Here we present a case study for using visual stratigraphy to date a shallow firn core from coastal West Antarctica. The Mount Siple ice core has the potential to reconstruct climate in this data-sparse region over recent decades. Line scanned images of the 24 m firn core were used to generate a grey-scale, which displays variability consistent with annual cycles. The resulting Mount Siple age scale spans from 1998 ± 1 to 2017 CE. This study demonstrates that the seasonal changes in the grey-scale record provide an independent method of dating firn cores. However, the presence of melt layers at this site has introduced an error of ±1 year. Visual line stratigraphy has the unique advantage over traditional annual layer counting, based on chemical or isotopic species, of being non-destructive and relatively inexpensive. Visual line stratigraphy has proved to be an effective dating method for this site.

The Rough field in the Southern Permian Basin was originally a producing gas field, later repurposed for natural gas storage and now a target to be the largest hydrogen storage site in the UK. Despite this, few past studies have investigated the facies and mineralogy present in the sandstone reservoir, which is imperative to ascertain its suitability for hydrogen storage. We present new petrographic and facies characterizations of the Permian Leman Sandstone Formation, using core from the Rough field. Our detailed analyses include core logging, SEM-EDX and XRD analyses. This research provides a new reservoir characterization and introduces novel reservoir facies classifications supported by detailed petrography. We identify four facies associations – aeolian, fluvial, sheetflood and floodplain – and find that each facies within the reservoir possesses different minerology. Certain minerals within these facies have the potential to react with hydrogen in some way, causing the potential production of hydrogen sulfide, dissolution and reprecipitation of carbonate minerals and clay mineral transformations. These reactions are dependent on mineralogy and abundance, which varies throughout the mixed heterogeneous facies. After evaluating the petrography and potential mineral reactions, we conclude that the Rough field has potential to be a suitable hydrogen storage site, but there is a level of unpredictability due to the heterolithic nature of the reservoir sandstones. This research highlights the importance of detailed characterization of heterolithic facies that occur in the Lower Permian stratigraphic interval in the Southern North Sea, especially along the western faulted margin. Such characterization is paramount for other sites under consideration for hydrogen storage.

Understanding the geomechanical behaviour of gas storage reservoirs and caprocks is critical for safe and secure storage, whether that be for hydrogen, carbon dioxide 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. 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 weakest zones in the reservoir and caprock, this study informs operational limits for injection pressures, reducing the risk of unintended fracturing or leakage. This methodology can be applied to other geological storage projects (CO2, or mixed gases), enabling more confident deployment of subsurface energy storage infrastructure.