Good reservoir injectivity is a fundamental requirement for high-quality CO₂ geological storage sites. Salt precipitation near injection wells, induced by brine evaporation and crystallization, is one of the key factors impairing reservoir injectivity. To clarify the differences in salt precipitation and consequent reservoir damage across distinct reservoir types, this study selected sandstone samples with varying micro pore structures and macro reservoir structures, and conducted salt precipitation simulation experiments based on a high-temperature and high-pressure core-flooding system. Employing thin-section analysis, scanning electron microscopy (SEM) with energy-dispersive spectroscopy (EDS), micro-area X-ray fluorescence (μ-XRF) spectroscopy, high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and micro-computed tomography (micro-CT) scanning, the salt crystal characteristics, distribution patterns, as well as variations in sandstone pore structures were systematically investigated. High-porosity and high-permeability reservoirs with favorable pore structures are characterized by a small number of salt precipitates, small-sized salt crystals, and dispersed single crystals. With the deterioration of the pore-throat size, sorting and connectivity, the quantity and size of salt crystals and their aggregates increase. With the change of the reservoir pore structures from the homogeneous large pore-throat type to the heterogeneous small pore-throat type, the distribution patterns of salt precipitation vary from weak homogeneous salt precipitation dominated by in-situ brine evaporation, to intensive local salt precipitation dominated by brine capillary backflow, and to intensive homogeneous salt precipitation controlled by brine capillary backflow and salt solute diffusion. Compared with macroscopically homogeneous massive sandstones, heterogeneous sandstones with low- and high-permeability zones generate a greater amount of salt precipitation both in low- and high-permeability segments. This is because the low-permeability zone lack effective brine displacement by injected CO₂, thereby retaining more residual brine for salt precipitation. Meanwhile, the salt crystal characteristics and contents indicate the existence of capillary backflow of brine from low-permeability zone to high-permeability zone. Reservoirs with different initial micro- and macro-structures have different characteristics of salt precipitation and thus varied risks of injectivity impairment. Heterogeneous reservoirs, both at the microscale and macroscale, carry a higher risk of salting-out induced reservoir damage, thus requiring the formulation of appropriate salting-out mitigation methods for these reservoirs.

How to cite: Sun, X., Deng, C., and Liu, K.: Effects of micro pore structures and macro reservoir structures on salt precipitation during CO2 geological storage, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-2112, https://doi.org/10.5194/egusphere-egu26-2112, 2026.

Ultra–deep shale geo–storage that couples secure CO₂ sequestration with enhanced CH₄ recovery demands explicit links from nanopore physics to reservoir–scale practice, yet how pore size and hybrid mineral-organic interfaces jointly govern CO₂–CH₄ competitive adsorption, mobility, and CH₄ displacement under the Lower Cambrian Qiongzhusi temperature–pressure window remains insufficiently quantified; here we address this by molecular–dynamics simulations in composite illite–TypeI kerogen slit nanopores spanning 2–10nm and five reservoir state points—330.15K and 30MPa, 360.15K and 45MPa, 390.15K and 60MPa, 420.15K and 75MPa, 450.15K and 90MPa—and by extracting gas-surface interaction energies, cohesive–energy density, a dimensionless competitive–adsorption indicator, self–diffusion coefficients, near–wall density integration, and CH₄ displacement efficiency during CO₂ injection into CH₄–saturated pores as constitutive inputs for dual–porosity⁄dual–permeability upscaling. Confinement amplifies selectivity: CO₂ consistently outcompetes CH₄ on both illite and kerogen, creating CO₂–rich adsorption layers that nearly exclude CH₄ from 2 nm surfaces; the competitive–adsorption indicator is ‹1 at 2nm (surface–dominated regime), rises to ≈1.3 at 4nm, and reaches ≈2.4–2.5 at 10nm at the highest temperature and pressure (mixed–fluid regime), while diffusion analysis shows CO₂ remaining surface–bound and slower than CH₄, which—once dislodged—resides in the central mixed fluid and is more mobile. Displacement metrics reveal a clear pore–width control: CH₄ displacement efficiency increases from ≈70–77% (2nm) to ≈85-89% (10nm), peaks near 390.15K and 60MPa, and declines slightly at 450.15K and 90MPa as elevated temperature weakens adsorption; near–wall integration confirms persistent CO₂ occupancy with a marked preference for illite across all conditions. Collectively, these pore–scale relations deliver a physically grounded design map for field deployment: (1) prioritize illite–rich, small–pore intervals to maximize durable CO₂ trapping and storage security; (2) leverage larger nanopores (≥4–10 nm) as the mobility corridor for liberated CH₄ to enhance deliverability; (3) schedule injections around moderate temperature and high pressure to balance displacement and retention; and (4) port the measured selectivity–width trends, cohesive–energy densities, diffusivity contrasts, near–wall occupancy fractions, and displacement curves directly into continuum simulators to forecast CO₂–EGR performance and monitoring signatures in Qiongzhusi–type ultra–deep reservoirs by connecting atomistic mechanisms to engineering–relevant operating windows and upscaling parameters.

How to cite: Zhang, L., Yuan, C., Tan, X., Stupakova, A., and Song, Z.: Geo–Storage Across Scales: From Nanopore Theory to Reservoir Practice for CO2–Driven Methane Displacement in Ultra–Deep Illite–Kerogen Shales, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-85, https://doi.org/10.5194/egusphere-egu26-85, 2026.

Geological CO₂ storage is a pivotal technology for achieving carbon neutrality. However, current assessments of storage potential predominantly rely on static volumetric methods or short-term simulations of dissolution processes. They often fail to adequately quantify the dynamic trapping capacity, particularly the actual contribution of mineral trapping, the dominant mechanism that ensures long-term permanence and enhanced security over centennial to millennial timescales.  This study developed a reactive transport modeling-based assessment framework to quantify the dynamic evolution and contribution of different trapping mechanisms, especially mineral trapping, over centennial timescales following CO₂ injection. A multiphase flow and reactive transport model, coupling CO₂-water-rock interactions, was established to simulate a 1000-year post-injection period for a typical reservoir A in China. The model integrates site-specific hydrogeological parameters and mineral reaction kinetics calibrated against experimental data. The simulation clearly reveals the sequential dominance of trapping mechanisms. Following injection cessation, the proportion of free-phase CO₂ decreases rapidly, while dissolution trapping increases significantly within the first century. Mineral trapping, the precipitation of carbonates such as calcite and dolomite, begins to contribute around 500 years and continues to grow, becoming the dominant mechanism for long-term security. This study proposes "effective mineral trapping capacity" as a time-dependent dynamic metric. In reservoir A, the amount of CO₂ immobilized through mineral reactions over a millennium far exceeds estimates based on short-term reactions, highlighting the necessity of long-term simulations to reveal the true storage potential. Besides, the simulation predicts the spatial evolution of CO₂ plume, trapping mechanism, formation pressure, and the impact of mineral reactions on porosity. This work provides a quantitative assessment of dynamic CO₂ mineralization potential through high spatio-temporal resolution reactive transport modeling. The findings elucidate the time-varying dominance of CO₂ trapping mechanisms for the design and risk management of CCUS project. Furthermore, it provides a transferable methodological framework for capacity evaluation and project optimization in similar or reactive reservoirs. This contributes to advancing the substantive deployment of long-term gigaton-scale, secure geological storage.

How to cite: Li, B., Pan, Z., and Zhang, K.: Dynamic CO₂ Storage Potential assessment via Reactive Transport , EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-15844, https://doi.org/10.5194/egusphere-egu26-15844, 2026.

How to cite: Yevugah, I. and Jacquey, A.: Consistent Dilatancy-Based Constitutive Model of Rock Salt for Geo-Energy Storage Applications: An Open-Source Numerical Implementation, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-6082, https://doi.org/10.5194/egusphere-egu26-6082, 2026.

The global energy system is transitioning to low-carbon solutions, with an increasing proportion of renewable energy sources. The intermittency of renewable energy generation, e.g. from wind and solar power, however, leads to a rising demand for large-scale and seasonal energy storage. Hydrogen is regarded as a vital energy carrier, and underground hydrogen storage (UHS) in porous geological media is considered a promising option due to its substantial storage capacity, relatively low cost, and potential safety benefits. Nonetheless, hydrogen leakage through caprock formations and hydrogen–rock–brine interactions remain critical uncertainties that require further research.

This study aims to investigate the impact of hydrogen injection on the sealing integrity of shale caprocks. High-pressure, constant-temperature batch reactor tests are employed to simulate gas–brine–rock interactions under reservoir-relevant conditions. Shale samples with three distinct mineralogical compositions (carbonate-, pyrite-, and clay mineral-rich) are selected to represent different types of caprock lithologies. Experiments are conducted using various gas compositions, including hydrogen and potential cushion gases, to evaluate how mineralogical heterogeneity influences geochemical reactions and caprock performance.

The ongoing experiments aim to identify the most suitable (i.e. hydrochemically stable) caprock composition for underground hydrogen storage, as well as gas compositions that are more favorable as cushion gases to enhance storage safety. The results are expected to provide insights into caprock stability and sealing behavior during future hydrogen storage operations.

How to cite: Fan, Q., Misch, D., Bensing, J., Skerbisch, L., and Shi, X.: Hydrochemical Stability of Shale Caprocks During Underground Hydrogen Storage (UHS), EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-5373, https://doi.org/10.5194/egusphere-egu26-5373, 2026.

Geological CO₂ storage during CO₂-enhanced oil recovery (CO₂-EOR) is a promising approach to simultaneously increase hydrocarbon production and mitigate carbon emissions. In this study, the potential of CO₂ huff-n-puff for heavy oil cold production and its associated CO₂ sequestration efficiency is experimentally evaluated. Five CO₂ huff-n-puff cycles were conducted at different injection pressures to determine the heavy oil recovery factor and CO₂ storage efficiency, and comparative tests were performed using N₂ and CH₄ huff-n-puff and viscosity-reducer-assisted CO₂ huff-n-puff. The results demonstrate that both heavy oil recovery factor and CO₂ storage efficiency increase with injection pressure and cycle number. At an injection pressure of 20 MPa, the cumulative oil recovery factor and CO₂ storage efficiency are 39.23% and 28.97%, representing increases of 14.61% and 16.76%, respectively, relative to 8 MPa. CO₂ exhibits the highest dissolved gas–oil ratio in heavy oil among the three gases tested at 16 MPa, and the resulting heavy oil recovery factor after CO₂ huff-n-puff are 3.59 and 1.86 times those obtained with N₂ and CH₄, respectively. The cumulative oil recovery factor and total oil exchange ratio are 10.12% and 1.76 t/t for N₂, 36.41% and 1.17 t/t for CO₂, and 19.57% and 4.96 t/t for CH₄. The heavy oil recovery factor is increased by approximately 3.24%–6.45%. These findings provide quantitative guidance for optimizing injection pressure and gas selection in CO₂ huff-n-puff schemes, thereby supporting the design and implementation of CCUS-oriented geological storage in heavy oil reservoirs.

How to cite: Du, K. and Li, S.: Experimental investigation of CO2 huff-n-puff for improving heavy oil recovery and CO2 underground storage, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-2523, https://doi.org/10.5194/egusphere-egu26-2523, 2026.

Hydrogen is an expensive and relatively scarce commodity. However, its storage—both to increase renewable energy efficiency by reducing curtailment and to support a zero-carbon energy system that reduces reliance on energy imports—appears inevitable. This raises a key question: how can the high upfront costs and substantial hydrogen volumes required for subsurface storage be reduced? One of the main cost drivers is the need for hydrogen cushion gas, which, depending on the techno-economic analysis, can account for up to 80% of the initial investment costs.

In this talk, we present two approaches to improve the competitiveness of hydrogen storage. First, drawing on lessons learned from the ACT Acorn CO₂ storage project, we explore the potential of a staged investment strategy. The central idea is to initiate storage operations at a small scale, requiring relatively modest volumes of cushion gas, while retaining the option to upscale if early phases prove successful and safe, efficient storage is demonstrated.

Second, we introduce a new conceptual model that allows hydrogen cushion gas to be replaced with cheaper and more readily available alternatives. The primary function of cushion gas is to provide compression during working gas injection and pressure support during production. We propose a strategy in which cushion gas (in this case CO₂) and working gas are spatially separated, preventing mixing or chemical reactions while still delivering the pressure support required for efficient operation.

We use the Long Clawson field in the East Midlands, UK, as a case study to demonstrate the theoretical feasibility of this approach. The field of interest is relatively shallow (approximately 680 m) and comprises several reservoir layers with an average thickness of ~10 m. Using an efficient black-oil simulator, reservoir modelling is employed to test and optimise the feasibility of cyclic hydrogen storage within these layers.

This work forms part of the East Midlands Storage (EMStor) project, a Strategic Innovation Fund–supported feasibility study focused on the development of hydrogen storage in repurposed hydrocarbon fields.

How to cite: Heinemann, N. and Williams, H.: An Innovative Approach to Reducing Upfront Costs in Hydrogen Storage via Cushion–Working Gas Separation, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-10001, https://doi.org/10.5194/egusphere-egu26-10001, 2026.

Green-hydrogen geological storage, geological sequestration of CO₂, and the generation, accumulation, and potential reservoir formation of natural hydrogen and methane involve a broad spectrum of lithologies, including sandstone, carbonate rock, shallow mudstone, halite (salt rock), serpentinite, basalt, granite, coal, and deep organic-rich shale. Marked contrasts in rock physical properties and pore-structure attributes can strongly regulate macroscopic gas diffusion. Therefore, elucidating gas diffusion behavior across different rock types is essential for evaluating gas storage capacity and geologic trapping potential.

In this work, representative rock samples were crushed to 0.50–0.841 μm particles and tested using a self-developed experimental setup to characterize the diffusion behaviors of H₂, CH₄, and CO₂ at 0.5 MPa. Depending on the observed diffusion features, diffusion coefficients were quantified using both unipore and dual-porosity (bidisperse) diffusion models. Pore-structure characteristics were independently constrained by N₂ physisorption, mercury intrusion porosimetry, and scanning electron microscopy, enabling a systematic assessment of pore-structure controls on gas diffusion. Additional experiments were performed on selected samples to compare diffusion coefficients under varying conditions of temperatures and pressures.

The results demonstrate pronounced inter-gas and inter-lithology differences in diffusion behavior, arising from contrasts in gas properties and rock pore structures. Overall, H₂ diffuses the fastest, followed by CH₄, whereas CO₂ exhibits the slowest diffusion. In micropores-rich rocks, CO₂ shows a distinct “fast initial–slow late-stage” diffusion pattern. Furthermore, diffusion coefficients increase with increasing temperatures but decrease with increasing gas pressures.

These findings reveal lithology-dependent response mechanisms in governing gas diffusion and provide a scientific basis for understanding gas migration in deep geological environments. The results also deliver key experimental constraints for studies of natural hydrogen and methane accumulation and for the assessment and optimization of geological CO₂ sequestration.

Acknowledgement: This work was supported by the Basic Science Center Program of the National Natural Science Foundation of China (NSFC) (Type A; No. 42302145).

How to cite: Xiao, G., Hu, Q., Hao, F., Zhang, T., Zong, Q., Wang, Q., Qiao, H., and Yang, S.: Comparative Diffusion Characteristics of Hydrogen, Methane, and Carbon Dioxide in Different Rock Types, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-12322, https://doi.org/10.5194/egusphere-egu26-12322, 2026.

Underground bio-methanation (UBM) of CO₂ and H₂ in depleted hydrocarbon reservoirs presents a promising strategy that combines carbon recycling, large-scale subsurface energy storage, and renewable CH₄ production. Despite its potential, the bio-reactive transport mechanisms underlying UBM remain poorly understood. To fill this knowledge gap, this study develops a numerical modeling framework. A coupled hydro-bio model was developed by integrating multicomponent multiphase flow with microbial growth and conversion processes, and was implemented numerically using the MATLAB Reservoir Simulation Toolbox (MRST). Key microbial kinetic parameters were calibrated using data from high-temperature and high-pressure conversion experiments conducted with formation water containing indigenous methanogenic microorganisms from the Shengli Oilfield, China. Within this this framework, the effects of operational and reservoir parameters, including shut-in duration, injection rate, and reservoir permeability, on gas transport, microbial conversion, and production performance were systematically investigated. Simulation results indicate that extended shut-in periods allow methanogens to continuously consume CO₂ and H₂, leading to greater pressure depletion and lower residual CO₂ in the gas phase. Specifically, increasing the shut-in duration from 180 to 720 days raises the final microbial CO₂ conversion from 43.5% to 96%. Higher injection rates extend the gas-front migration distance and stimulate a larger methanogen population, increasing the total CO₂ conversion, although the overall conversion efficiency slightly decreases due to higher gas input. In high-permeability reservoirs, enhanced gravity segregation causes gases to accumulate in the upper reservoir, limiting contact with methanogens near the far-well region and thereby reducing conversion efficiency. This study provides new insights into the coupled transport and microbial processes in UBM and offers guidance for the optimization of its design and field-scale implementation.

How to cite: Wu, L., Lin, J., Jiang, Y., Yu, D., Ren, L., Hou, Z., Fu, L., Luo, Z., and Xu, X.: Numerical analysis of bio-reactive transport in CO2-H2 underground bio-methanation within depleted reservoirs, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-1490, https://doi.org/10.5194/egusphere-egu26-1490, 2026.