The global commitment to mitigate climate change necessitates a transition of energy systems from fossil fuels to renewable sources. However, renewable energy technologies—such as wind and solar—provide intermittent supplies of clean energy. To manage this variability and minimize curtailment, storing excess energy as hydrogen presents a promising solution. A significant portion of the capital expenditure in subsurface hydrogen storage is attributed to the need for both working gas and cushion gas. Cushion gas refers to the volume of gas that remains permanently in the reservoir to maintain the pressure required for effective withdrawal of the working gas during injection–withdrawal cycles. Similar to CO₂ storage projects—where high upfront costs have been identified as a key barrier to implementation—hydrogen storage in porous media faces substantial capital costs. In fact, cushion gas can account for over 80% of total CAPEX in these systems (1), highlighting the critical need to reduce this cost. In this presentation, I will introduce three strategies to reduce the cost of cushion gas in hydrogen storage. Firstly, I will propose rethinking cushion gas not as a sunk operational cost, but as a recoverable and strategic national energy reserve—transforming it into an investment in energy security. Secondly, I will explore the use of alternative cushion gases, such as CO₂, to reduce overall storage costs. This will include a novel strategy using a case study from the Southern North Sea basin. Finally, and drawing on insights from the EMStor project (2), I will present a phased, cost-efficient development model. This approach begins with a moderately sized storage project, pre-designed for future expansion, thereby encouraging long-term investment.

1. https://doi.org/10.1016/j.ijhydene.2022.11.292
2. The UK's largest inland hydrogen cluster | East Midlands Hydrogen

Underground hydrogen storage in porous rocks presents a promising solution for renewable energy storage. While geochemical reactions between hydrogen and reservoir minerals are generally believed to have minimal impact on hydrogen loss or reservoir integrity, this assumption is based on limited experimental evidence. To accurately assess hydrogen's role in geochemical interactions, it is essential to conduct comprehensive batch experiments with appropriate control scenarios that distinguish hydrogen-induced effects from those arising solely from fluid–rock interactions. This study investigates the geochemical reactivity of hydrogen with reservoir sandstones containing less than 2% pyrite. Batch experiments were conducted using cylindrical core samples under conditions of 100 °C and 100 bar hydrogen partial pressure for five weeks. Three scenarios were examined: (1) dry samples exposed to hydrogen, (2) synthetic saline fluid-saturated samples with hydrogen, and (3) synthetic saline fluid-saturated samples with helium (as a control). Pre- and post-experimental analyses included measurements of permeability, porosity, magnetic susceptibility, thin-sections, fluid elemental concentrations (via ICP-OES and IC), and gas composition. In contrast to our previously studied pyrite-free Buntsandstein reservoir sandstones, the results from this study provide evidence that pyrite is reactive with hydrogen, potentially influencing other reservoir parameters. Specifically, samples exposed to hydrogen showed more than a twofold increase in magnetic susceptibility compared to those in the helium control group, indicating a potential formation of pyrrhotite from pyrite. Ongoing research into pyrite-bearing rocks aims to enhance the generalizability of these findings and contribute to more robust risk assessments for underground hydrogen storage.

To manage seasonal fluctuations in renewable energy, hydrogen can be produced from excess electricity and stored in geological formations. Saline aquifers, due to their large capacity and widespread presence in sedimentary basins, show strong potential for underground hydrogen storage (UHS). However, their viability in porous formations remains largely unproven. This study focuses on the Triassic Stuttgart Formation near Ketzin in the North German Basin, a former CO₂ storage site. Its heterogeneous lithology and anticlinal structure offer structural trapping potential, but a fault zone at the reservoir top presents a risk of gas migration, potentially intensified by geomechanical effects from cyclic hydrogen injection.

Previous UHS models have emphasised hydrodynamic behaviour, focusing less on geomechanical effects. However, understanding these effects is crucial for safe, long-term storage. This study presents a coupled hydro-geomechanical reservoir model to evaluate risks such as fault reactivation (assessed using slip tendency analysis of major faults near the wellbore) and ground deformation due to hydrogen injection and withdrawal. Site-specific simulations using CMG GEM indicate that faults remain stable and vertical displacements are within a small to moderate range.

The results provide valuable insight into flow and geomechanical behaviour during UHS in a saline aquifer setting. While based on a specific site, the analysis enhances understanding of reservoir integrity and supports the broader development of hydrogen storage technologies. The findings contribute to assessing the feasibility of UHS and aid in the design of a potential hydrogen storage demonstrator in the North German Basin.

The number of scientific articles on molecular hydrogen in the subsurface is exploding, indicating a growing interest in this potential energy resource. Various concentrations of hydrogen in naturally occurring gases and ppm values are reported, sometimes combined with projections of invoked large volumes of these gases based in part on overly optimistic assumptions. However, these figures are rarely placed into the context of a reserve estimate for an energy resource. Reserves are reliably proven quantities of raw materials that can be extracted with today's technology and at current prices. Although extraction technologies are still under development, recent cost estimates suggest that natural hydrogen may be price-competitive with hydrogen produced from renewable electricity. Nevertheless, volumetric quantities are very rarely estimated and reliably determined.

Three types of possible hydrogen deposits are predominantly discussed in the literature: accumulations over longer periods of time that could be extracted in the same way as hydrocarbon reservoirs, accumulations that are continuously replenished and source rocks that are artificially stimulated to produce hydrogen. The generation rates of H2 in the main processes, but also the reservoir properties, are crucial for assessing these possible hydrogen deposits.

We use reported gas flow rates for different geological settings and standardise these. These values are compared with reported and estimated production volumes of H2 per year that would be necessary to make a deposit economically viable. This contribution attempts to estimate the order of magnitude of a deposit that would be required for relevant, economic extraction of natural hydrogen.

Natural hydrogen (H2) is increasingly discussed as a potential contributor to a future sustainable energy system. We present the results of the first comprehensive soil gas survey targeting natural hydrogen seepage in Northern Bavaria, Germany. Our study focuses on three major fault zones: the Franconian Line, the Heustreu Fault Zone and the Staffelstein Fault, and investigates their role as potential migration pathways for natural hydrogen.

From 303 soil gas measurements, we identified several hydrogen hotspots with concentrations exceeding 1000 ppm at 1 metre depth. These anomalies show spatial correlations with known fault structures and reveal a heterogeneous hydrogen distribution, suggesting that only hydraulically active fault segments serve as effective conduits. Elevated hydrogen levels at distances from mapped fault traces may indicate lateral migration within aquifers or the influence of unmapped or inclined faults.

Although we considered potential hydrogen source rocks such as serpentinites and radiogenic granites, our findings suggest that structural permeability plays a more dominant role than proximity to source rocks. Weak correlations between hydrogen and carbon dioxide, along with a strong land use effect on CO2, confirm that CO2 is not a reliable hydrogen proxy. Low methane concentrations and noble gas measurements support a geogenic rather than microbial hydrogen origin.

Our results demonstrate the area’s considerable potential for natural hydrogen exploration and highlight the need for further research. Such research should include hydrogeological investigations, soil gas surveys and geophysical studies to better understand the extent, origin, migration pathways and flux rates of natural hydrogen in the region.