Aquifer Storage Research Articles

Application of Active Heating Tests with the Distributed Temperature Sensing to Characterize Flow Dynamics in a Tidal-Influenced Coastal Aquifer

Aquifer storage and recovery have gained attention as a solution that utilizes submarine groundwater discharge (SGD) as a surrogate water resource to alleviate water scarcity and fill the demand gap. Characterizing SGD is crucial for using coastal groundwater and improving understanding of the interaction between continental water and seawater. This study employs fiber-optical distributed temperature sensing (FODTS) and the heat tracer to quantify the groundwater flux in a coastal aquifer in northern Taiwan. The fluxes in different sections along the borehole were estimated from the temperature response caused by the active heating tests and campier groundwater flux under different tidal conditions, providing information on potential water resources for water resource planning and management. According to the active heating tests, the material of the sections with high-temperature response mainly consists of a gravel–sand mixture. Based on the estimations of groundwater fluxes along the well, the sections with low sensitivity of temperature response have low hydraulic conductivity and low groundwater flux. The estimated thermal parameters at the site are consistent with those obtained from the borehole samples in the laboratory tests. The groundwater fluxes in different sections are calculated based on the temperature response observed from the FODTS. The groundwater fluxes along the well vary between 0.02 and 1.77 m/day. There are considerable differences between the estimated fluxes during the tidal cycle in a heterogeneous coastal aquifer, indicating the high uncertainty of estimated SGD along coastlines.

Comparing Recovery Volumes of Steady and Unsteady Injections into an Aquifer Storage and Recovery Well

Aquifer Storage and Recovery (ASR) can involve injecting available surface water into an unconfined aquifer and then extracting it to provide secondary water for irrigation. This study demonstrates a method for evaluating the appropriateness of steady injection versus unsteady injection for an assumed situation. In design, it can be important to affect the transient: the proportion of the injected water that would be subsequently extracted (versus that remaining in the aquifer) and the proportion within the extracted water that would be an injectate (versus ambient groundwater). These proportions can be predicted from the predicted value of an ASR well’s Recovery Effectiveness (REN)—the time-varying proportion of injectate that is extracted subsequently from the same fully penetrating well. Applying the demonstrated procedure with appropriately detailed data and simulation models can predict the REN values resulting from steady versus unsteady injection, followed by steady extraction. For convenience in displaying and computing REN, the injectate was assumed to have a 100 ppm conservative solute concentration. For this demonstration, a homogenous isotropic unconfined one-layer aquifer was assumed. The scenarios involved steady or unsteady injection for 61 days via a fully penetrating ASR well. Then, 91 days of steady pumping led to the extraction of a total volume equal to that injected. For the assumed hydrogeologic data—31 years of Salt Lake City, Utah, rainfall data and estimated captured runoff—the results show that steady injection is more likely to cause a predictable REN but might not cause a higher REN than daily varying injection of the same total volume. Assuming different runoff or hydrogeologic flows would lead to different REN values. Steady injection causes a predictable groundwater mound and can assure a sufficient vadose zone thickness for overlying plants. Augmentation and storage of captured rainwater can help to provide a steady injection rate. For a situation that requires REN management, appropriate simulations can help water managers design ASR systems that will achieve REN goals and increase sustainable groundwater availability.

Numerical Modelling of CO2 Injection and Storage in Low Porosity and Low Permeability Saline Aquifers: A Design for the Permian Shiqianfeng Formation in the Yulin Area, Ordos Basin

The geological storage of CO2 in saline aquifers is a crucial method for achieving large-scale carbon storage in the future. The saline aquifers with low porosity and permeability in the Ordos Basin exhibit high irreducible water saturation and restricted fluid mobility, necessitating further investigation of their injectivity and storage safety. The fifth member of the Shiqianfeng Formation (P3sh5) in the Ordos Basin serves as a key layer for geological CO2 storage (GCS). The numerical simulation of CO2 injection in this reservoir is an indispensable process for characterizing the migration and storage of CO2. Injection pressure and well type (vertical well or horizontal well) are critical factors affecting GCS. The results of the numerical simulation are important preliminary preparations for promoting the GCS in the saline aquifer of the Shiqianfeng Formation in the future. This paper focuses on P3sh5 in the Yulin area as a case study. It investigates the injectivity and CO2 migration characteristics of these low porosity and low permeability saline aquifers in the Ordos Basin. Relatively high-quality distributary channel sandstone bodies in integrally low porosity and permeability strata were identified for injection. As CO2 is injected, the formation pressure gradually increases. It is essential to maintain it below the fracture pressure during CO2 injection to ensure safety. High-pressure (8 MPa) injection could achieve volumes 2.9 times greater than those in the low-pressure scenario (4 MPa) of 2 km horizontal branch well. Under the three injection well types, the injection rate of vertical wells is the lowest. Employing a “horizontal branch well injection” strategy could potentially amplify the injection volume by 2.87 times. CO2 predominantly migrates vertically near the horizontal interval of interest, while horizontally, the area near the interval of interest experiences a higher CO2 saturation, with the maximum saturation reaching about 50%. Overall, CO2 is migrated in the distributary channel sandstone bodies, indicating a higher storage safety and lower leakage risk. It is recommended that the number of drilling wells be increased and multiple horizontal branch wells implemented to enhance the injection efficiency. Overall, this study provides a geological foundation for the previous design and construction of the GCS project in the Ordos Basin’s saline aquifer. It also provides a reference for GCS in low permeability saline layers in similar regions worldwide.

Sustainable restoration of low-quality groundwater through aquifer storage and recovery

Sustainable restoration of low-quality groundwater through aquifer storage and recovery

A method for estimating maximum safe installable power for groundwater extraction with application to Africa

New groundwater development is a likely way to meet growing global water demand but needs careful management. To help inform the sustainable development of groundwater resources, a novel method based on the maximum safe installable power for water pumping systems and the maximum safe remaining installable power (considering current abstraction) is developed. The proposed model couples energy, technology and hydrogeological parameters, and is then developed to compute the maximum power that can be safely installed per km2 without exceeding a maximum annual pumpable volume, calculated through available recharge and storage. The model is applied to estimate the maximum safe installable power across Africa with a 0.2-degree resolution, using available energy and hydrogeological data. Constrained by recharge (considering that 25 % of the annual recharge is available for utilization), the maximum safe installable power ranges between 0 and 9960 W/km2 across Africa with regions such as the Congo Basin (~340 W/km2), and western Africa between the Ivory Coast and Nigeria (~230 W/km2) identified as having high potential for sustainable pumping system development. Constrained by storage (considering that 0.1 % of storage can be withdrawn per year), it ranges between 0 and 13,425 W/km2 highlighting the ability to harness storage for pumping system development in the large aquifers of Northern Sahara (~8720 W/km2). When considering limitations posed by both groundwater recharge and aquifer storage (considering that 25 % of the annual recharge and 0.1 % of storage can be withdrawn per year), along with current groundwater withdrawal, 93 % of the maximum safe installable power remains still installable on average across Africa. Nevertheless, 2 % of the locations are estimated to be already experiencing overexploitation, particularly in Sudan, northern Africa, and northeastern South Africa. These findings provide a novel and adaptable way to examine water security, which can assist institutions in targeting investments to meet water demand sustainably.

CO2 Trapping in Layered Porous Media by Effective Viscosification

AbstractSafe and efficient storage of CO2 in saline aquifers requires mobility control to prevent CO2 from accumulation and rapid spreading at the formation top below the caprock. In the past, we have demonstrated the effectiveness of two engineered olefinic‐based oligomers for viscosification of sc‐CO2 and the significant improvements in residual trapping of sc‐CO2 in brine‐saturated homogeneous sandstone cores (Ding et al., 2024, https://doi.org/10.2118/214842‐pa). The objective of this work is to examine the sweep efficiency and residual brine saturation in the layered cores by effective viscosification with two engineered molecules, providing the implications for CO2 trapping in layered porous media by effective viscosification. In neat CO2 injection, the CO2 channels through the high permeability layer, causing rapid breakthrough and high residual brine saturation. This results in an inefficient process for CO2 storage in saline aquifers. In viscosified CO2 injection, we observe significant improvements in crossflow at the interface between the two‐permeability layer, partly due to the mobility control and residual brine saturation reduction. In comparison to the neat CO2 injection, the synergistic effect of the mobility control and increases in interfacial elasticity by injection of vis‐CO2 results in delay in breakthrough by a factor of 2 and about 95% higher brine production. Compared to our previous work on displacement experiments in homogeneous sandstone core, there is a more significant reduction of residual brine saturation in layered cores by viscosified CO2 injection. Increases in injection rate is also demonstrated to improve the CO2 storage in layered cores. Both the CO2 viscosification and increases in injection rate may promote the injection pressure to overcome the capillary entry pressure, leading to CO2 displacement of brine in the low‐permeability layer. CT‐imaging data advances understanding of boundary conditions, brine production, and local residual brine saturation in layered cores.

Coupled feldspar dissolution and secondary mineral precipitation in batch systems: 6. Labradorite dissolution, calcite growth, and clay precipitation at 60 °C and pH 8.2–8.4

We conducted experiments on concurrent labradorite dissolution, calcite precipitation, and clay precipitation in batch reactor systems and tracked reaction processes using multiple isotope tracers. Labradorite was chosen for its role as a major and reactive component in basalt; the experiments thus directly impact our understanding of CO2 storage in basalt aquifers and enhanced rock weathering. We doped initial solutions with 29Si, 43Ca, and Ca13CO3(s). Experiments were conducted at 60 °C and pH ∼ 8.3 for up to 840 h, with isotope ratios in the experimental aqueous solutions measured using MC-ICP-MS. Unidirectional rates of labradorite dissolution near equilibrium were approximately two orders of magnitude slower than far-from-equilibrium rates reported in the literature. Calcite growth occurred near equilibrium and the rates were limited by the labradorite dissolution rates.In the steady state phase, the interplay of these three heterogeneous reactions—labradorite dissolution, calcite growth, and clay precipitation—results in a coupled system that approaches a near-equilibrium state. The system does not reach true equilibrium because labradorite continues to dissolve, albeit at a much slower rate near equilibrium. The overall reaction can be approximated as,Na0.4Ca0.6Al1.6Si2.4O8 + 0.6HCO3- + 1·.7H2O + 0.4H+ → 0.4Na+ + 0.6CaCO3(s) + 0.5Al2Si2O5(OH)4(s) + 0.6Al(OH)4- + 1.4SiO2o(aq)The experimental results show that using short-term far-from-equilibrium rate constants would lead to an overestimation of feldspar weathering rates at the Earth’s surface (e.g., basalt weathering and enhanced rock weathering) and CO2 mineralization in basalt aquifers.

Numerical investigation of fluid dynamics in aquifers for seasonal large-scale hydrogen storage using compositional simulations

Numerical investigation of fluid dynamics in aquifers for seasonal large-scale hydrogen storage using compositional simulations

Optimizing hydrogen storage in a heterogeneous aquifer considering hysteresis and dissolution

Hydrogen (H2) is a rising solution for carbon-neutral fuel transition. Saline aquifer, ubiquitous underground, is a competitive candidate for large-scale underground hydrogen storage (UHS). This study proposed to use a heterogeneous aquifer formation for probing the functioning of UHS and optimizing its operation. By integrating geological information with lithofacies from the Ordos Basin in China, a heterogeneous triplet aquifer model was built, upon which compositional simulations of UHS operations that consider two-phase flow, relative permeability hysteresis, hydrogen and water phase behavior, rock compressibility, and dissolution mechanisms were conducted. Orthogonal array L25 (56) with mixed levels was designed to optimize the H2 recovery. Results substantiate the feasibility of storing millions of cubic meters of H2 with over 95% recovery. Ignoring dissolution and relative permeability hysteresis will result in an overestimation of the hydrogen recovery factor, with the effect of relative permeability hysteresis being more significant. Provided equal cycle length, a lower injection-withdrawal rate is suitable for long-term operation of hydrogen storage, while a higher rate can achieve a higher recovery factor during the early cycles. Measures of lowering the skin factor and pre-extracting brine could improve storage capacity and reduce water production during injection and withdrawal. The optimized case is expected to achieve an average H2 recovery of 98.8% for 30 operation cycles with moderately low saline water production. These findings provide valuable insights for developing large-scale and cost-effective UHS in saline aquifers.

Overview of Typical Projects for Geological Storage of CO2 in Offshore Saline Aquifers

With the continuous growth of global energy demand, greenhouse gas emissions are also rising, leading to serious challenges posed by climate change. Carbon Capture, Utilization, and Storage (CCUS) technology is considered one of the key pathways to mitigate climate change. Among the CCUS technologies, CO2 storage in offshore saline aquifers has gained significant attention in recent years. This paper conducts an in-depth analysis of the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, exploring key issues related to the application, geological characteristics, injection strategies, monitoring systems, and simulation methods of CO2 storage in offshore saline aquifers. This study finds that CO2 storage in offshore saline aquifers has high safety and storage potential but faces several challenges in practical applications, such as geological reservoir characteristics, technological innovation, operational costs, and social acceptance. Therefore, it is necessary to further strengthen technological innovation and policy support to promote the development and application of CO2 storage in offshore saline aquifers. This study provides valuable experiences and insights for similar projects worldwide, contributing to the sustainable development of CO2 storage in offshore saline aquifers and making a greater contribution to achieving global net-zero emission targets.

Effect of reaction rate and pore structure heterogeneity on reactive solute transport in porous media

CO2 geological storage is the most direct and reliable method to reduce CO2 emission, and deep saline aquifers have the greatest storage potential of CO2. In the process of CO2 storage in saline aquifers, mineral precipitation and dissolution caused by reactive solute transport have a significant impact on reservoir storage potential. In order to predict the transport characteristics and storage potential of CO2 in saline aquifers, it is critical to understand the relationship between chemical reactions and transport properties. The governing equations of porosity evolution of porous media considering chemical reaction processes are proposed, and the relationship between effective reaction area and porosity is considered, and finally a kinetic model is established. Considering different reaction rates and different pore structure heterogeneity, the evolution characteristics of porosity, species concentration and fluid pressure were obtained by combining advection-diffusion equation and Darcy's law. The simulation results show that the dimensionless porosity of porous media transforms from uniform variation to extreme non-uniform variation under low Da number, typical Da number and high Da number condition. The dimensionless concentration can not reach the saturation concentration under low Da number condition. The dimensionless concentration decreases significantly in the inlet region and reaches the saturation concentration under typical Da number condition. The dimensionless concentration reaches the saturation concentration rapidly in the inlet region under high Da number condition. The variation of dimensionless pressure gradient in porous media is significantly correlated with the porosity distribution. The dimensionless advection mass flux of porous media is negatively correlated with the pore structure heterogeneity, while the dimensionless diffusion mass flux is positively correlated with the pore structure heterogeneity. The specie peak concentration decreased with increasing heterogeneity, and the time to reach the peak concentration increased with increasing heterogeneity. The research results can provide a theoretical foundation for the assessment of the transport pathways of CO2 storage in saline aquifers.

Harnessing the power of machine learning for the optimization of CO2 sequestration in saline aquifers: Applied on the tensleep formation at teapot dome in Wyoming

The sequestration of carbon dioxide in deep saline aquifers offers a highly promising approach to mitigate CO2 emissions resulting from the fossil fuels industry. The practicality of this solution is mostly dependent upon the CO2 trapping efficiency, which governs the capacity of the aquifer for CO2 storage. Generally, the compositional reservoir simulation is employed to evaluate the trapping efficiency, but is computationally expensive, particularly when adjusting parameters necessitates hundreds of simulations. In this paper, A machine learning (ML) proxy model was used to address these difficulties for fast evaluation and optimization of the residual and dissolution trapping mechanisms in the Tensleep sandstone formation in the Teapot Dome Field, located in Wyoming, USA. The initial CO2 storage capacity of the aquifer was calculated to be 17.7 thousand tons. In the simulation model, several injection wells were placed in the high porosity regions and CO2 injection was simulated over duration of 10 years, followed by a 90-year post-injection period. The injection rates were optimized to maximize the overall trapping efficiency, which takes into account both residual and solubility indices. In order to construct a dataset for machine learning-based proxy models, the Latin hypercube sampling technique was adopted to generate 100 simulation runs that varied operating constraints: maximum injection rate, maximum injection pressure, and number of injection wells. The Radial Basis Function-Artificial Neural Network (RBF-ANN) was specifically trained to accurately determine the most appropriate injection rates by identifying complex and non-linear correlations within the data. The total CO2 trapping effectiveness by the RBF-ANN model was enhanced from 75% to 83%, accompanied by an insignificant increase in the leakage index from 0.64% to 1.3%. The results indicated that machine learning proxy modeling offers a rapid and accurate approach to optimize the storage of CO2 in saline aquifers. Through the reduction of CO2 emissions, this method significantly improves the viability of large-scale sequestration projects, so making a valuable contribution to climate change mitigation.

CO2 geological storage in subsurface aquifers as a function of brine salinity: A field-scale numerical investigation

Subsurface aquifers demonstrate a broad range of salinities and salt compositions, affecting the physicochemical characteristics of the CO2/brine/rock systems, which in turn, influence the CO2 trapping of the aquifer formation. Available simulation studies generally focus on single NaCl systems and do not adequately account for the variations in salt types. In this study, the impact of salinity and salt type on several key parameters, including wettability, interfacial tension, brine properties, diffusion, and capillary pressure, were considered within the context of underground CO2 storage. We conducted pore network modeling to assess the impact of salinity (i.e., pure water, 1 M (molality), 3 M, and 5 M) and salt type (i.e., NaCl, CaCl2, and MgCl2) on the residual trapping behaviors. Subsequently, these findings were utilized in field-scale simulations to assess the influence of various salinities and salt types on the CO2 trapping capacity in a single salt brine system. The pore network modeling results showed that residual CO2 saturation decreases in higher salinity conditions, with the lowest value in MgCl2 brine system. In field-scale simulations incorporating residual trapping alone, the residual trapping capacity decreases in higher salinity NaCl brine systems. However, in high salinity MgCl2 brine, increased viscosity and density lead to a widespread CO2 plume, leading to an increased residual trapping capacity. This plume spread difference also influences the amount of dissolved CO2 in scenarios considering dissolution trapping alone. When considering both trapping mechanisms, our observations indicate that a decrease in dissolution trapping under high salinity and divalent cations conditions leads to enhanced residual trapping (e.g., ∼51.56% for 5 M MgCl2) - suggesting an interplay or codependency between these two mechanisms. The influences of diffusion and capillary pressure on the CO2 geo-storage trapping capacity are also investigated. Overall, an aquifer containing lower salinity brine composed of monovalent ions exhibits lower residual trapping, greater dissolution trapping, and lower mobile CO2. Especially, the pure water system exhibits the lowest percentage of mobile CO2 (∼13.72%). We also highlight that this impact is not governed by the corresponding wettability shift alone; rather, the physical properties of native brine (i.e., viscosity and density) play a part too. The findings help evaluate the CO2 storage potential of aquifers and thus assist in de-risking large-scale storage projects.

Typical Case Studies and Classification with Evaluation of Carbon Dioxide Geological Sequestration in Saline Aquifers

To achieve carbon neutrality in China’s fossil energy sector, saline aquifer CO2 geological storage has become a critical strategy. As research into carbon reduction and storage potential evaluation advances across various geological scales, the need arises for consolidating key CO2 storage cases and establishing a standardized classification system and evaluation methodology. This paper provides a comprehensive review of notable CO2 storage projects in saline aquifers, covering aspects such as project overviews, structural and reservoir characteristics, caprock integrity, and seismic monitoring protocols. Drawing on insights from mineral and oil and gas exploration, as well as international methods, this paper outlines the stages and potential levels of saline aquifer storage in China. It proposes an evaluation framework with formulas and reference values for key coefficients. The study includes successful global projects, such as Sleipner and Snøhvit in Norway, In Salah in Algeria, and Shenhua in China’s Ordos Basin, which provide valuable insights for long-term carbon capture and storage (CCS). By examining geological characteristics, injection, and monitoring protocols in these projects, this paper analyzes how geological features impact CO2 storage outcomes. For example, the Sleipner project’s success is linked to its straightforward structure, favorable reservoir properties, and stable caprock, while Snøhvit illustrates diverse structural suitability, and In Salah demonstrates the influence of fractures on storage efficacy. CO2 storage activities are segmented into four stages—survey, investigation, exploration, and injection—and are further categorized by storage potential: geological, technical, techno-economic, and engineering capacities. This study also presents evaluation levels (prediction, control, technically recoverable, and engineering) that support effective reservoir selection, potential classification, and calculations considering factors like reservoir stability and sealing efficacy. Depending on application needs, volumetric or mechanistic methods are recommended, with precise determination of geological, displacement, and cost coefficients. For China, a dynamic evaluation mechanism characterized by multi-scale, tiered approaches and increasing precision over time is essential for robust storage potential assessment. The levels and methods outlined here serve as a scientific foundation for regional and stage-based comparisons, guiding engineering approvals and underground space management. To align with practical engineering demands, ongoing innovation through laboratory experiments, simulations, and field practice is crucial, supporting continual refinement of formulas and key parameter determinations.

Geological screening of onshore saline aquifers for CO2 storage: Paraná and Espírito Santo basins, Brazil

Abstract. ​​​​​​​To meet the global goal of net-zero CO2 emissions by 2050, many governments are turning to Carbon Capture and Storage (CCS) as a critical technology. Brazil is the largest CO2 emitter in South America and the 7th largest globally, yet it is in the early stages of CCS development. Using publicly available geological and infrastructure data, this study evaluates the feasibility and suitability of saline aquifers for CO2 storage in onshore intracratonic basins in southern Brazil. Saline aquifers deemed suitable for CO2 sequestration are those below 800 m deep, with a thickness greater than 20 m, and in areas with regionally extensive caprock at least 10 m thick. Using these criteria, we classify areas within the Rio Bonito Formation of the Paraná Basin and the Mucuri Member in the onshore extent of the Espírito Santo Basin into potential and exclusion areas for CO2 storage. The Rio Bonito Formation is present in the central-southern Paraná Basin and ranges from outcrop exposures to over 3900 m depth. The formation ranges in thickness from 25–350 m, and sandstone intervals within the formation have a cumulative thickness between 13 and 150 m. Caprocks consist mainly of shale and siltstone. Based on the criteria used, CO2 sequestration in the Rio Bonito Formation is optimal in two zones of the Paraná Basin that extend over ca. 27 700 km2 (northern zone) and ca. 38 100 km2 (southern zone). The Mucuri Member is present in almost the entire onshore extent of the Espírito Santo Basin and ranges in depth from 500 to 2650 m. The unit reaches 400 m thick with a cumulative thickness of sandstone layers ranging from 0 to 320 m. Caprocks consist mainly of evaporites, but shale and sandstone intervals are also present. CO2 sequestration in the Mucuri Member is optimal in one zone of the onshore Espírito Santo Basin, which extends over ca. 630 km2. Together, these zones have the capacity to store > 6.1 Gt CO2 providing Brazil with suitable capacity for reducing its CO2 emissions over the short- to medium-term.

Accelerating Numerical Simulations of CO2 Geological Storage in Deep Saline Aquifers via Machine-Learning-Driven Grid Block Classification

The accurate prediction of pressure and saturation distribution during the simulation of CO2 injection into saline aquifers is essential for the successful implementation of carbon sequestration projects. Traditional numerical simulations, while reliable, are computationally expensive. Machine learning (ML) has emerged as a promising tool to accelerate these simulations; however, challenges remain in effectively capturing complex reservoir dynamics, particularly in regions experiencing rapid changes in pressure and saturation. This article addresses the challenges by introducing a fully automated, data-driven ML classifier that distinguishes between regions of fast and slow variation within the reservoir. Firstly, we demonstrate the variability in pressure across different reservoir grid blocks using a simple brine injection and production scenario, highlighting the limitations of conventional acceleration approaches. Subsequently, the proposed methodology leverages ML proxies to rapidly and accurately predict the behavior of slow-varying regions in CO2 injection simulations, while traditional iterative methods are reserved for fast-varying areas. The results show that this hybrid approach significantly reduces the computational load without compromising on accuracy. This provides a more efficient and scalable solution for modeling CO2 storage in saline aquifers.

Effects of multiple operational parameters on recovery efficiency of underground hydrogen storage in aquifer

Due to its unique gravimetric energy density and zero carbon emissions, hydrogen is a top priority for the development of future clean and sustainable energy systems. To satisfy energy demand, underground hydrogen storage (UHS) is being adopted. Among underground hydrogen storage sources, aquifers may be one of the best places for large-scale storage of hydrogen (H2). However, there is still lacking to understand the operational parameters of UHS, which is essential to achieve better UHS performance. In this study, operational parameters such as hydrogen production time, hydrogen injection rate, hydrogen production rate, frequency and length of cycles, shut-in period, number of wells, and spacing of wells are the focus of numerical simulations. Form the results, some insights are obtained as follows: (1) At higher hydrogen injection rates, H2 recovery performance declined due to the short contact time between hydrogen and water, as well as lateral expansion of the gas. (2) Optimizing the hydrogen production rate and ensuring sufficient production time were crucial for enhancing hydrogen production performance. (3) Shorter lengths and higher frequencies of storage cycles contributed to an increase in the cumulative hydrogen production volume. Moreover, introducing a shut-in period between the injection and production periods exhibited a detrimental effect on the performance of UHS. (4) In the dual-well configuration, cumulative hydrogen production volume and cumulative recovery efficiency experienced increases of at least 0.51 × 107 m3 and 9.27%, respectively. Concerning well spacing, its impact on the performance of UHS was slight. The effectiveness of UHS in aquifers was confirmed by these results. These understandings provide a certain basis for the optimization of operating parameters.

Analytical model for CO2-water displacement with rate-dependent phase permeability for geological storage

Analytical modelling is an effective tool for predicting reservoir behaviour under high uncertainties, like CO2 storage in aquifers, where multiple simulation runs are necessary for stochastic modelling and risk assessment. This paper formulates the Buckley-Leverett problem with x-dependent fractional flow. We derive a new analytical model for displacement of brine by CO2 accounting for (i) rate-dependent phase permeability during radial flows and (ii) radial flows of Forchheimer's high-rate gas injection; this analytical model is also valid for (iii) linear flows during flooding in micro heterogeneous or composite cores and (iv) CO2-water flow upscaling in reservoirs where layering is perpendicular to flux direction. An exact solution of the flow equation is based on the observation that the flux of each phase conserves along the characteristic trajectories. We discuss S-shape fractional flow function, which is typical for reservoir rocks. The solution includes formulae for phase saturations and fluxes and trajectories of the displacement CO2-water front and of the forward and rear mixture zone boundaries. The fast analytical model can be used for multivariate sensitivity study and sweep efficiency prediction.

Numerical simulation of the coupled thermal-hydro-mechanical fields for evaluating CO2 geo-sequestration storage in deep saline aquifers of Hainan Fushan Sag, China

Geo-sequestration storage of CO2 in saline aquifers is an important technological option to reduce carbon emissions in China in the future. The theory of geo-sequestration storage of CO2 in saline aquifers involves complex physical operations and chemical phenomena among reservoir stress, seepage, and temperature fields, and the numerical simulation models coupling thermal-hydro-mechanical (THM) fields are widely applied to analyze the evolution of multiphysical processes in CO2 reservoirs. Based on the geo-sequestration storage project of saline aquifer CO2 in Fushan Sag, Hainan Province, under the premise of considering the change of permeability and porosity after the mineralization of CO2 in the rock reservoirs, this study simulates the evolution of temperature, stress, and seepage fields during the sequestration process of saline aquifer Continuous CO2 injection wells clarifies the range of influence of the temperature field, seepage field, and the boundary of its stress field of saline aquifer Continuous CO2 injection wells in different sequestration periods. It reveals the influence mechanism of the fault structure on the reservoir CO2 sequestration pressure and capacity, and evaluates and estimates the CO2 injection storage capacity of Fu 1# well in Fushan Sag and on this basis. The THM numerical simulation model proposed in this study plays a crucial role in guiding theoretical evaluations of the CO2 geo-sequestration potential in saline aquifers and determining its technical parameters, thereby offering significant value for engineering applications.

Gradient-guided Convolutional AutoEncoder for predicting CO2 storage in saline aquifers with multiple geological scenarios and well placements

CO2 sequestration in saline aquifers is a crucial component of carbon capture, storage, and utilization (CCUS) technology. The subsurface fluid flow of CO2 and brine in porous media involves the coupling of multiple physics fields, featuring complex nonlinear partial differential equations (PDEs). The prevalent approach for studying subsurface fluid flow is to discretize PDEs in spatial and temporal dimensions and solve them numerically. Here, this work proposed a Gradient-guided Convolutional AutoEncoder (GCAE), where the gradient differential operator is incorporated as physical prior knowledge into the loss function of the neural network. The physical prior knowledge guides the training process of the neural networks, enhancing their physical interpretability compared with the purely data-driven Convolutional AutoEncoder (CAE). This work applied GCAE to the CO2 sequestration in the homogeneous formation, the heterogeneous formation, as well as the heterogeneous formation with different well placements to demonstrate the improvement in prediction accuracy, data stability, and generalization capability compared with the CAE approach.