Understanding the geomechanical behaviour of gas storage reservoirs and caprocks is critical for safe and secure storage, whether that be for hydrogen, CO 2 or natural gas. While large-scale natural gas storage has been practiced since 1915, storing new gas mixtures, particularly hydrogen with repeated injection–extraction cycles, demands renewed geomechanical analysis. One example of this is the Rough Field in the UK, being redeveloped for hydrogen storage, which lacks geomechanical assessment of the reservoir and caprock performance under proposed storage pressures. This study models fracture pressure across the Rough Field and surrounding basin, evaluates the mechanical response to fluid injection at reservoir-scale, and investigates fluid flow and leakage along bounding faults through a multi-scale geomechanical modelling approach. Basin-scale results show that fracture pressure varies spatially, with a maximum value of 2.5 MPa above pre-production reservoir pressure, indicating that fracture would occur under injection pressures exceeding this. Reservoir-scale modelling identifies the weakest zones (first to fracture) at reservoir edges where bounding faults intersect the reservoir. Fluid flow modelling demonstrates how pressure changes drive fluid flow along permeable faults, with implications for permeability evolution, leakage, and fault stability. This helps predict how pressure changes affect permeability and fault stability, guiding subsurface storage plans. By identifying the fracture pressures and the potential weakest zones in the reservoir and caprock, this study could be used to inform operational limits for injection pressures, reducing the risk of unintended fracturing or leakage. This methodology, although chosen here to investigate hydrogen storage, could be applied to other geological storage projects (CO 2 , or mixed gases), enabling more confident deployment of subsurface energy storage infrastructure.
Brown et al. (Wed,) studied this question.