order control on CO₂ storage performance. Optimistic scenarios, characterized by lower CO₂ endpoint relative permeability and higher residual gas saturation, produce compact and vertically confined plumes, enhanced residual and solubility trapping, and improved long-term containment, albeit with moderately higher injection pressures. Pessimistic scenarios favor injectivity but result in faster plume migration, larger plume footprints, sustained mobile CO₂ fractions, and reduced trapping efficiency. By explicitly integrating drainage and imbibition uncertainty within a single coherent SCAL-based workflow and propagating it through dynamic simulations, this study provides a robust and transparent framework for CCS risk assessment, storage design, and project optimization under conditions of limited experimental data availability.

High-temperature aquifer thermal energy storage offers a promising solution for balancing fluctuating energy supply and demand. While previous studies have primarily focused on heat and mass transfer within reservoir, wellbore heat loss has received comparatively limited attention. In this study, a coupled wellbore-reservoir model is developed and validated with a real district case to quantify the impacts of wellbore heat loss on overall system performance. Sensitivity analyses and a comprehensive techno-economic assessment are conducted to identify the dominant factors influencing heat loss. The results indicate that continuous heating losses occur in both the reservoir and the wellbore throughout system operation. At a low flow rate of 10 l/s, nearly 90% of the total energy loss originates from the wellbore. At a higher flow rate of 40 l/s, the contribution of wellbore heat loss decreases but still increases over time, rising from ca. 60% in the 1st year to ca. 70% as the operation proceeds. Furthermore, variations in flow rate and injection strategy primarily affect the system levelized cost of heat through changes in the total recovered energy, whereas improvements in wellbore insulation performance mainly reduce costs by decreasing heat loss within the wellbore.

The expansion of the geothermal industry is constrained by high exploration costs and comparatively low profits. This study presents an efficient and cost-effective exploration strategy that leverages legacy data from mature hydrocarbon fields to assess the feasibility of geothermal development. A numerical workflow was applied to a water-saturated aquifer overlying a depleting gas reservoir, using old wellbore and seismic data to construct a 3D geological model that reflected the geometry and petrophysical properties of the potential geothermal reservoir. An integrated model that incorporates the geological framework with surface mapping was developed to support informed engineering decision-making. A well-doublet plan was proposed for geothermal operation, with careful consideration of both subsurface geology and surface infrastructure constraints. The results indicate that the B & uuml;ckeberg Formation contains four sand layers with potential for geothermal energy recovery. Sand 3 is considered the primary geological target due to its sufficient thickness, favorable petrophysical properties, and high reservoir temperature. A well-doublet cluster in Gro beta burgwedel was identified as the most promising geothermal development target based on geological parameters and surface constraints. The production simulations indicate Sand 3 could sustainably produce 75 degrees C hot water for approximately 24 years. In addition, multiple alternative development scenarios across the region were evaluated, including variations in sand layers and surface locations, which highlight the geothermal potential of the entire study area. This methodology demonstrates the feasibility of repurposing existing legacy geological data to guide low-cost, low-risk geothermal exploration, particularly in mature hydrocarbon fields where geoscientific data has already been acquired.

The energy transition is a long-term strategy dedicated to achieving carbon neutrality in Germany by 2045. This process includes the development of renewably generated electricity from wind and solar power. As these energy sources are dependent on weather conditions, imbalances in availability and demand might result in a deficit or excess of renewable energy. In times of excessive availability, hydrogen can be generated and stored in subsurface storage sites from which it can be withdrawn when the demand increases. Using subsurface storage sites is a viable option as those currently store natural gas. Considering the properties of hydrogen, converting existing storage sites poses many challenges, including the total stored energy content and the amount of extractable working gas. Using an exemplary storage formation, a numerical simulation model is set up in an open-source software and used to calculate and compare the stored volumes and energy contents for natural gas and hydrogen. Storage withdrawal and pressure profiles for both cases are developed. A pseudo gas is defined with individually alternating compressibility, density and viscosity behavior to independently assess the influence of these properties on the withdrawal rates. A sensitivity analysis of various storage, bottom-hole flowing pressures and the skin factor on the extraction rates is also performed. The results show that a larger volume of natural gas and a resulting higher energy content can be stored in the storage site compared to hydrogen. Changes in extraction rates occur earlier and pressure decrease is greater for stored hydrogen. The compressibility factor has the largest influence on the extraction behavior of the gas, leading to a steeper decline in hydrogen withdrawal rates and a quicker pressure depletion. The levels of the storage and the bottom-hole flowing pressure impact the slope of the decline and the level of withdrawal rates.

This study presents a comparative evaluation of three subsurface energy storage technologies: methane storage, hydrogen storage, and high-temperature aquifer thermal energy storage (HT-ATES), within an identical geological and storage facility. The novelty lies in the application-oriented assessment of different energy storage carriers under unified porous media storage and long-term cyclic operation. Using a digital workflow based on a real geological model derived from a real gas field. The energy density, production performance, and energy efficiency of three storage types are analyzed over 20 years of cyclic operation. The results show: For energy density, methane storage exhibits the highest volumetric energy density and the greatest sensitivity to porosity, enabling substantially greater cumulative energy injection and recovery compared with hydrogen storage and HT-ATES. The energy density of HT-ATES shows limited sensitivity to porosity and demonstrates competitive performance in low-porosity formations. For production performance, all three storage types are capable of supplying energy continuously and stably during the winter season. The key difference is that methane and hydrogen storage can produce over 90% of their stored energy within two weeks, as they accumulate pressure during the energy injection season. HT-ATES is limited by material balance operation and higher working fluid density, it cannot withdraw large volume energy a short time. For energy efficiency, all three storage types exhibit high recovery performance. However, the requirement for cushion gas in gas storage systems reduces their competitiveness compared to HT-ATES. Methane storage has the largest CO₂ footprint due to combustion emissions. Hydrogen and HT-ATES, when charged with zero‑carbon sources, produce no direct emissions. HT-ATES incur higher system operational carbon emissions due to continuous pumping requirements.

A high-temperature aquifer thermal energy storage (HT-ATES) system has the potential to balance the seasonal mismatch of energy supply and energy demand. Reservoir permeability heterogeneity is generally not considered in the investigation and design of ATES projects. In this case, this study investigated the influence of heterogeneous permeability fields on the performance of target HT-ATES, i.e., pressure, terminal production temperature, energy recovery rate, and levelized cost of heat. Results show that the heterogeneous permeability distribution slightly influences the terminal production temperature and energy recovery rate with the constant injection and production rate. However, the injection and production pressures are highly related to the standard deviation of unevenly distributed permeability but demonstrated to be independent of the correlation length. Compared to the heterogeneity of the permeability field, the reservoir energy recovery rate and terminal production temperature are more sensitive to the well spacing. In addition, energy loss due to the surrounding rocks only matters during the early times of the operation period and becomes less significant as the operation proceeds. Furthermore, the growth in injection/production pressures due to the permeability heterogeneity considerably increase the system levelized cost of heat by more than 25 % compared to the current operating ATES systems.

Experimental work demonstrates that there is a dependency of relative permeability in CO2-brine systems on varying CO2 solubility. The influence of this observation on field-scale modelling is investigated alongside experimental work. The impact of relative permeability differences in various saturation zones on the amount of CO2 stored, the plume shape and the contribution of different trapping mechanisms will be quantified to assess their significance in practical applications. SCAL laboratory experiments are conducted, measuring the two-phase relative permeability between brine and supercritical CO2 across a range of varying amounts of dissolved CO2 in the brine. The data are incorporated into 3D numerical simulations in a semi-synthetic model to predict the flow behaviour of CO2 in porous media filled with saline formation water. Sensitivity analyses are performed to evaluate the impact of relative permeability curves on the storage efficiency of the different CO2 trapping mechanisms. Subsequently, correlations amongst the measured properties could be established and generalised with sufficient experiments. This process requires utilising diverse porous media characteristics, such as varied pore structures, wettability, and various brine compositions with differing salinity levels, to resemble typical prospective reservoirs for geological CO2 storage. This study integrates sensitivity analysis to examine how variations in solubility-dependent relative permeability affect CO2 storage efficiency predictions. The goal is to refine field-scale simulation accuracy and provide a comprehensive understanding of how trapping mechanisms, including structural, residual, and solubility trapping, respond to relative permeability changes. The numerical reservoir simulation results confirm that the simulated CO2 flow behaviour and trapping mechanisms appear to be sensitive to relative permeability changes for example, when the changes occur due to the solubility of CO2 in brine. Moreover, an even more significant phenomenon is observed where hysteresis plays a significant role. Simulations reveal substantial variations in predicted CO2 storage efficiency when relative permeability assumptions are altered. Different trapping mechanisms show distinct behaviours depending on the hysteresis method used. The scenarios involving hysteresis incorporate additional trapping mechanisms such as residual trapping. Sensitivity assessments using simulation models are utilised for planning further experimental work and prioritising the most influential parameters for practical applications. This paper presents a study on the influence of saturation functions and CO2 solubility on CO2 storage performance utilising a combination of experimental and numerical simulation work.

High-temperature aquifer thermal energy storage (HT-ATES), with its high storage capacity and energy efficiency and its compatibilities with renewable energy sources, arouses broad interest. The density-driven buoyancy flow becomes more significant for HT-ATES, which may lead to a lower thermal recovery efficiency than the conventional low-temperature ATES. Thus, understanding the displacement and thermal transport processes during HT-ATES is essential for predicting and assessing the performance of HT-ATES. In this study, the governing equations for HT-ATES considering the buoyancy flow are nondimensionalized, and five key dimensionless parameters regarding the thermal recovery efficiency are determined. Then, numerical simulations are implemented to study the recovery efficiency for a sweep of the key dimensionless groups for multiple circulations and storage volumes. It is found that the displacement processes can be classified into three regimes: a buoyancy-dominated regime, a conduction-dominated regime, and a transition regime. In the buoyancy-dominated regime, recovery efficiency is mainly correlated to the ratio between the Rayleigh number and the Peclet number. In the conduction-dominated regime, the recovery efficiency is mainly correlated to the product of a material-related parameter and the Peclet number. Then, multivariable regression functions are provided to estimate the recovery efficiency using the dimensionless parameters. The recovery efficiency estimated by the regression function shows good agreement with the simulation results. Finally, well screen designs for optimizing recovery efficiency at various intensities of buoyancy flow are investigated.

Carbon dioxide (CO2) capture, utilization, storage (CCUS), and High-temperature aquifer thermal energy storage (HT-ATES) have been considered as effective advanced techniques that could remarkably contribute to renewable energy and mitigating global warming. Thus, this study tries to combine these two concepts. We investigate the potential for storing & extracting the heating from deep aquifers by utilizing CO2 as a working fluid. To compare the performance of CO2 and traditional HT -ATES working fluid water (H2O), two parallel HT-ATES cycling simulations are employed in DuMux based on a real geology model, identical well doublet design, and pump performance to test the behavior of H2O HT-ATES and CO2 HT-ATES. The 30 years cycling simulation shows CO2 HT-ATES have similar reliable performance to H2O HT-ATES, but there is some difference worth noting: The traditional H2O HT-ATES (76-90 C) have a higher and more stable extract temperature than CO2 HT-ATES (73-90 C-degrees) because of water heat capacity is larger. The CO2 HT-ATES (27.3-28.3 kg/s) have higher flow rates than H2O HT-ATES (20.8-24.3 kg/s) since the viscosity difference. The CO2 HT-ATES could form the CO2 gas cap, thermal conduction and convection to the caprock less than H2O HT-ATES, which leads to less heating loss during the heating store stage. H2O HT-ATES (4000 TJ) have more total energy input/output volume than CO2 HT-ATES (3000 TJ), but the energy efficiency of CO2 HT-ATES (92 %) is superior to H2O HT-ATES (85 %). Besides, CO2 HT-ATES can sequester a certain amount of CO2 yearly, over 1.6 Mt CO2 will be sequestered in the aquifer after 30 years of operation.

Abstract Due to the rapid expansion of renewable energy required to meet the 2050 net-zero target, hydrogen has been recognized as a clean and low-carbon fuel. When it is produced by electrolysis from renewable electricity it is referred to as ‘’green hydrogen’’. While the energy production from solar and wind power plants varies greatly over time and rarely meets both the daily and seasonal demand a reliable technology for energy storage must be established. In this context, underground hydrogen storage (UHS) shows an efficient solution for the long-term storage of energy. For the planning and operation of UHS in porous geological formations, it is very important to know the movement and mixing of the injected hydrogen with the initial gas in place. Mixing can be driven by advective flow but also by diffusive flux during idle periods. This paper is focused on determining the effective binary diffusion coefficients of hydrogen and methane under representative gas storage conditions. In total, seven diffusion measurements were carried out for two sandstone samples (Berea and Bentheimer). A modified core flooding cell was used for these measurements. A semi- steady-state diffusive flux was ensured by connecting one end face of the sample to a chamber filled with the first gas and flowing the second gas along the other end face. The composition of the outflowing gas was analyzed by gas chromatography. Measurements were performed under typical gas storage conditions in a pressure range from 10 to 100 bar and at 25 and 40°C. The saturation state of the samples was dry. Each measurement was analyzed by a comparison to a simulation model and the effective diffusion coefficient was determined. The range of measured effective diffusion coefficients is from 6.5 * 10−8 m2/s to 3.7 * 10−7 m2/s. Repeated measurements under the same conditions are in good agreement, what validates the measurement procedure. The results indicate a decreasing behavior of the effective diffusion coefficient with increasing pressure and temperature in the considered ranges. The findings gained in this study allow a better estimation of the diffusive contribution to the gas mixing during UHS.

The increased share of renewable energy sources will lead to large fluctuations in energy availability and increases energy storage’s significance. Large-scale hydrogen storage in the subsurface may become a vital element of a future sustainable energy system because stored hydrogen becomes an energy carrier available on demand. Large hydrogen amounts can be stored in porous formations such as former gas fields or gas storages, while caverns can contribute with high deliverability. However, the storage of hydrogen induces unique processes in fluid-fluid and rock-fluid interactions (for example, bio- and geochemical reactions), which may affect the efficiency of the storage. In the present study, a mathematical model describing the two-phase multicomponent flow in porous media, including bio- and geochemical reactions, is developed to predict these hydrogen-related processes. The proposed model extends an existing model in the open source simulator DuMux describing the bio-reactive transport process considering methanation and sulfate-reduction by geochemical reactions. Significant attention is placed on the reduction from pyrite-to-pyrrhotite coming with the generation of harmful hydrogen sulfide. This reaction is calibrated by developing a kinetic model in DuMux that mimics the observations of reactor experiments from literature. The developed and calibrated model is afterwards used for simulation runs on field scale to assess the impact on Underground Hydrogen Storage (UHS) operations. The developed kinetic model describes the reduction from pyrite-to-pyrrhotite in agreement with the observations in the literature, whereby particular focus was placed on the hydrogen sulfide production rate. The consecutive implementation of the transport model in DuMux on field scale, including the bio- and geochemical reactions, shows the potential permanent hydrogen losses caused by reactions and temporary ones induced by gas-gas mixing with the initial and cushion gas.

High-temperature aquifer thermal storage (HT-ATES) is an effective method to mitigate the increasing greenhouse gas emissions, and it is attracting industry attention as an alternative to traditional fossil fuels for heating and cooling. However, the uncertainty of exploration and long profit cycles impede the popularization of HTATES technology. In this paper, to optimize HT-ATES evaluation and make the results more convictive, we demonstrate a numerical study based on a real district and a proven aquifer. An integrated HT-ATES model includes the wellbore and aquifer is used to simulate the fluid flow and heat transfer. Moreover, a dynamic economic assessment is demonstrated depending on the HT-ATES fluctuation performance. A 30-year HT-ATES cycling simulation shows that the wellbore and aquifer have had a continuous heating loss since the operation started. Working well and balancing the well lost 2.7% and 2.2% of total energy through the wellbore. The aquifer lost 4.1% of total energy due to heating transfer to overburden and other layers. HT-ATES could recover around 90% of stored total energy. The HT-ATES economic performance is affected by the heating store and production cycling, the benefit mainly comes from the heating production season. The initial investment and heat exchange efficiency between the HT-ATES & end-application system determines the levelized heat (LCOH) cost and payback time, the optimist case still needs 3 years to be profitable. HT-ATES have considerable green benefits, it could reduce local CO2 emissions 1937 t/year.

With their high storage capacity and energy efficiency as well as the compatibilities with renewable energy sources, high-temperature aquifer thermal energy storage (HT-ATES) systems are frequently the target today in the design of temporally and spatially balanced and continuous energy supply systems. The inherent density-driven buoyancy flow is of greater importance with HT-ATES, which may lead to a lower thermal recovery efficiency than conventional low-temperature ATES. In this study, the governing equations for HT-ATES considering buoyancy flow are nondimensionalized, and four key dimensionless parameters regarding thermal recovery efficiency are determined. Then, using numerical simulations, recovery efficiency for a sweep of the key dimensionless parameters for multiple cycles and storage volumes is examined. Ranges of the key dimensionless parameters for the three displacement regimes, that is, a buoyancy-dominated regime, a conduction-dominated regime, and a transition regime, are identified. In the buoyancy-dominated regime, recovery efficiency is mainly correlated to the ratio between the Rayleigh number and the Peclet number. In the conduction-dominated regime, recovery efficiency is mainly correlated to the product of a material-related parameter and the Peclet number. Multivariable regression functions are provided to estimate recovery efficiency using the dimensionless parameters. The recovery efficiency estimated by the regression function shows good agreement with the simulation results. Additionally, well screen designs for optimizing recovery efficiency at various degrees of intensity of buoyancy flow are investigated. The findings of this study can be used for a quick assessment and characterization of the potential HT-ATES systems based on the geological and operational parameters.

This work introduces an efficient approach in addition to the traditional scheme of polymer screening for the application of enhanced oil recovery. Microfluidics technology which requires less sample volumes, and less time consumption, is applied to the polymer screening procedure. This approach delivers an efficient screening process and enables the upscaling of polymer flow behavior in porous media. This work investigates three commercial polymer products, A, B, and C, which vary in average molecular weight at shear rate (0.1 – 1000 s−1) and temperature (20°C– 60°C). Fifteen polymer solutions with different concentrations are made from the three products and screened through three evaluation stages. The first stage is measuring the bulk shear viscosity of the polymer solutions in the rheometer. The second stage is conducting single-phase polymer flooding through a novel micromodel. The stage of this approach applies the results from the earlier stages by running two-phase flooding experiments that implement polymer flooding for reservoir conditions of an oil field in Oman. The micromodel structure used in this work is generated based on X-ray micro-computed tomography (μCT) images of a Bentheimer core plug. Thus, the micromodel's porosity, permeability, pore, and grain size distribution are similar to the core plug. This characteristic gives an upscaling potential to a larger scale, such as core plug or even a field implementation. A database with bulk shear viscosity and model fits (Power law & Carreau) is generated from the rheometer measurements for polymers A, B, and C. A novel 3D surface model that relates the shear rate, temperature, bulk viscosity, and concentration is developed from the data in the first stage. The single-phase flooding experiments allow the investigation of the behavior of polymer in porous media under shear and extensional flow. Furthermore, the comparison of bulk shear viscosity and in-situ viscosity shows the potential to support the analysis of an empirical constant (C-factor). In addition, polymer injectivity and retention are investigated by analyzing the pressure drop and residual resistance factor after each single-phase polymer flooding experiment. The last stage of this work provides the improvement of displacement efficiency and the recovery factor, which measures the success of the approach. The novelty of this approach is the utilization of the linear Bentheimer micromodel for delivering an efficient polymer screening process. This micromodel reflects similar rock properties as Bentheimer rocks, which provide the potential to upscale the results from microfluidics to reservoir rocks. In addition, the novel 3D surface model developed in this work allows comprehensive screening, which is accomplished through combining the parameters required in polymer evaluation at one domain.

The properties of polymeric materials are commonly modified by adjusting the dispersity of the molecular weight distribution, since polymer properties are dominated by intermolecular interactions. We utilized this approach to alter the rheological behavior of polymer solutions for application sub-surface and other porous media flow. We correlate the molecular weight distributions with screen factor measurements and in-situ rheological behavior. Aqueous solutions were prepared using mixtures of partially hydrolyzed polyacrylamide (HPAM) having different molecular weights. The behaviour of the solutions was studied in single-phase flooding experiments using Bentheimer and Berea outcrops, as well as a glass-silicon-glass microfluidic device that mimics porous media. The in-situ rheological behavior determined from flooding experiments was monitored by differential pressure measurements. To improve data accuracy, the core flooding experimental set-up was equipped with multiple pressure sensors along the core. Polymer solutions of same shear viscosity but significantly different dispersities were utilized for the investigation. Elongational viscosities were determined by screen factor measurements. We show that the apparent viscosity during polymer injection is significantly altered for polymer solutions of same average molecular weight but different dispersity. Namely, the onset of shear thickening occurs at lower equivalent shear rates when dispersity is high. Furthermore, the flow of polymer solutions in porous media was correlated to screen factor measurements. This effect of the dispersity of the molecular weight distribution can be used to optimize polymer solution applications in porous materials.