Underground hydrogen storage in porous formations is a promising solution for large-scale energy storage. Understanding hydrogen flow and trapping at the pore-scale is crucial for assessing storage capacity and recovery efficiency. While pore-scale flow visualisation experiments provide realistic insights, they are resource intensive and technically challenging. Pore-network models offer a computationally efficient tool for simulating multiphase flow in porous media and can serve as a valuable complement to pore-scale experiments. However, their accuracy remains a key uncertainty and must be evaluated for future application. This study evaluates the performance of a quasi-static pore-network model by comparing its predictions against three-dimensional pore-scale hydrogen flow visualisation experiments in a homogeneous Bentheimer sandstone and a layered Clashach sandstone. The model was calibrated to match experimental end-state saturations, and its performance was evaluated through comparisons of spatial saturation profiles and pore occupancy. The novelty of this study lies in the direct comparison of hydrogen displacement between pore-scale experimental observations and pore-network model simulations, providing an assessment of model performance under varying degrees of rock heterogeneity relevant to underground hydrogen storage. The pore-network model shows good agreement with experimental observations for the homogeneous rock, particularly during drainage, and is subsequently used to analyse additional scenarios, including cyclic hydrogen injection and withdrawal, and wettability variations. These simulations provide insights into capillary pressure behaviour and residual saturation trends. In contrast, for the heterogeneous and layered Clashach sandstone, the model fails to capture the trapping and fluid redistribution observed experimentally during imbibition, revealing limitations in modelling fine-scale heterogeneity. ... Read more

Hydrogen–water displacement in porous rocks involves capillary-dominated multiphase-flow processes at the pore scale that are critical for understanding fluid distribution, trapping, and recovery behaviour. Three-dimensional pore-scale flow visualisation experiments provide direct insight into these processes but are resource intensive and technically challenging. Pore-network models offer a computationally efficient alternative for simulating capillary-dominated multiphase flow, but their accuracy depends on how well-simplified displacement rules represent real pore-scale behaviour. This work presents a direct pore-by-pore comparison between experimentally observed displacement events and predictions from a quasi-static pore-network model. The comparison enables evaluation of the model’s simplifying assumptions and its ability to reproduce pore-scale displacement behaviour across contrasting rock types, including a homogeneous Bentheimer sandstone and a layered Clashach sandstone. The model was calibrated to match experimental end-state saturations, and its performance was evaluated using spatial saturation distributions and pore-occupancy statistics. The pore-network model shows good agreement with experimental observations for the homogeneous rock, particularly during drainage. It is subsequently used to analyse additional scenarios, including cyclic hydrogen injection and withdrawal and wettability variations, providing insight into capillary pressure behaviour and residual saturation trends. In contrast, for the heterogeneous rock, the model does not fully capture the trapping and fluid redistribution observed experimentally, indicating limitations in representing fine-scale heterogeneity. Overall, the results identify the conditions under which the quasi-static pore-network model can reliably represent hydrogen–water displacement and where its simplifying assumptions become limiting, providing guidance for its application in pore-scale multiphase-flow research. ... Read more

Achieving climate neutrality requires rapid scale-up of CO2 storage to gigatonne scale. Storage clusters—multiple injection sites sharing regional aquifers—offer economic benefits but introduce new challenges in subsurface pressure management. Elevated reservoir pressures can lead to fault slip and leakage, generating environmental and operational risks that span beyond individual license areas. Current site-focused workflows are insufficient for characterizing such cross-boundary effects.

This work introduces the research activities and key ideas of the international research project MuPSI which develops an integrated, multiscale screening and simulation approach to assess geomechanical risks in storage clusters. We present results of a new screening workflow that enables rapid evaluation of pressure interference and fault activation risk across regional aquifers. This is coupled with high-resolution modeling of fault response and new software to bridge region-, project-, and fault-scales. A new highly efficient approach for pressure-stress coupling offers greater software flexibility in geomechanical assessment of individual projects.

The approach is demonstrated using North Sea case studies, including the Horda Platform (Norway) and East Mey (UK). Outputs will support operators and regulators in improving investment decisions, permitting, and cross-license coordination. MuPSI also delivers stakeholder training and knowledge-transfer tools to accelerate adoption of robust, risk-informed storage cluster design. ... Read more

Understanding pore-scale hydrogen displacement and trapping is crucial for developing subsurface hydrogen storage facilities. While pore-scale flow visualization experiments provide critical insights, they are complex and re source-intensive. Quasi-static pore-network models (PNMs) offer a faster alternative for simulating multiphase flow. This study uses a widely employed PNM to simulate hydrogen flow in sandstones, comparing results with pore-scale flow visualization experiments at reservoir conditions.

Two sandstone samples were used: homogeneous Bentheimer and heterogeneous Clashach. Pore networks were extracted comprising pores and throats, and hydrogen-water flow was simulated, modelling drainage and imbibition processes. Results were analysed for fluid saturations and pore occupancies.

For the homogeneous rock, the PNM matches experimental results for both drainage and imbibition, enabling simulations of different wettability conditions and multiple injection and production cycles. For the heterogeneous rock, the PNM reasonably predicts the hydrogen flow path during drainage but fails to accurately predict imbibition. This discrepancy highlights the limitations of PNMs in predicting pore-scale flow in complex rocks.

In conclusion, while PNMs offer a computationally efficient means to simulate hydrogen flow, they cannot currently replace experimental observations for complex rocks. Further validation against experimental findings is necessary to refine these models and expand their applicability for underground hydrogen storage. ... Read more

Subsurface porous rocks hold significant hydrogen (H₂) storage potential to support an H₂-based energy future. Understanding H₂ flow and trapping in subsurface rocks is crucial to reliably evaluate their storage efficiency. In this work, we perform cyclic H₂ flow visualization experiments on a layered rock sample with varying pore and throat sizes. During drainage, H₂ follows a path consisting of large pores and throats, through a low permeability rock layer, substantially reducing H₂ storage capacity. Moreover, due to the rock heterogeneity and depending on the experimental flow strategy, imbibition unexpectedly results in higher H₂ saturation compared to drainage. These results emphasize that small-scale rock heterogeneity, which is often unaccounted for in reservoir-scale models, plays a vital role in H₂ displacement and trapping in subsurface porous media, with implications for efficient storage strategies. ... Read more

Hypothesis

Underground hydrogen (H2) storage is a potentially viable solution for large-scale cyclic H2 storage; however, the behavior of H2 at subsurface pressure and temperature conditions is poorly known. This work investigates if the pore-scale displacement processes in H2-brine systems in a porous sandstone can be sufficiently well defined to enable effective and economic storage operations. In particular, this study investigates trapping, dissolution, and wettability of H2-brine systems at the pore-scale, at conditions that are realistic for subsurface H2 storage.

Experiments

We have performed in situ X-ray imaging during a flow experiment to investigate pore-scale processes during H2 injection and displacement in a brine saturated Bentheimer sandstone sample at temperature and pressure conditions representative of underground reservoirs. Two injection schemes were followed for imbibition: displacement of H2 with H2-equilibrated brine and with non-H2-equilibrated brine. The results from the two cycles were compared with each other.

Findings

The sandstone was found to be wetting to the brine and non-wetting to H2 after both displacement cycles, with average contact angles of 54° and 53°, for H2-equilibrated and non-H2-equilibrated brine, respectively. We also found a higher recovery of H2 (43.1%) when displaced with non-H2-equilibrated brine compared to that of H2-equilibrated brine (31.6%), indicating potential dissolution of H2 in the unequilibrated, imbibing brine at reservoir conditions. Our results suggest that underground H2 storage may indeed be a suitable strategy for energy storage, but considerable further research is needed to fully comprehend the pore-scale interactions at reservoir conditions. ... Read more