Abstract Understanding CO2 nanobubble formation in water‐saturated sandstone is critical for understanding fluid behavior in CO2 storage systems. Here, CO2 exsolution from an aqueous phase in a sandstone was investigated using small‐angle neutron scattering at 50°C during cyclic depressurization from 12 to 0.7 MPa. Nanoscale heterogeneities consistent with CO2 clusters and nanobubbles (5–200 nm) were resolved during pressure reduction. Although bulk phase diagrams predict exsolution at ∼8 MPa at 50°C, detectable exsolution emerged only at 2.4 MPa, indicating strong confinement and surface effects. A progressive loss of signatures associated with nanobubbles <∼15 nm suggests preferential disappearance of nanobubbles, consistent with curvature‐driven coarsening (e.g., Ostwald ripening). Repeated cycling revealed partial qualitative reversibility, implying nucleation and saturation‐history (hysteresis) effects relevant to operational pressure transients in CO2 storage. Our findings improve assessment of CO2 mobility, trapping, and leakage risk under dynamic pressure in CO2 storage systems.

Flow and transport in fractured geological media are strongly controlled by aperture heterogeneity and uncertainty in subsurface characterisation, yet most upscaling approaches rely on deterministic representations of fracture permeability. This study presents a scalable probabilistic workflow that bridges image-based fracture geometry and uncertainty-aware hydraulic predictions across scales. The approach integrates Bayesian correction of aperture-permeability model misspecification, a deep learning surrogate for predicting spatially distributed permeability statistics, and Darcy-scale flow upscaling to propagate uncertainty to effective transmissivity. The workflow is applied to natural shear fractures from core material in the Little Grand Wash Fault damage zone (Utah) and to simplified geometries derived from the same datasets. The Bayesian component quantifies uncertainty due to measurement errors and imperfect constitutive relations, while a Residual U-Net learns the effects of local heterogeneity and spatial correlation on predicted permeability uncertainty. Together, these components generate ensembles of permeability fields that are subsequently upscaled to probabilistic macroscopic flow responses. Results show that common empirical aperture-permeability relations are systematically biased for natural fractures, whereas the proposed probabilistic workflow yields uncertainty-aware permeability estimates consistent with physics-based behaviour. The method captures the impact of channelisation, connectivity, and complex 3D void geometries on transmissivity while quantifying the resulting uncertainty bounds. Computational efficiency arises from the proposed hybrid strategy for probabilistic upscaling, which combines physics-informed and data-driven approaches, preserves Stokes-flow consistency and supports uncertainty propagation without repeated high-fidelity simulations.

The presence of oxygen impurities in biomethane raises concerns over mineral stability and reservoir integrity during subsurface storage operations. This study evaluates the impact of oxygen on the mineralogical stability of reservoir rocks during subsurface biomethane storage using laboratory batch experiments, complemented by batch reactive modelling to interpret short-term behaviour and explore longer-term re-equilibration trends. Two geologically distinct reservoir samples, representing sandstone and marlstone formations, were subjected to controlled oxygen-brine-rock interactions under reservoir-relevant conditions. Geochemical analyses show minor alterations in fluid composition and minimal mineralogical changes that primarily involve slight variations in clay and carbonate mineral phases. Batch modelling further supports these findings, demonstrating limited mineral dissolution and precipitation reactions over both short- and long-term scenarios. A key aspect of this study is the direct comparison between oxygen- and nitrogen-exposed systems under matched conditions, which allows oxygen-specific geochemical effects to be isolated from generic gas-brine-rock interactions. Overall, the results indicate that oxygen impurities at typical biomethane concentrations are unlikely to cause significant formation damage, providing valuable insights for setting oxygen tolerance limits in subsurface biomethane storage operations. This study contributes to the broader understanding of subsurface geochemical processes relevant to energy storage. Further studies are nevertheless required, involving longer-term experiments and reactive transport modelling, while taking microbial activity into account.

To enable hydrogen (H2) to substantially contribute to the energy transition, a better understanding of the efficacy of large-scale underground hydrogen storage (UHS) is needed. Storage options in porous rocks such as reservoirs and saline aquifers offer the largest potential by volume. However, sandstone reservoirs are typically characterised by different degrees of heterogeneity that affect storage. Heterogeneities include deformation bands, often found in well-sorted aeolian sandstone with good UHS potential. Deformation bands are planar, low-permeability features that can develop through grainsize reduction and fusing in response to changes in stress. Little is known about the effect of heterogeneities on the injection, storage and recovery of H2. Therefore, this study examines the effect of permeability contrasts caused by deformation bands on UHS. To do this we undertake two cycles of H2 injection and production in a two-phase (H2-brine) flow experiment on a Sherwood Sandstone sample containing a deformation band at 50 degrees C and 10 MPa in an X-ray micro Computed Tomography scanner. In addition, we repeat the experiment with helium to further evaluate effects of the permeability contrasts and understand whether helium can be a useful proxy for H2 in laboratory-based experiments. The results show that the deformation band analysed is a baffle to flow, increasing the required injection pressure for gas transit, and there are few pathways for H2 across it. In the first cycle very little H2 is trapped below and in the deformation band. But when the pathways become blocked during imbibition, due to brine snap off, there is a substantial increase in H2 trapping, reducing H2 flow and production. We also see trapping of H2 in larger pores and post injection movement of H2. Both processes exhibit similar characteristics, with H2 occupying the pore centres and brine on the rock surfaces. Our observations will assist in understanding processes within UHS reservoirs and enable strategies to be developed to deal with fluid movement and pressure changes resulting from permeability contrasts. There are many similarities in the behaviour of H2 and helium in our experiment, confirming our observations with H2. As such, we find that helium can be used as a proxy in these conditions, although adjustments may need to be made for the viscosity differences.

The comparison between laboratory-induced and subsurface fractures, and their corresponding flow is still unclear. Here, we examine three natural shear fractures and two induced tensile fractures from the same low-permeability lithology. Using high-resolution synchrotron imaging, we extracted three-dimensional fracture void geometries to analyse aperture distributions, surface roughness, and spatial correlation patterns. We then compared measured fracture transmissivities against theoretical predictions from parallel-plate models (cubic law) and direct numerical simulations (DNS) of flow to evaluate consistency and uncertainties. We find that despite differences in heterogeneity, induced tensile and natural shear fractures can generally yield similar flow in caprocks. Our comparisons further indicate that the choice of flow estimation method can introduce more uncertainty than the fracture opening mode.

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.

Secure subsurface storage is a cornerstone of future low-carbon energy systems, with Carbon Capture and Storage (CCS) playing a central role in long-term greenhouse gas mitigation. The effectiveness of CCS depends on the ability of caprocks to act as durable sealing barriers that prevent buoyant CO₂ migration over geological timescales (>10⁴ years). Despite their importance, significant uncertainty remains in quantifying the sealing capacity of shale and mudstone caprocks, largely due to challenges in characterising their low porosity and nanoDarcy-scale permeability.Mineralogical analyses show that the studied caprocks are dominated by clay minerals, primarily illite–smectite and kaolinite, with subordinate quartz. This mineralogical composition results in complex pore systems dominated by micro- to nano-scale pores and a high proportion of bound fluids, posing challenges for conventional petrophysical characterisation. Accurate assessment of porosity and permeability is therefore critical for evaluating seal integrity. Conventional laboratory techniques, including Helium Pycnometry, Mercury Intrusion Porosimetry (MIP), and Brunauer–Emmett–Teller (BET) analysis, provide valuable quantitative data and serve as calibration and validation references. However, these methods are often limited by sample preparation effects, incomplete representation of pore connectivity, and measurements conducted under non-representative stress and fluid conditions, highlighting the need for complementary non-destructive approaches.Nuclear Magnetic Resonance (NMR) has been widely applied in reservoir rock characterisation due to its ability to resolve pore size distribution, porosity, and fluid behaviour. Its application to caprocks, however, remains limited because standard NMR workflows developed for sandstones and carbonates often yield inconsistent results in clay-rich, low-porosity formations. This study evaluates the applicability of NMR for caprock characterisation and develops caprock-specific workflows suitable for CCS seal assessment.Sample selection focused on primary shale seals overlying reservoirs identified as potential CO₂ storage targets in the Malay Basin, offshore Peninsular Malaysia. The main target intervals comprise Groups B, D, and E from four fields hosting major developed reservoirs. Low-field NMR measurements were conducted using tailored protocols that account for low porosity, complex pore geometry, and clay-related effects. Mineral oil saturation was evaluated as a non-reactive alternative to brine and was found to provide more stable and repeatable porosity measurements by minimising clay swelling and chemical alteration.NMR-derived porosity shows good agreement with conventional laboratory measurements. Analysis of T₂ relaxation distributions indicates that pore systems are dominated by bound fluid components, consistent with limited pore connectivity and strong capillary sealing behaviour. By integrating NMR with conventional petrophysical data, this work builds a high-resolution database of shale properties, reduces uncertainty in caprock seal performance, and supports safe and reliable CCS storage design. The outcomes are directly relevant to offshore Peninsular Malaysia and contribute to national energy transition and climate objectives.

The transition to sustainable energy systems introduces a complex landscape, wherein geothermal energy and carbon dioxide storage (CCS) play critical roles. These activities target geological formations that are always faulted and fractured. As the focus intensifies on alternative energy systems for decarbonisation, understanding these faulted rocks in the subsurface gains great importance. Fault and fracture systems can act not only as conduits for fluid flow but they can also be zones of mechanical weakness that may respond dynamically to fluid pressure changes due to natural geological processes or anthropogenic activities, such as CCS or geothermal extraction. This dual role of fault and fracture systems as pathways for fluid flow and as potential triggers for mechanical failure makes their study a cornerstone of sustainable subsurface resource management. The challenge lies in accurately characterising the permeability of these systems and estimating their mechanical behaviour under changing stress conditions. This is vital for ensuring the integrity and efficacy of operations like CCS and geothermal energy extraction, where even slight variations in fluid pressure can have significant implications. For instance, experiences from the fluid injection experiment for an enhanced geothermal system in Basel, Switzerland, and the In Salah CCS pilot site in Algeria highlight how minor changes in pore fluid pressures (as little as 10 MPa) can induce leakage and/or seismic activities. We highlight selected case studies from both active and prospective CCS and geothermal sites (in Svalbard and Mid-Ethiopian Ridge, respectively). These examples illustrate methodologies in fault stability analysis and geomechanical characterization, shedding light on the relationship between fluid flow, stress alterations, and rock mechanics in faulted and fractured formations. By coupling empirical data with modelling techniques, we present strategies to mitigate risks and enhance the efficiency of subsurface decarbonisation efforts.

To better understand how cyclic effective stress variations affect the mechanical and transport properties of reservoir rocks during underground hydrogen storage (UHS), this study conducted proportional loading experiments on three porous sandstones varying in porosity and permeability. Proportional loading experiments were conducted under different stress paths, simulating variations in effective stress caused by cyclic UHS. Mechanical properties, porosity, and permeability were evaluated based on the mean effective stress and the number of loading cycles. Scanning electron microscopy (SEM) analysis provided insights into the microscopic deformation processes responsible for observed macroscopic behaviours. Results indicate distinct deformation mechanisms influenced by stress paths. Under cyclic triaxial loading conditions (K = 0), high-porosity sandstones initially exhibit compaction but transition to dilatancy-dominated deformation, characterised by microcrack development and grain rearrangement. This dilatancy behaviour paradoxically results in a negative correlation between porosity and permeability. This phenomenon arises because fragmented grains obstruct pore throats, modifying the pore structure and causing localised variations in porosity distribution, which in turn adversely impacts permeability. Conversely, the low-porosity sandstone consistently exhibits compaction-driven deformation, with porosity loss closely correlating with permeability reduction. Under cyclic proportional loading conditions (K > 0), all sandstones exhibit predominant compaction, particularly under repeated cyclic loading. The mechanical and transport properties initially evolve mainly with increasing mean effective stress irrespective of stress paths. However, during cyclic loading, both bulk and pore compressibilities significantly depend on the applied stress paths, becoming notably larger at higher stress path values. Consequently, greater accumulations of inelastic strain and subsequent porosity and permeability loss occur under elevated stress path conditions. SEM observations revealed that these inelastic strains predominantly originate from grain fracturing, contact wear, and compaction or consolidation of clay-rich grain boundaries under cyclic loading. Furthermore, permeability evolution across all samples follows an exponential decay trend, emphasising the cumulative impact of cyclic loading-induced microstructural changes. These findings elucidate critical process-driven mechanisms governing mechanical and transport property evolution in reservoir rocks under cyclic stress conditions, thereby informing the design and operational safety assessments of underground hydrogen storage facilities.

The development of hydrocarbon fields with high CO₂ content requires the integration of Carbon Capture and Storage (CCS) technologies, in alignment with national regulatory frameworks in Malaysia that prohibit CO₂ venting as part of greenhouse gas reduction strategies. Within offshore Peninsular Malaysia (PM), multiple geological storage options have been identified, including depleted hydrocarbon fields and deep saline aquifers. However, preliminary storage capacity assessments indicate that depleted fields alone are insufficient to accommodate the projected volumes of CO₂ from current and future high-CO₂ field developments. Consequently, saline aquifers represent a critical additional storage option, offering the potential to expand long-term capacity for large-scale CCS implementation. The primary objective of this study is to assess the potential of saline aquifers within the Malay Basin as secure geological storage sites for CO₂. This assessment involves a detailed evaluation of core descriptions, facies groupings, depositional environment distributions, and the associated sealing and storage properties characterization. These analyses are essential for delineating the continuity, heterogeneity, and regional distribution of seal and storage intervals. The findings are intended to provide a systematic framework for evaluating the feasibility of long-term CO₂ containment in saline aquifers, thereby supporting regional-scale CCS deployment in the Malay Basin. A comprehensive basin-scale investigation was undertaken to identify prospective aquifer systems and define potential seal and storage intervals within the stratigraphic succession. Regionally, the stratigraphic framework from Groups M/N/O to A/B records a progressive depositional shift from dominantly non-marine environments, including upper and lower coastal plain settings during the Oligocene synrift phase, towards increasingly tidal, estuarine, and marine environments through the Miocene to Pliocene. Within Group E, the central Malay Basin hosts multiple storage-prone intervals characterized by significant thickness, lower VClay values, and relatively higher porosity, deposited in a range of lower coastal plain, lacustrine, estuarine, and tidal settings. In contrast, the northwestern and eastern parts of the basin are characterized by various thickness successions with higher VClay and lower porosity, indicating enhanced sealing potential in these regions. The identification of saline aquifers with both storage and sealing capacity in the Malay Basin provides an opportunity to establish a regional CCS hub that could serve as a benchmark for future projects worldwide. Unlocking these storage sites not only enables the continued development of high-CO₂ hydrocarbon resources but also contributes to Malaysia’s aspiration of achieving net-zero carbon emissions aspiration. Beyond national benefits, this study highlights technological and methodological advancements that may serve as a global reference for optimizing CCS deployment, offering a scalable framework for both regional and international applications.

The natural occurrence of carbon dioxide in subsurface reservoirs is proof of concept that it can be securely stored over geological timescales. Gas accumulations naturally enriched in CO 2 were identified in the East Irish Sea Basin, and their origin was evaluated using a large well and geophysical database. Legacy petroleum fluid samples indicate that CO 2 is regionally negligible, except within the proximal North Morecambe and Rhyl gas fields in the northern basin. Despite relatively elevated ionic concentrations within the northern basin, interpretations of CO 2 dissolution from formation water samples are not conclusive due to widespread contamination. Geochemical measurements of Carboniferous coal and shale samples indicate that units are typically mature and are lacking any further generative potential. While the accumulated CO 2 may have been generated from Carboniferous limestones or formerly organic-rich units, this is likely to have been limited based on their burial history and widespread extent compared to the local present-day distribution of CO 2 . Instead, thick and densely spaced Paleogene igneous dykes were mapped near the Rhyl Field. Despite being the most likely origin, igneous intrusions are interpreted across the northern basin and near several accumulations that lack CO 2 , suggesting that other geological elements have influenced its contemporary distribution, such as the cap rock or migration.

Structural uncertainties and unresolved features in fault zones hinder the assessment of leakage risks in subsurface CO2 storage. Understanding multi-scale uncertainties in fracture network conductivity is crucial for mitigating risks and reliably modelling upscaled fault leakage rates. Conventional models, such as the Cubic Law, which is based on mechanical aperture measurements, often neglect fracture roughness, leading to model misspecifications and inaccurate conductivity estimates. Here, we develop a physics-informed, AI-driven correction of these model misspecifications by automatically integrating roughness effects and small-scale structural uncertainties. Using Bayesian inference combined with data-driven and geometric corrections, we reconstruct local hydraulic aperture fields that reliably estimate fracture conductivities. By leveraging interactions across scales, we improve upon traditional empirical corrections and provide a framework for propagating uncertainties from individual fractures to network scales. Our approach thereby supports robust calibration of conductivity ranges for fault leakage sensitivity analyses, offering a scalable solution for subsurface risk assessment.

During underground hydrogen storage (UHS) operations, reservoir rocks often experience time-dependent deformation under long-term stress, which can alter the microstructure and subsequently affect the stability and hydrogen storage efficiency. Therefore, understanding and predicting these time-dependent deformation of reservoir rocks under in situ conditions and its impact on rock properties are crucial for ensuring the long-term safe operations of UHS. This study investigates the time-dependent mechanical and transport behaviour of three representative porous sandstones-St Bees, Castlegate, and Zigong-through constant stress (creep) and multilevel stress creep experiments. These tests were designed to simulate the in situ conditions (1.3-2.6 km depth) of the underground hydrogen storage process at a laboratory scale. In the constant stress experiments, permeability and porosity were measured concurrently to reveal the impact of time-dependent deformation on the transport properties of porous sandstones. In the multi-level stress creep tests, long-term pore pressure cycling was applied to simulate hydrogen injection and withdrawal, and the results were compared with those from experiments under constant pore pressure. This allowed for a systematic assessment of the influence of pore pressure fluctuations on the mechanical response and transport characteristics of the sandstones. The research results indicate that all three sandstones exhibit stable creep behaviour, with the steady-state creep rate increasing as temperature and stress increased. The high-porosity St Bees and Castlegate Sandstones show higher steady-state creep rates under the same conditions compared to the low-porosity Zigong Sandstone. The creep behaviours of the three sandstones under in situ conditions can be well described by Burgers model. The permeability of the three sandstones gradually decreased during the experiments, and this trend become more obvious as the stress and temperature increases. Microstructural analysis reveals that the deformation mechanism of the high-porosity St Bees Sandstone is dominated by dilatancy. Although shear-induced deformation causes the feldspar and quartz clusters to fracture, creating new voids and increasing the overall porosity, the fractured debris from these clusters block the throats, complicating the pore structure and leading to a significant permeability loss. The deformation mechanisms of Castlegate and Zigong Sandstone, on the other hand, are dominated by compaction, with pore compression and microcrack closure being the primary causes of porosity, permeability losses. Pore pressure cycling increases the creep rate of sandstones, accumulating more inelastic strain especially in St Bees Sandstone, but has limited effect on the properties of Castlegate and Zigong Sandstones.

In underground hydrogen storage operations, reservoir rocks often experience periodic pore pressure fluctuations due to annual or more frequent gas extraction and injection cycles. These fluctuations subject the reservoir rocks to cyclic effective stress changes, causing their mechanical and transport behaviors to differ from those under static conditions. However, understanding how porous rocks react to cyclic loading conditions is still limited. To bridge previous research gaps, cyclic loading tests were conducted on Castlegate and St Bees Sandstone, with applied stress amplitudes ranging from 70 to 90% of their monotonic peak strength. This experimental approach was designed to replicate the in situ stress conditions experienced by reservoir rocks during gas operations. Concurrently, we utilised the steady-state method to measure permeability changes under cyclic loading. By comparing the micro-CT features of the sandstones before and after cyclic loading tests, we quantitatively analysed the microscopic mechanisms driving these alterations in sandstone samples. Our results show that under cyclic loading conditions, the inelastic axial strain and Young’s Modulus initially increase for both sandstones, with the most significant changes occurring within the 1st cycle, followed by a trend towards stability. Permeability decreases with increasing stress and loading cycles. For the Castlegate Sandstone, elevated confining pressure intensified permeability loss, while in St Bees Sandstone, high confining pressure resulted in less permeability loss compared to low confining pressure, which was related to shear band development. Microstructural analysis showed grain movement, rotation, and rearrangement in Castlegate Sandstone under external forces, leading to pore/throat compression and reduced porosity/permeability. In contrast, St Bees Sandstone microstructure changes under low stress involved grain cracking from shear dilatancy, increasing porosity but blocking throats, complicating pore structure, then reducing permeability. Under high confining pressure, the strength of St Bees Sandstone rose without sufficient differential stress for shear dilatancy. Decreased permeability and pore volume were linked to compaction-dominated deformation.

We investigate the evolution of poro-mechanical, transport properties and strength characteristics of different sandstones during the cyclic underground hydrogen storage (UHS). Therefore, we selected three different types of sandstones: fine-grained St Bees (∅ =19~22%), coarse-grained Castlegate (∅=18~20%), and coarse-grained Zigong (∅=7~11%). These sandstones exhibit significant porosity, grain size, and mineralogical differences. The samples were imaged using micro-CT to characterise their initial microstructure and then subjected to cyclic loading experiments under hydrostatic as well as various deviatoric stress paths. The aim is to simulate the in-situ stress during cyclic UHS at depths of ~1.5-3km. The permeability of the samples was measured at different stress points. After completing the cyclic loading tests, we performed repeat micro-CT characterization as well as scanning electron microscopy (SEM) analysis to record the permanent changes in the microstructure caused by the stress cycles. The experimental results show that at shallower depths (low-stress state), the high porosity Castlegate sandstone (∅=18~20%) and the St Bees sandstone (∅=19~22%) exhibit an increase in elastic modulus during the tests, experiencing strain hardening due to compaction. The permeability of both sandstones decreases with an increase in mean stress, independent of the stress path. The fine-grained St Bees sandstone shows more significant accumulative inelastic strain and higher permeability loss than the coarse-grained Castlegate sandstone at the same stress state. In contrast, the low-porosity Zigong sandstone (∅=7~11%) shows no significant changes in mechanical properties, and its permeability loss is related to the closure of the initial microcracks. At greater depths (high-stress conditions), the mechanical and transport properties of the fine-grained St Bees sandstone exhibit an evident dependence on the stress path. During stress cycling under deviatoric stress conditions, the rock experienced a noticeable weakening indicated by a reduction in elastic modulus. The porosity of the sandstone decreased by 0.8~1.4% due to the combined effects of compaction and dilatancy, with a permeability loss exceeding 50%. The application of deviatoric stress led to lower permeability than hydrostatic tests conducted under the same mean stress. In contrast, the coarser-grained Castlegate and Zigong sandstones show an insignificant stress path dependence in their mechanical and transport properties. Due to compaction, these sandstones experience increased intergranular contact, leading to reduced porosity, increased elastic modulus, and strain hardening. The lower-porosity Zigong sandstone shows a higher sensitivity of permeability to stress than the higher-porosity Castlegate sandstone, which is related to its more complex pore structure. Microstructural analysis reveals that factors such as porosity, particle size, microfractures, and the presence and distribution of compliant components like clay minerals are the primary causes for the variations in the poro-mechanical and transport properties of the three sandstones under cyclic stress. Therefore, in addition to the depth of the reservoir, grain size (and their distribution) and mineralogical characteristics play a significant role in the selection of hydrogen storage candidates.

The Malay Basin has received significant attention for geological carbon dioxide storage (GCS), but there are no published studies addressing the selection of appropriate deep saline aquifers. This study closes this gap. We process spatial data and use geological modelling and cluster analysis to identify optimal areas for GCS, considering various subsurface characteristics such as temperature, pressure, porosity and thermophysical CO2 properties. It is found that the basin contains numerous Cenozoic aquifers suitable for GCS including locally thick, but low net-to-gross (NTG), stacked formations. Pliocene aquifers are too shallow to offer storage for CO2 in large quantities, but upper Miocene aquifers located in the northwest of the basin contain promising intervals with significant porosities and conditions favouring denser CO2. Middle Miocene aquifers, while low NTG, are thick, and optimally located around the margins of the basin. They also have significant storage capacity and could be developed as a stacked GCS site. Lower Miocene aquifers are higher NTG, but deeply buried across many areas of the basin, yet the oldest aquifer evaluated still holds substantial storage capacity, where subject to minor burial at the margins of the basin. Overall, this study provides a novel first assessment of aquifer GCS potential in the Malay Basin, while also contributing to wider efforts to evolve screening workflows for other geological basins.

Determining the (in)efficiency of wetting phase displacement by an invading non-wetting phase (drainage) in a single fracture is key to modelling upscaled properties such as relative permeability and capillary pressure. These constitutive relationships are fundamental to quantifying the contribution, or lack thereof, of conductive fracture systems to long-term leakage rates. Single-fracture-scale modelling and experimental studies have investigated this process, however, a lack of visualization of drainage in a truly representative sample at sufficient spatial and temporal resolution limits their predictive insights. Here, we used fast synchrotron X-ray tomography to image drainage in a natural geological fracture by capturing consecutive 2.75 μm voxel images with a 1 s scan time. Drainage was conducted under capillary-dominated conditions, where percolation-type patterns are expected. We observe this continuously connected invasion (capillary fingering) only to be valid in local regions with relative roughness, λb ≤ 0.56. Fractal dimension analysis of these invasion patterns strongly aligns with capillary fingering patterns previously reported in low λb fractures and porous media. Connected invasion is prevented from being the dominant invasion mechanism globally due to high aperture heterogeneity, where we observe disconnected invasion (snap-off, fragmented clusters) to be pervasive in local regions where λb ≥ 0.67. Our results indicate that relative roughness has significant control on flow as it influences fluid conductivity, and thus provides an important metric to predict invasion dynamics during slow drainage.

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.

Geological carbon capture and storage (CCS) is a critical technology for mitigating greenhouse gas emissions, but the risk of leakage remains a significant concern. Fault and fracture networks across sealing intervals are potential pathways for CO2 to escape from storage reservoirs, necessitating accurate assessment of their permeability and connectivity. Our study presents an integrated approach for modelling geological leakage in fault zones, combining single fracture stress-permeability laboratory measurements with detailed fracture outcrop data to simulate in-situ conditions for carbon storage. We studied caprock sequences cut by a normal fault in the Konusdalen West area (Svalbard, Norway), a regional seal for the reservoir of the Longyearbyen CO2 Laboratory, and an analogue to Barents and North seas caprock formations. Digitising the outcropping fracture network, we explored the variations in fracture size distribution and their connectivity in different portions of the fault zone. These parameters are fundamental to establish if the fracture network provides permeable pathways. Integrating outcrop analysis with laboratory measurements allows us to create coupled hydromechanical models of the natural fracture network and to evaluate their upscaled permeability. We found that fracture network geometries vary across the fault zone, resulting in different upscaled permeability models, thus highlighting the importance of including detailed fracture network information into permeability simulations. Our study provides a framework for incorporating fracture permeability measurements and outcrop analysis into the modelling of geological leakage in fault zones, which can inform the design and operation of CCS projects and help mitigate the risks associated with geological storage of CO2.