Conference Agenda

Underground Hydrogen Storage (UHS) Demonstration in porous media requires understanding of Hydro-Mechanical-Electrical (HME) coupling under realistic in situ conditions. Usually, these domains are studied partially, limiting consistent interpretation and applicability to various reservoir flow simulations and monitoring strategies. To address this, we developed the System for Experimental Petrophysics (SEPP), which enables simultaneous hydraulic, electrical, and ultrasonic measurements on a single core during single-phase (brine) and two-phase (H₂-brine) flow. As part of the GEOZeit project to investigate potential site for UHS, experiments were conducted under in situ reservoir conditions (37 °C, 150 bar confining pressure and pore pressures ranging from 10 to 120 bar), representative for the former Ketzin CO₂ storage site in Germany. This multi-physics approach allowed investigation of flow properties, fluid saturation, and geomechanical response in Bentheimer sandstone during pore pressure cycling and relative permeability tests. Results show that as effective stress decreases, intrinsic permeability increases and bulk electrical resistivity decreases over the tested pressure range. During drainage two-phase flow, brine relative permeability sharply declines with brine saturation, whereas hydrogen permeability remains low, indicating limited gas connectivity at high brine saturation. Bulk resistivity increases with decreasing brine saturation, enabling real-time saturation tracking. P-wave velocity drops as brine saturation decreases, while S-wave velocity remains approximately constant. Joint HME analysis enables stress-dependent permeability estimations, pressure-dependent saturation retrieval, and differentiation between homogeneous and patchy fluid distributions. These findings demonstrate that integrated measurements on a single core provide parameters suitable for reservoir simulation and geophysical monitoring in UHS and other subsurface storage applications.

Hydrogen containment in the subsurface is important for underground energy storage and nuclear waste disposal, where it may be generated (e.g. by radiolysis). In these settings, gas is confined by sealing formations, including claystones. Gas accumulation may elevate pore pressures and induce capillary failure, enhancing gas migration. Sealing capacity is typically quantified by the gas breakthrough pressure (P_breakthrough); however, experimental constraints for H₂, particularly under stress, remain limited.

This study investigates H₂ capillary sealing in the Amaltheenton Claystone (Hils and Sack synclines, Lower Saxony Basin, Germany). The area provides a natural laboratory with a pronounced south–north gradient in thermal maturity and maximum palaeo-burial depth (d_max), enabling assessment of burial-dependent behaviour. Water-saturated core plugs were prepared parallel and perpendicular to bedding to evaluate anisotropy.

Stepwise gas pressurisation experiments were conducted under varying stress conditions, with breakthrough identified by an abrupt downstream pressure increase indicating formation of a continuous gas pathway. Diffusion coefficients (D_eff,t) and effective permeability (k_eff) were simultaneously determined.

P_breakthrough increases with confining pressure (0.75–3 MPa at 5–20 MPa) for a shallow-buried sample, consistent with stress-induced pore compaction. It also increases systematically with burial depth, from 3 to 5.5 MPa across samples spanning d_max ~1.7–2.8 km, reflecting progressively tighter pore structures. Minor bedding anisotropy is observed. D_eff,t values are on the order of ∙10^-10–∙10^-11 m²/s. Following breakthrough, k_eff increases by up to one order of magnitude (∙10^-23–∙10^-22 m²).

These initial findings constrain gas pressures sustained by the claystones and inform migration risk assessment in subsurface systems.

Underground hydrogen storage (UHS) in geological formations is emerging as a promising strategy to support the energy transition by balancing energy supply and demand while reducing greenhouse gas emissions. Ensuring caprock integrity is critical for safe hydrogen (H₂) containment and efficient recovery from porous reservoirs.

This study evaluates the quality of the Middle Triassic Weser Formation as a caprock at the Ketzin CO₂ pilot site (North German Basin), which is currently being assessed as a potential test site for UHS in a saline aquifer. The Weser Formation is composed of mudstones interbedded with evaporite and dolomite layers, which overlie the reservoir sandstones of the Stuttgart Formation.

An integrated characterization of the mineralogical, geochemical, and petrophysical properties of the caprock is presented. In particular, we address open questions related to caprock behavior under UHS conditions, including the geochemical reactivity of H₂ with caprock minerals. Hydrogen wettability is also investigated, which controls sealing capacity and hydrogen retention.

The results indicates that the Weser Formation has a good potential as a caprock for UHS, based on its fine-grained lithology, high clay content, substantial thickness (~80 m), and favorable petrophysical properties. Its wide spatial distribution across the North German Basin further supports its suitability as a regionally effective sealing formation for UHS. However, long-term geochemical stability during hydrogen storage remains a key uncertainty. Our experiments showed that Fe-bearing carbonates can react with H₂, changing the caprock porosity and permeability and potentially affecting its sealing integrity over time.

Hydrogen dissolution and microbial reaction are important controls on underground hydrogen storage (UHS) in porous rocks. When hydrogen dissolves into formation water, it can feed microbial communities and alter brine chemistry. A saline-aquifer analog of the former Ketzin gas storage site (town gas, natural gas, CO₂) is used here to assess dissolved H₂ during repeated storage cycles. The numerical analysis focuses on dissolved-phase reactive transport and the water-chemistry response around an injection well. It gives a hydrogeochemical view of UHS under saline aquifer conditions.

The dissolved-phase reactive-transport reservoir model couples H₂ migration with methanogenesis, sulfate reduction, acetogenesis, microbial biomass growth, and pyrite precipitation. This numerical model is solved using Geochemist Workbench. Hydrogen has very low dissolution rate in brine for the modeled temperature, pressure and salinity. At this injection condition, dissolved H₂ stays concentrated near the well. This is also valid due to five months of injection and five months of production times. Methanogenesis generates dissolved CH₄(aq) during the early storage period. As cycling continues, sulfate-reducing activity becomes dominant at the domain scale. Dissolved sulfide remains low because pyrite formation removes much of the sulfide produced by microbial sulfate reduction.

Near-well methane accumulation, sulfate depletion, and pH change contribute to the water-chemistry response. In this dissolved-H₂ case, they are stronger monitoring signals than dissolved sulfide. A small dissolved hydrogen input can therefore create local geochemical change. For similar saline-aquifer conditions, monitoring programs can combine hydrogen, methane, sulfate, sulfide, and pH measurements to identify both hydrogen transport and microbial conversion.

This study investigates microstructural changes in natural anhydrite exposed to brine, sulphate-reducing bacteria, hydrogen, and carbon dioxide under controlled laboratory conditions. Three anhydrite samples from a salt pillow in the Netherlands were analysed to assess how mineralogical heterogeneity, grain size, impurities, and pore structure influence biotic and abiotic reaction processes relevant to hydrogen storage in salt caverns.

The samples were artificially fractured to increase reactive surface area and examined before and after treatment using scanning electron microscopy, energy-dispersive spectroscopy, broad-ion-beam cross sections, and image analysis. Hydration experiments showed limited gypsum formation at 20°C, while no hydrate formation was observed at 40°C. Exposure to brine caused secondary porosity in impure anhydrite samples, mainly through the mobilisation of fine-grained talc along grain boundaries.

Experiments with Desulfovibrio desulfuricans, H₂, and CO₂ revealed microbial activity, biofilm formation, low but measurable H₂S production, and the precipitation of secondary carbonate phases. Calcium carbonate replacement occurred along anhydrite grain boundaries and was most pronounced in fine-grained, relatively pure anhydrite. Coarser and more impure samples showed more open grain boundaries and higher secondary porosity, suggesting that magnesium-bearing phases and other impurities influence reaction kinetics and carbonate precipitation.

The results demonstrate that even low-porosity anhydrite can undergo microstructural and mineralogical alteration when exposed to reactive fluids and microorganisms. These changes may affect porosity, transport pathways, and mechanical integrity in anhydrite-bearing salt formations. Site-specific experimental studies using natural samples are therefore essential for constraining reaction kinetics and assessing the long-term durability of hydrogen storage caverns.