Geologic Carbon Sequestration Research Articles

Mechanical integrity of tubular elements based on strength and fracture criteria during transient CO2 injection

Geological carbon sequestration (GCS) is an essential technology for reducing carbon emissions. Wellbore integrity is crucial to ensure the safety of GCS. During low-temperature carbon dioxide (CO2) injection, the wellbore temperature decreases, causing the tubing and casing to contract, resulting in considerable axial tensile stresses, and making mechanical failure likely. This paper establishes a transient flow model for CO2 injection to predict the temperature and pressure distribution in the wellbore. Then, the strength safety factor of the tubing and casing is calculated using the material strength criteria. Fracture mechanics theory is employed to analyze the risk of crack propagation in defective tubing or casing during CO2 injection. The study indicates that the wellbore temperature near the wellhead is lower as CO2 is injected. Under typical injection conditions, the tubing and casing have high strength safety factors but small crack propagation factors. The stress intensity factor of cracks on the tubing and casing's outer surface is more significant than inner surface defects, posing a higher risk of crack propagation. When the tubing or casing exits a penetrating crack, its propagation safety factor is less than 1, necessitating the avoidance of through-wall cracks. The results guide maintaining wellbore integrity in carbon dioxide geological sequestration engineering.

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

Heterogeneous reservoirs offer greater potential for increased oil production and carbon storage capacity when using CO2 injection-production coupling technology in a broader range of geological formations. However, the impact of heterogeneity on the mechanisms and effectiveness of CO2 utilization and storage remains unclear. This study comprehensively investigates the mechanisms of enhanced oil recovery and the sequestration potential of CO2 injection-production coupling technology in heterogeneous reservoirs using both microscopic visualization experiments and macroscopic core experiments. The results reveal that during continuous gas flooding, CO2 forms rapid flow channels, leading to the formation of oil films and columnar residual oil in high-permeability zones, while small pores remain unaffected. Meanwhile, under high-speed injection conditions, the overall microscopic recovery rate increases by 13.8%. However, a higher proportion of porous residual oil is retained in low-permeability zones. During asynchronous injection-production cycles, the microscopic recovery rate remains above 86%, indicating a more thorough utilization of porous residual oil, which is predominantly present in membranous and angular corner configurations. The mechanisms of enhanced oil recovery include the increase in energy, dissolution expansion, and displacement-transport mechanisms. In asynchronous injection-production mode, macroscopic recovery rates are all above 80%. Additionally, with an increase in permeability contrast, the CO2 utilization efficiency rises from 5.9% to 8.6%, demonstrating the high potential of injection-production coupling technology for enhanced oil recovery and geological carbon sequestration in heterogeneous reservoirs. This study provides theoretical support for CO2 injection development and geological sequestration in heterogeneous reservoirs.

Combining Steam and Flue Gas as a Strategy to Support Energy Efficiency: A Comprehensive Review of the Associated Mechanisms.

Conventional steam injection projects have long been an iconic process in the development of heavy oil reserves; nevertheless, they face significant challenges in terms of energy efficiency, environmental compliance, and economic viability. Factors such as oil price fluctuations, the imperative for an energy transition, and the push to reduce carbon footprints are hindering new or ongoing implementations of traditional steam injection technologies. In response to these challenges, hybrid methods, such as the combination of steam and flue gas, are emerging as an opportunity to optimize thermal processes to improve oil recovery, energy efficiency, and environmental sustainability and extend reservoir productivity life. Steam injection enhances oil recovery by reducing the viscosity of crude oil, improving oil mobility and facilitating its extraction. The utilization of flue gas in steam injection processes has a significant impact on oil recovery and energy efficiency, leveraging industrial byproducts. This not only lowers operating costs but also reduces environmental emissions, aligned with energy transition trends. Incorporating the flue gas into a steam-based process in heavy oil reservoirs has emerged as a promising thermally enhanced oil recovery strategy. This work presents a comprehensive review based on experimental, numerical, and field studies of hybrid steam and flue gas technology as an EOR process. The main recovery mechanisms associated with the process are analyzed. In addition, the laboratory equipment required for experimental evaluations is presented, and reservoir modeling, kinetic and compositional effects on reservoir fluids, and the reduction in heat losses in the steam injection process are discussed. Furthermore, field implementations are reviewed to evaluate lessons learned and experiences on an operative scale. The combination of steam and flue gas represents an opportunity for carbon utilization and geological carbon sequestration. This dual functionality underscores its potential to enhance oil recovery and address carbon-related environmental concerns.

Simulation of CO2 dissolution reactions in saline aquifers using lattice Boltzmann method

CO2 dissolution reactions in saline aquifers during geologic carbon sequestration (GCS) involve multiple physicochemical processes and pose a challenge for both experimental and numerical techniques to capture reactive transport features and complex porous structures. Benefited from advanced models in the lattice Boltzmann (LB) community, namely, multiphase flow LB model and multicomponent transport LB model with chemical reactions, dynamics of CO2-water interfaces, concentration evolution of ions, and heterogeneous and homogeneous reactions could be readily captured by the proposed LB model to characterize CO2 dissolution reactions applicable to far-field applications. This LB model can not only emphasize CO2 dissolution processes at the scale of a few pores but also elaborate on the corresponding controlling mechanisms in porous media during GCS in saline aquifers. LB simulations herein indicate that both diffusion coefficient and reactive interfacial length may change the total concentration gradient at the CO2-water interface to further affect CO2 dissolution reactions. It is also confirmed that CO2 dissolution is a non-equilibrium process, which could not be neglected in reservoir-scale simulations. The effect of reactive interfacial length on CO2 dissolution is negligible due to a narrower range of contact angles in saline aquifers. Influenced by the structural complexity of porous media, the dissolution of CO2 clusters shows a strong heterogeneous characteristic evaluated by the pore size distribution. The evolution of pH in homogeneous reactions is estimated via mass action equations. Besides, the effects of partial pressure, formation temperature, and salinity, as three key factors in the practical application, are thoroughly probed. The high pressure is conducive for sequestration because of its greater sequestration efficiency, but the temperature has both positive and negative impacts on CO2 dissolution trapping and should be carefully evaluated in a certain saline aquifer before the operation. High ion strength would decrease the efficiency of dissolution trapping to some extent.

Deep learning-assisted Bayesian framework for real-time CO2 leakage locating at geologic sequestration sites

Accurate and efficient localization of CO2 leakage if occurred in subsurface formations, is of significant importance in achieving secure geological carbon sequestration (GCS) projects. However, this task is inherently challenging due to the considerable uncertainties in the subsurface. In this work, we develop a novel deep learning-assisted Bayesian framework for identifying potential CO2 leakage sites based on the reservoir pressure transient behavior measured at the wellbores of injection or observation wells. The method consists of two essential steps: 1) Deep learning surrogate: This step aims to effectively replace the intensive high-fidelity simulation with an efficient deep learning surrogate. 2) Bayesian inversion: In this step, the posterior distributions of potential CO2 leakage locations are inverted, in which the surrogate serves as the forward model. The above two processes are automated using Bayesian optimization instead of a labor-intensive trial-and-error approach. The proposed framework is verified using a 3D geological model simulating CO2 sequestration into a brine-filled reservoir. The results demonstrate the Bayesian-optimized surrogate could successfully capture the underlying process of subsurface CO2-brine flow. The Bayesian inversion algorithm enables localizing CO2 leakage with high accuracy. To our knowledge, the proposed Bayesian framework is implemented for the first time to locate multiple leakage sites at the field scale. The proposed workflow provides an accurate and efficient approach to detecting possible CO2 leakage locations in a real-time manner and has promising potential for field-scale GCS applications.

Machine Learning-based 4-D Seismic Data Integration and Characterization of Channelized Anticline Aquifer for Geological Carbon Sequestration

Machine Learning-based 4-D Seismic Data Integration and Characterization of Channelized Anticline Aquifer for Geological Carbon Sequestration

Hydraulic Behavior of Fractured Calcite-Rich Sandstone After Exposure to Reactive CO2–H2O Flow

Geological carbon sequestration in jointed reservoirs will require the use of fracture network for the flow of CO2 plumes. However, acidic solution formed at the interface between brine and CO2 can cause chemical erosion of the local rock mass, especially in rocks with high carbonate content. The use of the water alternating gas technique for injection stimulation can exacerbate this issue, as the water–CO2 interface occurs in areas near the injection point. As a result, acidic flow can impact the surrounding rock mass, particularly around the main flow paths where fracture network conductivity is much higher than matrix permeability. To investigate the impact of acidic flow on fracture conductivity, we conducted an experiment on a fractured sandstone sample that was exposed to CO2-saturated water. Our findings revealed a nearly ten-fold increase in post-experimental water-relative permeability, and restriction of flow within established flow channels, which consist one third of the fracture surface. In conclusion, our study sheds light on the dynamic behavior of fractured sandstone under the influence of CO2–H2O flow, revealing significant changes in transmissivity and fracture geometry. These findings contribute to a better understanding of the hydraulic performance of fractures in the context of geological carbon sequestration.

Engineering Meter-scale Porous Media Flow Experiments for Quantitative Studies of Geological Carbon Sequestration

This technical note describes the FluidFlower concept, a new laboratory infrastructure for geological carbon storage research. The highly controlled and adjustable system produces a strikingly visual physical ground truth of studied processes for model validation, comparison and forecasting, including detailed physical studies of the behavior and storage mechanisms of carbon dioxide and its derivative forms in relevant geological settings for subsurface carbon storage. The design, instrumentation, structural aspects and methodology are described. Furthermore, we share engineering insights into construction, operation, fluid considerations and fluid resetting in the porous media. The new infrastructure enables researchers to study variability between repeated CO2 injections, making the FluidFlower concept a suitable tool for sensitivity studies on a range of determining carbon storage parameters in varying geological formations.

Integrated containment risks assessment for subsurface CO2 storage: Overburden analysis and top seal integrity study, offshore Norway

This study summarizes the OASIS (Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea) project that focuses on assessing the containment risks associated with the geological carbon sequestration (CCS) of the Northern Lights project. CCS is viewed as one of the most effective solutions for reducing carbon emissions, as it captures carbon dioxide from point sources and permanently stores it in suitable geological formations. However, injecting CO2 into the subsurface may have mechanical consequences, including fault reactivation, top seal fracturing, surface heave, etc. This study proposes an interdisciplinary workflow to characterize the caprock, faults, and overburden associated with CCS projects in the Horda Platform area, to improve injection-induced containment risk assessment. Our findings show that the proposed workflows and tools effectively characterize stress-related mechanical hazards. However, due to the complex nature of rocks, it is challenging to evaluate the top seal integrity using a single method. Therefore, the proposed interdisciplinary approach is more effective for any fluid injection site's characterization, given the complex nature of the subsurface and its behavior under injection-induced stress changes. This research paper adds knowledge about the top seal integrity assessment and the reliability of injected CO2, making CCS projects more reliable and safer. Although this study focuses on the northern North Sea, the proposed methods are equally applicable globally to characterize subsurface CO2 storage sites. Apart from CCS projects, these research results can benefit other subsurface injection projects, such as water injection for reservoir management, wastewater injection for disposal, hydrogen storage, and hydraulic fracturing for unconventional hydrocarbon resources.

On the resilience of bio-cemented silica sands in chemically reactive environment

Exposure of geomaterials to an acidic environment is frequently encountered in modern-day geo-energy and geo-environmental engineering activities, in e.g. incorporation of chemical stimulation for unconventional shale gas exploitation, enhanced geothermal systems, geological carbon sequestration, and the long-term regional stability in carbonate-rich coastal areas. The Multiphysics-involved process for each application is complex and an optimised control calls for a better understanding on the coupling mechanism of the chemical, hydraulic and mechanical fields. This laboratory-based study aims to provide a quantitative calibration and derivation of the key coupling parameters accommodating our recently proposed framework of reactive chemo-mechanics, using a bio-cemented rock-like material as a representative for dissolvable rocks. The advantage of bio-cemented specimens (here by microbially induced carbonate precipitation) over natural rocks lies in their more uniform grain-bond structure and laboratory tunable calcite content. An experimental setup is introduced for investigating the role of calcite content on the mechanical and hydraulic properties of bio-cemented silica sands, followed by uniaxial tests on the bio-cemented specimens immersed in acidic environment to allow a reactive chemo-mechanical setting. Our results show that bio-cemented samples appear to be more “resilient” to an acidified aqueous environment in terms of less strength degradation compared to natural carbonate-rich rocks. Ductile failure mode is observed in the bio-cemented specimens within a certain range of the calcium carbonate content and a brittle-to-ductile transition in the failure mode occurs when the calcite content in the specimen decreases. With the calibrated model and the derived coupling parameters, we further illustrate an example of numerical prediction on the mechanical response of bio-cemented specimens under varying acidic environments and loading rates.

Impact of wettability on capillary phase trapping using pore-network modeling

The impact of rock wettability on phase mobility and capillary trapping is significant in the valuation of geologic carbon sequestration scenarios. Wetting conditions of CO2/brine/rock systems can vary from site to site and over time due to changes in temperature, pressure, salinity, mineral composition and surface roughness. Therefore, effective predictability of CO2 mobility and trapping in underground formations requires a thorough exploration of the relationship between wetting conditions and phase saturation over a wide range of contact angles. In this paper, we use pore-network modeling to investigate the effect of wettability on phase mobility and capillary trapping. We simulate different wetting and nonwetting conditions during secondary flooding cycles where the initial phase saturations are varied significantly. Characteristic initial-residual (IR) saturation curves and the locus of residual phase connectivity and saturation are determined for each wettability condition.Simulations show that when the receding phase is the wetting phase, there is reduced trapping of that phase owing to piston-like advance by the nonwetting phase and sustained layer flow of the wetting phase. Such flow regimes cause nonlinearity in the characteristic initial-residual (IR) saturation curve, which is not captured by traditional trapping models. A proposed extended Land-based model matches the IR trends for all wettabilities. Simulations also show that the loci of residual phase saturation and phase connectivity are a strong function of wettability. When the receding phase is strongly nonwetting, the locus remains nearly constant in phase connectivity, while at increasingly wetting conditions, the locus forms a closed-loop in the saturation-connectivity space, where the endpoint of the locus is constrained by pore topology as residual saturations approach low values.

Effects of roughness on density-driven convection of dissolved CO2 in discrete fracture-matrix system

Dissolution trapping is a permanent and safe mechanism for geological carbon sequestration. An increase in density caused by the dissolution of CO2 into brine can trigger a density-driven convection process. In this study, the effect of fracture roughness on the density-driven convection process in heterogeneous saline aquifers is numerically analyzed by using a three-dimensional rough fracture-matrix model. The results show that the variation of the fracture aperture, a microscale heterogeneity phenomenon, can result in the change of the macroscopic flow characteristics. The rough fracture surface intensifies the convection inside the fracture and makes the migration path of the solute more tortuous. The spatial variability of the aperture generates the merging of convective fingers and suppresses the development of weak convective fingers, thus further enhancing the longitudinal extent of convective mixing. It is indicated that neglecting roughness during the flux growth stage can lead to an underestimation of dissolved fluxes by about 20%. The consideration of fracture roughness variation can contribute to the better understanding and prediction of the dynamics of dissolved CO2 in real reservoirs.

Emergence of Unstable Focused Flow Induced by Variable‐Density Flows in Vertical Fractures

AbstractFluids with different densities often coexist in subsurface fractures and lead to variable‐density flows that control subsurface processes such as seawater intrusion, contaminant transport, and geologic carbon sequestration. In nature, fractures have dip angles relative to gravity, and density effects are maximized in vertical fractures. However, most studies on flow and transport through fractures are often limited to horizontal fractures. Here, we study the mixing and transport of variable‐density fluids in vertical fractures by combining three‐dimensional (3D) pore‐scale numerical simulations and visual laboratory experiments. Two miscible fluids with different densities are injected through two inlets at the bottom of a fracture and exit from an outlet at the top of the fracture. Laboratory experiments show the emergence of an unstable focused flow path, which we term a “runlet.” We successfully reproduce the unstable runlet using 3D numerical simulations and elucidate the underlying mechanisms triggering the runlet. Dimensionless number analysis shows that the runlet instability arises due to the Rayleigh‐Taylor instability (RTI), and flow topology analysis is applied to identify 3D vortices that are caused by the RTI. Even under laminar flow regimes, fluid inertia is shown to control the runlet instability by affecting the size and movement of vortices. Finally, we confirm the emergence of a runlet in rough‐walled fractures. Since a runlet dramatically affects fluid distribution, residence time, and mixing, the findings in this study have direct implications for the management of groundwater resources and subsurface applications.

Distribution of CO2-CH4 in a nanoslit medium and the efficiency of displacement of CH4 by CO2

The replacement of CH4 with CO2 in reservoirs is crucial for natural gas exploitation and sequestration of CO2. Therefore, the states and distribution patterns of coexisting CO2 and CH4 and the dynamic patterns of CH4 displacement by CO2 in mineral slits must be understood. Here, we simulate the molecular dynamics and displacement efficiency of CH4 in gypsum, quartz, and illite mineral slit models. The results demonstrate that gas density is not uniform throughout the slits and prove that gypsum and quartz have a greater adsorption capacity for CO2 than for CH4 and illite has a greater adsorption capacity for CH4. We find that (1) the application of the same force to different mineral slits leads to dissimilar CH4 displacement efficiencies, whereas an increase in the applied force in the same mineral slit is positively correlated with the CH4 displacement efficiency; (2) the main factor affecting CH4 displacement efficiency is CO2 adsorption; (3) the greater the adsorption capacity of mineral slits for CO2 (such as for gypsum), the more difficult it is to displace the CH4 in the slit despite large applied force; and (4) CH4 displacement efficiencies of illite, quartz, and gypsum decrease under the same conditions. These results provide a reference for theoretical research and industrial applications related to geologic carbon sequestration.

High-resolution geoelectrical characterization and monitoring of natural fluids emission systems to understand possible gas leakages from geological carbon storage reservoirs

Gas leakage from deep geologic storage formations to the Earth’s surface is one of the main hazards in geological carbon sequestration and storage. Permeable sediment covers together with natural pathways, such as faults and/or fracture systems, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of natural gases are released, can be helpful for understanding the effects of potential gas leaks from carbon dioxide storage systems. In this framework, we propose a combined use of high-resolution geoelectrical investigations (i.e. resistivity tomography and self-potential surveys) for reconstructing shallow buried fracture networks in the caprock and detecting preferential gas migration pathways before it enters the atmosphere. Such methodologies appear to be among the most suitable for the research purposes because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO2 storage (i.e. porosity, fracturing, water saturation, etc.). The effectiveness of the suggested geoelectrical approach is tested in an area of natural gas degassing (mainly CH4) located in the active fault zone of the Bolle della Malvizza (Southern Apennines, Italy), which could represent a natural analogue of gas storage sites due to the significant thicknesses (hundreds of meters) of impermeable rock (caprock) that is generally required to prevent carbon dioxide stored at depth from rising to the surface. The obtained 3D geophysical model, validated by the good correlation with geochemical data acquired in the study area and the available geological information, provided a structural and physical characterization of the investigated subsurface volume. Moreover, the time variations of the observed geophysical parameters allowed the identification of possible migration pathways of fluids to the surface.

Multi-Scale Seismic Measurements for Site Characterization and CO2 Monitoring in an Enhanced Oil Recovery/Carbon Capture, Utilization, and Sequestration Project, Farnsworth Field, Texas

To address the challenges of climate change, significantly more geologic carbon sequestration projects are beginning. The characterization of the subsurface and the migration of the plume of supercritical carbon dioxide are two elements of carbon sequestration that can be addressed through the use of the available seismic methods in the oil and gas industry. In an enhanced oil recovery site in Farnsworth, TX, we employed three separate seismic techniques. The three-dimensional (3D) surface seismic survey required significant planning, design, and processing, but produces both a better understanding of the subsurface structure and a three-dimensional velocity model, which is essential for the second technique, a timelapse vertical seismic profile, and the third technique, cross-well seismic tomography. The timelapse 3D Vertical Seismic Profile (3D VSP) revealed both significant changes in the reservoir between the second and third surveys and geo-bodies that may represent the extent of the underground carbon dioxide. The asymmetry of the primary geo-body may indicate the preferential migration of the carbon dioxide. The third technique, cross-well seismic tomography, suggested a strong correlation between the well logs and the tomographic velocities, but did not observe changes in the injection interval.

Subcritical CO2 adsorption on geomaterials of coal-bearing strata in the context of geological carbon sequestration

This paper explores the adsorption behaviour of geomaterials in the framework of CO2 sequestration in shallow level coal seams. Manometric adsorption experiments were carried out on two anthracite coal samples, two rock samples from East Irish Sea, MX80-bentonite, Speswhite kaolinite, dry, wet and biofilm-laden (Bascillus mojavensis-laden) sand at subcritical pressure range (up to 6.4 MPa) of isothermal condition at 298.15 K. The experiments were aimed to investigate the influence of the biogeological conditions of coal and caprock constitutions on CO2 adsorption. At lower pressures, the moisture had an influence on the CO2 adsorption on coal resulted in reduced adsorption capacity. At elevated pressures, the volume expulsion behaviour and coal-water interaction had an influence on the adsorption capacities of moist coal sample and resulted in comparable adsorption capacities to dry sample. The disparity in the adsorption capacities between the wet powdered and wet intact core samples showed that the results obtained with powder samples may not reflect the field conditions. Wet conditions and Bascillus mojavensis bacteria influenced the adsorption capacity of sand and showed CO2 chemisorption capacity. The desorption isotherm pattern of wet and biofilm sand showed that the CO2 was continuously adsorbed independent of the gas phase pressure. Among the clay minerals, bentonite had greater affinity towards CO2. Despite the fact that the adsorption capacity of the cap rock is smaller than that of the coal samples, the experimental investigation with constituents of the cap rock provides insights into the effect of biogeological conditions of coal and rock sample constituents on CO2 storage in coal seams.

New insights into the dolomitization and dissolution mechanisms of dolomite-calcite (104)/(110) crystal boundary: An implication to geologic carbon sequestration process

Geologic carbon sequestration (GCS) is a promising strategy to reduce the harm of CO2 due to the rapidly increased fossil fuel combustion. Dolomitization and dissolution processes of deeply buried carbonate reservoirs significantly impact the potential of GCS. However, previous investigations mainly focus on the macroscopic batch experiments, the mechanisms at atomic level are still unclear especially for crystal boundary, but urgently required. Herein, the GCS potential and the effects of boundary dissolution on calcite and dolomite were investigated based on both analytical and simulation methods such as molecular dynamics simulation (MDS) and density functional theory (DFT) calculations, to deeply unveil the mechanisms of dolomitization and formation of intergranular secondary pores from the atomic perspective. The morphology results indicated that the dissolution of calcite and dolomite in carbonic acid solution started via the edges and corners. In addition, the simulated results showed that the carbon sequestration potential presented an order in dolomite (PMg50%) > PMg40% > PMg30% > PMg20% > PMg10% > calcite by dolomitization due to the reduced bulk volume but increased lattice stress. Furthermore, both electrons transfer and diffusion coefficients results suggested that the (104)/(110) boundary was preferentially dissolved as compared to the (104) and (110) planes, indicating that crystal boundary was beneficial to the formation of pores for the oil and gas storage, but harmful to the stability of long-term GCS. Therefore, this study, for the first time, provides new insights into uncovering the mechanisms of the GCS process in depth, from an atomic level focusing on the crystal boundary, thereby promoting the understand of the long-term evolution for both calcite and dolomite in deep reservoirs.

Numerical simulation of the impact of different cushion gases on underground hydrogen storage in aquifers based on an experimentally-benchmarked equation-of-state

Underground hydrogen storage (UHS) in geological formations is a promising technology for large-scale hydrogen energy storage. In this study we focus on UHS in saline aquifers. Although lessons were learned from similar studies, including geological carbon sequestration and underground gas storage, the unique thermodynamic and physical properties of hydrogen distinguish UHS from the other subsurface storage projects. We developed a two-phase, three-component reservoir simulator, which incorporated essential physics based on the fully coupled multi-physics framework of the Delft Advanced Reservoir Simulation (DARSim). Properties of fluid mixtures were computed using the GERG-2008 equation of state (EoS), in which the parameters were determined by fitting laboratory data. The simulation results demonstrated the impact of different cushion gases (CO2, CH4, and N2) on UHS. Most hydrogen stayed in the gaseous phase at the top of the aquifer when CH4 and N2 were used as the cushion gas. Conversely, hydrogen-rich fingers were observed in the aqueous phase when CO2 was used as the cushion gas, because dissolved CO2 increased brine density, leading to density-driven downward convection which was favorable for hydrogen dissolution into the aqueous phase. The highest purity of produced hydrogen was observed when CO2 was used as the cushion gas, whereas using CH4 and N2 as the cushion gas was favorable for the hydrogen production rate and mobility. This work is the first study that utilizes an EoS-based reservoir simulator to investigate hydrogen's flow patterns and interactions with cushion gases in an underground storage system. Specifically, the productivity and retrievability of hydrogen in a two-phase, three-component UHS system were analyzed in detail. The developed reservoir simulation tool and research findings from this study will be valuable to support decision making in practical UHS projects.

Pore-scale modeling of thermal-hydro-mechanical-chemical coupled rock dissolution and fracturing process

Acid fracturing can effectively improve the connectivity inside underground reservoirs, which is of significance for geothermal exploitation and geological carbon sequestration. It involves a complex thermal-hydro-mechanical-chemical (THMC) coupled process. This work first develops a pore-scale THMC coupled model combining the lattice Boltzmann method (LBM) and the discrete element method (DEM) to describe the acid fracturing process, particularly covering chemical damage, rock dissolution, and solute transport. A chemical damage variable based on the cohesive bond is proposed to characterize the alteration of mechanical parameters caused by local rock dissolution. The change of fluid pathway due to rock dissolution is handled by the lattice Boltzmann solute transport model combined with the volume of pixel method. Based on the proposed model, the influence of injection pressure and Damkohler number (Da) on the THMC coupled rock dissolution and fracturing process is analyzed. Results indicate three types according to dissolution morphologies, i.e., permeation, cavity, and permeation-cavity. The first and second types are related to the reaction-controlled and diffusion-controlled processes, respectively. Particularly, the permeation-cavity type occurs at conditions with high injection pressure and high Da and is the combination of the first two types, where the dissolution around the main fracture presents the cavity type but converts into the permeation type around secondary fractures. Additionally, the evolution patterns of reactive surface area and dissolution rate with time differ significantly with rock dissolution types. In particular, for the permeation type, the aperture of fracture far away from the injection hole could be larger than that near the injection hole under the THMC coupling, which is quite different from HM and THM coupling.