Salt domes are increasingly recognized as strategic assets for the energy transition, serving not only in hydrocarbon exploration but also in sustainable applications such as hydrogen storage and CO₂ sequestration. In alignment with the UAE’s sustainability and decarbonization goals, the Infra-Cambrian Hormuz Salt domes represent promising targets for subsurface storage. However, a critical challenge is that the limited knowledge of their internal architecture constrains assessments of cavern feasibility and long-term containment integrity. This study integrates data from three wells and 3D seismic to characterize the Jebel Al Dhanna salt dome—the only emergent salt dome onshore UAE—and its inclusions. Lithological analysis indicates that over half of the drilled interval consists of massive halite, indicating laterally extensive zones suitable for cavern development. Both sedimentary and igneous inclusions are present, with thicknesses ranging from 1 to 193 m. Inclusions thicker than the ~40 m vertical seismic resolution generate strong reflections, allowing the mapping of 52 features up to 40 m thick and laterally continuous for tens of meters to over 1 km. Synthetic seismograms and core photographs confirm excellent well–seismic correlation. Three-dimensional models indicate that inclusions cluster in the upper 1.35 km of the dome, particularly along its eastern, western, and central sectors. Although halite forms the dome framework, non-halite inclusions exhibit strong spatial heterogeneity, reflecting variable source contributions and entrainment histories. These findings document a plug-shaped salt stock with inclusion corridors and large volumes of massive halite, supporting the suitability of Jebel Al Dhanna for future geostorage in the UAE. The integrated workflow and analytical techniques applied in this study provide a practical framework for assessing the internal architecture and storage suitability of other salt domes for hydrogen and CO₂ containment.

How to cite: Ali, M., Alshehhi, H., and Ali, M.: Imaging Inclusions within the Hormuz Salt at Jebel Al Dhanna, United Arab Emirates: Insights into Subsurface Storage, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-7, https://doi.org/10.5194/egusphere-egu26-7, 2026.

EGU26-7

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Basaltic rocks have emerged as promising targets for the geological storage of carbon dioxide (CO₂) due to their global distribution and their capacity to promote mineralization reactions that permanently immobilize CO₂ as stable carbonates. The Early Cretaceous Paraná Magmatic Province (PMP), one of the largest continental igneous events on Earth, comprises extensive basaltic flows and intrusive bodies (dikes and sills) known as the Serra Geral Group in Brazil. In addition to lava flows, intrusive rocks emplaced along the sedimentary sequence may act as effective caprocks, playing a crucial role in reactive CO₂ storage systems. In southern Brazil, several studies have identified the Upper Permian Rio Bonito Formation (RBF), in the Paraná Basin, as a suitable siliciclastic saline-aquifer reservoir for CO₂ along the Torres Trough (TT). This formation is intruded by multiple basaltic bodies, whose geological and petrological characterization can provide key insights into their suitability as sealing units within a CO₂ storage system. In this context, this study aims to characterize the petrographic and geochemical features of basaltic intrusive bodies hosted in the RBF using analog outcrops from the Criciúma region. These exposures, when integrated with subsurface data from stratigraphic wells in the TT, provide a robust basis for understanding the geometry and extension of such bodies. The integrated analysis of RBF characteristics together with basaltic intrusions is innovative and seeks to build a holistic understanding of the reservoir–seal system for CO₂ storage. The methodology combines detailed geological mapping of the basaltic rocks, petrographic analysis with whole-rock geochemistry. Major and minor oxides were determined by X-ray fluorescence (XRF), whereas trace and rare earth elements were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES). The geological data points to the occurrence of expressive sills and rare dikes. Petrographic descriptions focused on quantifying mineral and alteration phases, textures, and mineral compositions that influence rock reactivity with injected CO₂. Preliminary results reveal a mineral assemblage dominated by calcic plagioclase, augite, opaque minerals, and apatite, with intergranular and micrographic mesostasis. These mineral phases are known for their high reactivity in mineral carbonation processes, particularly in basaltic systems subjected to pressure-temperature conditions compatible with geological CO₂ storage, such as those in the TT. Moreover, the variable degrees of alteration observed among samples suggest heterogeneities in permeability and porosity, critical parameters for understanding fluid-flow dynamics and carbonate precipitation in the subsurface. The results contribute to identifying key features necessary to evaluate the potential of basaltic sills as sealing units. This study thus represents an initial step in the characterization of basaltic rocks intruding the RBF and highlights the importance of integrating geology, petrography, geochemistry, and experimental approach to support carbon capture, utilization, and storage (CCUS) strategies in the context of climate change mitigation.

How to cite: Fontoura, G., Florisbal, L., Waichel, B., Bállico, M., Osako, L., Manna, M., Maccari, G., and Filho, C.: Assessing basaltic intrusive rocks as caprock candidates for CO₂ geological storage: Insights from the Rio Bonito Formation, Paraná Basin, Brazil, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-342, https://doi.org/10.5194/egusphere-egu26-342, 2026.

EGU26-342

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Carbon Capture and Storage (CCS) has become a crucial climate change mitigation strategy aimed at reducing net anthropogenic greenhouse gas emissions through the capture, transport, and permanent subsurface storage of CO₂ from industrial sources or directly from the atmosphere. Its expanding role underscores the importance of identifying geologically suitable regions for future carbon storage. The Grand Banks region offshore eastern Canada remains underexplored for CCS despite its proximity to major CO₂ sources, favourable geological formations, and existing offshore infrastructure that could be repurposed. However, the region’s tectonic activity, seismic history, and structural complexity necessitate detailed assessments to ensure secure CO₂ injection and long-term storage.

In this study, we evaluate CCS feasibility in the offshore Grand Banks region of Newfoundland, Canada using two-dimensional (2D) seismic reflection data, structural analysis, and numerical modeling. The objectives are to: 1) identify prospective CCS sites, 2) build a regional structural and fault framework, 3) investigate structural relationships between fault networks and salt structures, and 4) establish safe CO₂ injection thresholds that minimize the risk of induced seismicity. Seismic profiles southwest of Newfoundland were interpreted using Petrel™ Schlumberger software to characterize the stratigraphic sequences, fault networks, and the geometry and distribution of salt structures. These interpretations were then integrated into the Petex™ MOVE suite to conduct fault and stress analyses on the regional structural fabric. The resulting interpretation and structural model, combined with logistical constraints like offshore distance and existing well infrastructure, facilitated the identification of candidate CCS sites and optimal injection locations. Geological parameters derived from seismic interpretation, including fault geometry and salt distribution, and reservoir porosity and permeability, were incorporated to assess storage integrity under multiple injection scenarios and define safe operational thresholds that minimize risks of induced seismicity and CO₂ leakage. Numerical simulations were conducted to evaluate CO₂ injection and migration behaviour within candidate reservoir-caprock pairs, highlighting leakage pathways and geomechanical responses of faults and caprocks to pressure changes.

Our results reveal two dominant normal fault sets trending N-S and E-W, closely associated with various salt structures that play a crucial role in shaping the region’s subsurface architecture. The spatial correlation between the fault systems and salt distribution indicates their coupled evolution during Mesozoic rifting events and highlights a complex yet strategically favourable setting in which faults may act as either barriers or conduits to fluid flow, while certain salt bodies influence structural trapping efficiency.

By providing foundational geoscientific assessments of the subsurface conditions, these findings advance understanding of CCS integration into the region’s energy infrastructure. This study introduces a multidisciplinary approach that provides a comprehensive framework for evaluating CCS potential in tectonically complex offshore settings and offers transferable insights for CCS deployment in similar geological environments worldwide, supporting climate change mitigation efforts and informed sustainable energy transition planning.

How to cite: Devries, J., Peace, A., and Awolayo, A.: Feasibility assessment of carbon sequestration in the Grand Banks, offshore Newfoundland, Canada, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-770, https://doi.org/10.5194/egusphere-egu26-770, 2026.

EGU26-770

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Underground hydrogen storage (UHS) is a key opportunity in the transition to sustainable energy economy as it addresses the challenge of intermittent renewable energy production. However, a better understanding of the pore scale processes in the rock-porewater-hydrogen system is crucial for secure UHS. To address these geochemistry-related questions, the interaction between quartz and hydrogen gas was investigated in this study. Quartz is a major constituent of siliciclastic rocks, therefore for the batch experiment two types of quartz grains were used: the grains of a natural, inclusion free quartz crystal and quartz grains separated by hand picking from a typical reservoir sandstone of the Carpathian-Pannonian region. Batch experiments combined with geochemical modeling (PHREEQC) were carried out to match the experimental results.

For the batch experiments, 2 g of quartz and 70 ml of deionized water were mixed in a reactor vessel. The experiments were conducted under varying pressures (50–100 bar) and temperatures (80–100 °C), corresponding to the expected conditions for underground hydrogen storage. Throughout the 72-hour experiments, the chemical composition of the solution was monitored through sampling and analyzed by inductively coupled plasma optical emission spectrometry (ICP-OES). Quartz grains were examined before and after the experiments via scanning electron microscope (SEM-BSE) and Fourier-transform infrared spectroscopy (FTIR) to observe any effect of dissolution or surface alteration on the quartz grains. Reference experiments were conducted with helium gas under the same p-T conditions.

Results show that quartz reactivity with hydrogen remained quite low in all experimental runs. The pH displayed considerable increase during some of the experimental runs, which was unforeseen in the geochemical models. Quartz solubility was found to be primarily pH-dependent, as reflected by Si concentrations in solution samples from experiments. Lower solubility (~2 mg/l) was observed in acidic and neutral pH ranges, whereas somewhat higher solubility (~6 mg/l) was observed under alkaline conditions. Silanol groups on the surface of the powdered quartz grains, confirmed by FTIR, may have contributed to the observed increase in pH and enhanced quartz solubility, and should be accounted for the geochemical models.

In the experiment, involving quartz grains from the sandstone reservoir, significantly higher dissolved Si concentrations were measured compared to the experiments with pure quartz under the same conditions. This difference was likely due to the dissolution of other rock forming minerals (e.g., kaolinite) remaining in trace amounts on the surface of the grains despite careful preparation.

In conclusion, quartz is a less reactive mineral under the typical pressure and temperature conditions of subsurface hydrogen storage, therefore quartz dominant rocks seem to be favorable for future hydrogen storage. Further study of silanol behavior and its integration into geochemical modeling may enhance the accuracy of future predictions.

How to cite: Horvath, L., Kővágó, Á., Cseresznyés, D., Szabó, C., Gelencsér, O., Breitner, D., and Falus, G.: Geochemical Investigation of the Hydrogen Gas – Quartz – Porewater System for Understanding Underground Hydrogen Storage in Siliciclastic Reservoirs , EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-1170, https://doi.org/10.5194/egusphere-egu26-1170, 2026.

EGU26-1170

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Identifying reliable and scalable offshore CO₂ storage sites requires systematic workflows that connect geological screening with project maturity assessment. In this study, we present a nine-stage evaluation framework that integrates Storage Readiness Levels (SRL), deterministic filtering, Common Risk Segment (CRS) analysis, semi-quantitative scoring, and milestone-based maturity tracking into a unified methodology. The approach is implemented in a modular Excel platform designed to ensure transparency, reproducibility, and applicability across variable data conditions. We applied this framework to major offshore basins surrounding the Korean Peninsula, including the Yellow Sea, South Sea, and East Sea. Initial screening (SRL1–2) identified four basins with adequate depth, sealing systems, and storage potential. CRS-based risk classification (SRL3) narrowed candidates to the Eastern Gunsan Basin (EGB) and the southwestern Ulleung Basin shelf (SWSUB). Quantitative scoring and structure-scale analysis (SRL4) further differentiated prospects within the SWSUB, where six Miocene prospects advanced to SRL5 due to robust seismic–well control and 3D geologic modeling. Among them, one depleted gas field demonstrates conditional SRL6 maturity supported by dynamic simulation results but requires additional geomechanical and monitoring design. The case study reveals significant variability in basin maturity and highlights key data gaps limiting site progression. More broadly, the SRL-based workflow provides a practical path for harmonizing site screening, risk evaluation, and readiness assessment—offering a transferable tool for offshore CCS planning in regions with heterogeneous datasets. This work demonstrates that structured readiness frameworks can accelerate identification of high-potential CO₂ storage opportunities and improve communication with regulatory and industrial stakeholders.

How to cite: Kim, K., Kim, T.-W., Yoon, B., and Nugraha, H. D.: A multi-stage SRL-based framework for offshore CO2 storage assessment: Application to the Korean continental shelf, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-1770, https://doi.org/10.5194/egusphere-egu26-1770, 2026.

EGU26-1770

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The Kvartsevoe rare metal deposit in East Kazakhstan was discovered in 1967 and is being currently re-evaluated after decades of inactivity. The geology of the area consists mainly of Devonian to Carboniferous metasediments, folded during the latest consolidation phase of the Altai orogen (i.e. Late Carboniferous-Permian) and intruded by series of post-kinematic Permian granites. Metals and elements of economic interest, in particular Lithium, are found in a ~300 m wide and ~700m long pegmatite body, associated with medium-earth biotite granites of phase II of the Kalba complex (i.e. 286±1 Ma). The deposit is represented by a series of pegmatite veins located in one of the projections of the Alypkelsky granite massif, the sedimentary host rocks near the deposit are hornfels of variable metamorphism up to the point of transformation into tourmaline-graphite-quartz-mica hornfels. Numerous quartz veins are found in the close vicinity of the Kvartsevoe deposit. Field observations suggest that the latter veins are genetically linked to the pegmatites. They cross-cut Permian granites and Paleozoic metasediments, show regular trends and typically extend 10s to 100s of metres. We conducted an integrated geochemical-structural study of the veins. Our preliminary results suggest vein emplacement under strike-slip stress regime with NW-SE orientation for the axis of minimum principal stress. The study seems, in addition, to confirm the genetic link between the veins and the pegmatites. Therefore, our findings suggest that the pegmatites were also emplaced under the same stress field. This latter result may be used in the future to predict the orientations of the pegmatites hosting economic metals in the subsurface.

How to cite: Pascal, C., Marina, M., Tatiana, O., Eldar, S., Dastan, T., Oxana, K., and Artem, D.: Paleostress study of the Kvartsevoe rare metals deposit, East Kazakhstan, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-1876, https://doi.org/10.5194/egusphere-egu26-1876, 2026.

EGU26-1876

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The thermal regime of sedimentary basins is jointly shaped by deep lithospheric dynamics and basin-scale tectonic evolution. Investigating these characteristics not only provides critical insights into unraveling tectono-thermal evolutionary trajectories but also plays a pivotal role in regulating hydrocarbon generation, preservation, and phase differentiation. The Permian–Triassic interval in the central Junggar Basin constitutes a key target for hydrocarbon exploration; however, its geothermal attributes remain poorly constrained owing to limited drilling data and significant burial depths. Leveraging borehole temperature logs, rock thermal property measurements, and integrated well log–seismic datasets, this study refines the present-day geothermal characterization of the Permian–Triassic succession and clarifies its regulatory effects on the hydrocarbon system, thereby laying a solid foundation for future exploration endeavors. Key results are as follows: ① Rock thermal conductivity ranges from 1.009 to 3.915 W/(m·K), which is predominantly controlled by lithology and physical properties (conglomerate > sandstone > mudstone) and exhibits a positive correlation with burial depth. Radiogenic heat production varies between 0.312 and 2.238 μW/m³, depending on the abundance of radioactive elements (mudstone > conglomerate > sandstone), and is lower than that in the adjacent Tarim and Qaidam Basins due to differences in provenance. ② Since the Early Permian, the basin has undergone a gradual attenuation of heat flow. The present-day average geothermal gradient and terrestrial heat flow are 20.8 °C/km and 39.6 mW/m², respectively, showing a spatial pattern of being higher in the east-north and lower in the west-south. With the Permian–Triassic burial depth exceeding 5 km, the measured temperatures (125–200 °C) are notably lower than those of extensional basins in eastern China. ③ Predictive modeling reveals a south-to-north thermal attenuation trend. The Fengcheng and Lower Urho Formations (main source rocks) have average bottom temperatures of 173.1 °C and 191.4 °C, respectively, with most intervals entering the high-over mature gas generation stage. The Triassic Karamay and Baikouquan Formations (reservoirs) exhibit lower basal temperatures (145.6 °C and 150.6 °C), remaining within the liquid oil window. The Permian Upper Urho Formation (average basal temperature of 163.2 °C) has experienced extensive oil cracking in the southern part of the basin, which is unfavorable for liquid oil preservation.

How to cite: Su, T. and Liu, H.: Present-Day Geothermal Characteristics of the Permian–Triassic in the Junggar Basin and Implications for Petroleum Geology, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-4484, https://doi.org/10.5194/egusphere-egu26-4484, 2026.

EGU26-4484

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The offshore area of northwestern Taiwan is considered a potential site for carbon capture and storage (CCS). However, the containment integrity—particularly the risk of faults breaching the reservoir–seal system—remains insufficiently constrained. Based on stratigraphic and sedimentological investigations, the Late Miocene Nanchuang and Pliocene Kueichulin formations are identified as the primary reservoir units, effectively sealed by the overlying thick Late Pliocene Chingshui Shale. This study aims to analyze the variation trends of fault displacement and reconstruct the temporal evolution of regional faulting, thereby assessing the resultant seal integrity. We integrated 48 multichannel seismic profiles with data from one exploration well. Fault geometries were delineated by identifying high-density contour zones on isopach maps and verifying them against seismic reflection characteristics. A total of 16 normal faults were identified. Quantitative analysis reveals that the maximum vertical displacements observed within the Chingshui Shale, Kueichulin Formation, and Nanchuang Formation are approximately 0.025 s (~40 m), 0.022 s (~35 m), and 0.020 s (~30 m), respectively. Crucially, the maximum displacement within the regional seal (~40 m) is consistently smaller than the shale’s thickness defined at the well location (~81 m). The results indicate that fault activity was episodic and closely linked to the regional tectonic framework. The initial phase of elevated activity occurred during the Late Oligocene to Early Miocene (Mushan, Daliao, and Shihdi stages), associated with rapid subsidence during the post-rift phase. A subsequent phase of reactivation was observed during the Pliocene to Late Pliocene (Kueichulin and Chingshui Shale stages), corresponding to the foreland basin flexure. Consequently, the insufficient fault throws and the long-term decreasing activity trend imply that seal integrity is preserved, supporting the feasibility of the study area for CCS.

Keywords: offshore northwestern Taiwan, fault activity, multichannel seismic (MCS), carbon capture and storage (CCS), seal integrity.

How to cite: Chen, K.-T., Hsu, H.-H., Wu, P.-R., Chen, Y.-P., Lin, Y.-X., Mirza, A., Lin, Y.-J., and Yao, C.-H.: Assessment of fault activity at offshore carbon storage prospects off northwestern Taiwan, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-6270, https://doi.org/10.5194/egusphere-egu26-6270, 2026.

EGU26-6270

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To attain net-zero aims and mitigate climate change, large-scale carbon capture and geological storage of CO₂ are necessary. Thailand's government aims to reduce CO₂ emissions by 20% by 2030, compared to current levels. This study uses a national-scale GIS-based multi-criteria decision analysis (MCDA) to screen Thailand's lithology and sedimentary basins for CO₂ storage capacity. We ranked geological, hydrogeological, and infrastructure data such as reservoir lithology and thickness, structural stability, formation depth, brine salinity, proximity to CO₂ sources, and surface land use using six criteria. An analytical-hierarchy process (AHP) was used to weight these variables and get a composite appropriateness score for each region. The petroleum basin with Permian carbonate reservoir and the Khorat Plateau with Mesozoic sandstones are the two highest priority regions, according to the findings. These regions combine thick, well-sealed reservoirs with surrounding large emitters. The output prioritizes probable storage sites spatially, taking into account geological capacity, infrastructural, and social variables. This thorough screening approach, which uses the original data layers and figures, creates a reproducible framework for CCS site selection in Thailand and other rising nations.

How to cite: Phantuwongraj, S., Piyaphong, P., Jitmahantakul, S., Assawincharoenkij, T., Thotsaphon, T., and Na Nakorn, D.: A multi-criteria screening evaluation of geological CO2 storage potential in Thailand, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-9028, https://doi.org/10.5194/egusphere-egu26-9028, 2026.

EGU26-9028

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This abstract describes one of the work packages of TUM.GTT´s GeoChaNce.Bayern research project, funded by the Bavarian Environmental Agency. A shallow seismic campaign was conducted near the eastern Bavarian town of Simbach am Inn. The poster will provide an overview of the initial results of the shallow seismic campaign and an outlook on the ongoing work on seismic interpretation in the eastern part of the North Alpine Foreland Basin in Germany.

Deep geothermal energy has the potential to replace fossil-fueled heating in Bavaria. However, an increase in geothermal site construction and, thus, drilling activity is necessary to reach the goal of supplying 25% of the building heat used in Bavaria. Drilling efficiency and safety are often compromised by the subsurface's challenging geological and geomechanical conditions. One critical aspect of ensuring a safe drilling process is mitigating the risk of encountering uncontrolled gas influxes, also known as kicks. To do so, potential gas reservoirs in shallow and deep stratigraphic layers should be identified and mapped prior to drilling. An additional step is to reconstruct the migration history of hydrocarbons from source to surface, in order to understand the likelihood of gas occurrence. Here we integrate newly acquired shallow and legacy deep seismic reflection data, well logs and documented drilling incidents in the Altötting-Simbach area, which represents a shallow and deep gas-prone area in the eastern Bavarian part of the North Alpine Foreland. Comprising a large fault-bounded basement high (Landshut-Neuötting High) and basement trough (Giftthal trough) as well as proven shallow and deep natural gas deposits, makes the Altötting-Simbach area an ideal candidate to study gas migration in the North Alpine Foreland Basin. We will introduce the dataset, initial interpretations, and planned workflows to unravel the gas migration history and provide context for drilling risk mitigation in deep geothermal energy production in the North Alpine Foreland Basin.

How to cite: Breitsameter, J., Aconcha, E., Khalifa, N., Duschl, F., Shatyrbayeva, I., Tveritina, V., and Drews, M.: Investigating gas shows and migration pathways to mitigate drilling risks of deep geothermal wells in Eastern Bavaria, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-9424, https://doi.org/10.5194/egusphere-egu26-9424, 2026.

EGU26-9424

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Green hydrogen is one of the solutions in the European energy transition strategy towards Net Zero, despite the high production costs and associated risks.

Underground hydrogen storage (UHS) can help mitigate energy security issues related to hydrogen production in foreign countries and seasonality of green hydrogen production from renewable wind and solar sources. UHS requires in-depth knowledge of the subsurface and long-term monitoring to minimise the risks associated with hydrogen storage.

Here, we present FUSE (Open Infrastructure on Future Underground Hydrogen Storage), a partnership between OGS, the University of Trieste and the University of Udine, and funded by the Friuli Venezia Giulia Region (NE Italy). The project aims to create an open, integrated and distributed infrastructure designed to link academia and industry for the investigation, characterisation, and de-risking of potential UHS sites and accelerate white hydrogen exploration.

Within the project we will integrate geophysical instrumentation with advanced laboratory facilities and multi-scale numerical modelling to characterize reservoir/caprock systems and assess potential hazards related to hydrogen injection, storage and extraction. The infrastructure includes:

• The acquisition of high-resolution imaging and monitoring equipment including borehole logging systems, seismic and geoelectric arrays, and optical DAS cable for monitoring purposes. This will enable both the characterisation of potential UHS sites and the continuous observation of pressure-induced changes and fluid migration patterns within the reservoir once hydrogen storage begins.
• The development of multi-platform remote sensing capabilities through the acquisition of airborne and drone-based magnetic and gravity systems to map subsurface heterogeneities and structural discontinuities.
• The enhancement of experimental petrophysical and fluid-dynamics laboratories to define hydrogen–rock–fluid interactions and processes. These facilities are essential to quantify the petrophysical properties affecting hydrogen containment and recovery and fluid migration within the reservoir/caprock system.
• The integration of predictive modelling software suites to derisk site selection and quantify fluid-dynamic processes in the subsurface.

Furthermore, FUSE aims to provide new tools to support the emerging exploration of natural (white) hydrogen. Overall, FUSE will boost opportunities for research and industry realms in the identification of potential UHS sites and help de-risk future efforts aimed at initiating large scale hydrogen storage.

How to cite: Barison, E., Ferraccioli, F., Bonini, L., Soldati, A., Marchioli, C., Pipan, M., De Paoli, M., Gei, D., Giorgi, M., Civile, D., Forte, E., Bellezza, C., Schleifer, A., Lipari, V., Picotti, S., Franceschi, M., Corradetti, A., and Del Ben, A.: A new infrastructure to characterize Underground Hydrogen Storage and White Hydrogen sites, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-11548, https://doi.org/10.5194/egusphere-egu26-11548, 2026.

EGU26-11548

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This study investigates subsurface characterization and reservoir selection for underground hydrogen storage (UHS) in Lithuania, emphasizing geological viability and storage integrity. ​ Lithuania's reservoirs exhibit promising characteristics for UHS, including favorable porosity, permeability, and caprock integrity. ​ A preliminary study of  10-year simulation of hydrogen injection and recovery in the Syderiai saline aquifer demonstrated the feasibility of UHS, though recovery efficiency was reduced by nearly 50% when using a single well for both injection and production. ​ Volumetric analysis estimated a combined storage capacity of approximately 898.5 Gg H2 (~11 TWh) for the Syderiai and Vaskai saline aquifers. ​ After this preliminary study, a systematic approach was utilized to evaluate and rank Lithuanian geological sites for UHS using multi-criteria decision-making (MCDM) methods in details. The study involved identifying and collecting data on essential parameters, which were divided into technical, safety, and environmental aspects. Subsequently, geological options such as salt caverns, brine ponds, and depleted oil reserves were selected. The parameters were validated, converted to numerical values, and organized into a scoring matrix for compatibility with the MCDM method. Challenges such as data gaps and weight assignments were addressed by incorporating expert input and refining the methods to emphasize positively contributing parameters. The study also highlights the importance of collaboration between researchers, industry stakeholders, and policymakers to ensure safe, cost-effective, and sustainable UHS solutions that support Lithuania's transition to a clean energy system.

How to cite: Verma, A., Dangi, S. L., and Pal, M.: Subsurface characterization and reservoir selection in Lithuania for underground hydrogen storage, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-11734, https://doi.org/10.5194/egusphere-egu26-11734, 2026.

EGU26-11734

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Deepwater shallow sediments can fall within the pressure and temperature stability field of CO2-hydrate. Under these conditions, injected CO2 can be immobilized as a solid phase, which is a potential option for long-term sequestration. However, CO2-hydrate formation can strongly change the coupled hydro-thermo-mechanical response of the near-well region. Hydrate bonding can increase stiffness and strength, while pore filling and connectivity reduction can decrease intrinsic permeability, lower relative permeability to CO2, and reduce injectivity. These competing effects imply that an effective injection strategy should balance maximizing the amount of CO2 stored in the solid hydrate form and maintaining sufficient permeability for injectivity. Excessive pressure buildup and geomechanical instability should also be avoided.

We develop a fully coupled thermo-hydro-mechanical-chemical model to simulate CO2 injection, hydrate kinetics, heat transfer, and sediment deformation. The formulation solves for pore pressure, temperature, displacement, and hydrate saturation. Additional governing equations representing reaction kinetics and mass transfer between gaseous and solid phases are also derived. Hydrate formation and dissociation are described using a kinetic model based on local thermodynamic disequilibrium, and the associated latent heat is included in the energy balance. The geomechanical field is represented by a coupled poromechanical model that accounts for effective stress, fluid pressure, and geomechanical properties. Sediment stiffness, strength, and permeability are modeled as functions of hydrate saturation and stress. Candidate injection schedules including rate, bottom-hole pressure, and temperature are considered in the investigation. The sequestration efficacy is quantified by solid-phase CO2 mass, injectivity, pressure evolution, and shear and tensile failure risks.

Numerical results indicate that hydrate formation localizes near the injection point during early time, leading to rapid permeability reduction and a progressive increase in the injection pressure to sustain the target rate. Injection schedules with step-wise and intermittent operations can delay near-well permeability damage and facilitate outward migration of the hydrate formation front, which helps the spatial distribution of solid CO2 while maintaining injectivity. Results also suggest that hydrate-induced strengthening can increase resistance to deformation, but also change stress concentrations and alter failure patterns depending on the degree of permeability damage and pressure buildup. Analyses indicate that stronger injection leads to greater solid CO2 storage, but can reduce injectivity and geomechanical safety margins. This critical threshold is controlled by sediment physical and geomechanical properties as well as bottom-hole boundary conditions.

This study provides a numerical model for designing CO2 injection strategies in hydrate-stable deepwater sediments. It can be used to provide quantitative predictions and references for injection optimization to achieve robust solid sequestration while avoiding excessive permeability damage and geomechanical instability.

How to cite: Guo, X., Jin, Y., Pang, H., Shen, S., and Tang, J.: Optimizing CO2 Injection for Hydrate-Based Solid Sequestration in Deepwater Shallow Sediments Based on a Coupled THMC Model, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-13252, https://doi.org/10.5194/egusphere-egu26-13252, 2026.

EGU26-13252

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Abstract: The issue of global climate warming is becoming increasingly severe, and geologic CO₂ storage has emerged as a key measure for mitigating climate change, making storage safety particularly critical. In the In Salah region, InSAR technology has been applied to the world’s largest industrial-scale CO₂ storage project to monitor surface deformation induced by CO₂ injection with high precision. In this study, InSAR-observed surface deformation was combined with the surface elastic deformation theory of GEETSMA and Tarantola’s geophysical inversion method to establish a two-dimensional inversion framework linking surface deformation to reservoir pore pressure. Using this framework, we optimized the reservoir’s physical and mechanical parameters, obtained the spatial distribution of pore pressure changes, and evaluated reservoir leakage risk by calculating local mass flux, pressure gradients, and overall mass balance, identifying potential leakage zones and the total possible leaked CO₂, thereby providing a quantitative basis for assessing storage safety. The inverted parameters and pressure distributions can not only support safety assessments but also guide the optimization of injection strategies. Overall, this approach offers a cost-effective method for evaluating the safety of CO₂ sequestration against potential leakage.

Keywords: CO₂ sequestration, InSAR, reservoir pore pressure, geophysical inversion, storage safety

How to cite: Du, W., Toussaint, R., Marwan, F., and Måløy, K. J.: Mapping Reservoir Pressure from Surface Deformation: An InSAR and Geomechanical Inversion of the In Salah CO₂ Reservoir for Assessing CO₂ Storage Safety, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18024, https://doi.org/10.5194/egusphere-egu26-18024, 2026.

EGU26-18024

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Legacy wells represent a long-term risk to the integrity of geological CO₂ storage and other subsurface energy systems, yet leakage detection and interpretation remain difficult because surface gas fluxes are highly variable and strongly modulated by environmental conditions. Here we present a field investigation of gas leakage from an integrity-compromised legacy well in northeastern British Columbia, using high-frequency, multi-species flux monitoring to examine how subsurface leakage is expressed at the surface under variable environmental conditions. We combine continuous CH₄ and CO₂ flux measurements, repeated spatial mapping, and co-located soil and meteorological observations over several days, using multivariate statistics and machine-learning approaches to interpret leakage behaviour. We find that leakage expresses through two contrasting but coupled surface signatures. Methane emerges as a compact and persistent hotspot (~1 m²), consistent with focused, advective transport along pathways near the wellbore. In contrast, excess CO₂ forms a broader and mobile footprint (~30 m²) that shifts between surveys, reflecting strong near-surface modulation as migrating CH₄ is partially oxidised and redistributed laterally within the soil. Emissions are modest yet sustained over the observation period, illustrating how small, chronic leaks may accumulate into climate and containment concerns over storage timescales. Baseline CH₄ variability is dominated by environmental state, whereas short-lived high-flux events contribute disproportionately to total emissions and are not explained by measured surface forcing, indicating transient changes in subsurface source behaviour or flow configuration. Together, these results show that surface leakage signatures reflect coupled environmental modulation and subsurface intermittency rather than source behaviour alone.

How to cite: Pullen, B. and Cahill, A.: Coupled environmental modulation and source intermittency in gas leakage from a legacy well, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18131, https://doi.org/10.5194/egusphere-egu26-18131, 2026.

EGU26-18131

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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.

How to cite: W Mohd Zainudin, W. N. S., Busch, A., Inskip, N. F., Claes, H., Sazali, W. M. L., Md Shah, S. S., and Lew, C. L.: Reducing Uncertainty in CCS Caprock Seal Performance Using NMR: Insights from Offshore Peninsular Malaysia, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18958, https://doi.org/10.5194/egusphere-egu26-18958, 2026.

EGU26-18958

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Geological sequestration is widely regarded as an effective strategy for mitigating atmospheric CO₂ emissions, yet its success depends on a robust understanding of subsurface fluid transport. Central to this challenge is the ability to characterize permeability heterogeneity at the core scale. Conventional permeability measurements on core plugs provide only bulk-averaged values and are limited in spatial representativeness, while medical CT combined with core-flooding experiments can image core-scale permeability patterns but lacks sufficient resolution. Conversely, micro-CT enables pore-scale characterization and permeability simulation, but its restricted field of view limits assessment of larger-scale heterogeneity. To bridge these scale gaps, this study integrates multi-resolution X-ray CT imaging to capture both pore-scale features and core-scale variability, thereby improving permeability characterization. Four sandstone core-plug samples were scanned at resolutions of 5.0 μm, 22.3 μm, and 68.9 μm. Binary segmentation and pore network models were constructed at each resolution to quantify porosity, pore and throat size distributions, connectivity, and simulated permeability, which were evaluated against laboratory measurements. Simulated permeability derived from 5.0 μm images agrees well with experimental results, whereas simulations based on coarser resolutions are strongly influenced by partial-volume and point-spread effects. Despite this limitation, throat size exhibits robust correlations with experimental permeability across all resolutions. Building on this observation, we introduce the lower partial standard deviation (LPSD), a grayscale-based statistical index that reduces segmentation uncertainty while capturing pore-scale variability. LPSD shows strong positive correlations with pore size, throat size, and experimental permeability at all resolutions. Cross-resolution validation using a heterogeneous sample further demonstrates consistent permeability distributions estimated from LPSD at 22.3 μm and 68.9 μm. Because 68.9 μm resolution is applicable to whole-core CT scanning with Geotek RXCT, the proposed approach enables core-scale permeability mapping that preserves sub-core heterogeneity, providing a more reliable foundation for CO₂ transport modeling, injection strategy design, and long-term storage performance assessment.

How to cite: Huang, J.-J. S., Liu, Y.-M., Kioka, A., Chen, S.-H., Jhuo, Y.-S., and Ge, L.: Quantifying Sandstone Permeability Using Multi-Resolution X-ray CT and Statistical Indexes, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-19131, https://doi.org/10.5194/egusphere-egu26-19131, 2026.

EGU26-19131

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To address long-term geological carbon storage under net-zero emission scenarios , this study proposes an innovative accelerated CO₂ mineralization and storage technology that uses Penghu basalt as the storage medium, combined with supercritical carbon dioxide and waste desalination brine. Through a laboratory-scale high-pressure automatic injection system, a CO₂-brine mixed fluid is injected into basalt cores under simulated temperature and pressure conditions corresponding to a depth of 1,500 meters, promoting reactions between carbonate species and metal ions such as Ca, Mg, and Fe to form stable carbonate minerals, thereby achieving long-term and secure carbon fixation.

To evaluate the storage capacity, this study adopts a volumetric mass-balance approach. Based on the representative chemical composition of Penghu basalt, the best-performing stratigraphic unit indicates a mineralized CO₂ storage potential of approximately 7,800 MtCO₂. Under Taiwan’s current carbon fee (approximately USD 9-10 per tCO₂e, equivalent to about NTD 300), this corresponds to a potential avoided carbon cost on the order of USD 70-80 billion.

This technology simultaneously converts waste brine into a reaction medium, reducing impacts from marine discharge and avoiding competition for freshwater, thus integrating carbon storage with water resource sustainability. The research outcomes are expected to provide a concrete technical basis for the development of mineralization-based CCUS and carbon credit mechanisms in Taiwan’s offshore islands and coastal regions.

How to cite: Chang, C.-W. and Yang, W.-T.: Carbon Sequestration in Penghu Basalt: Integrating CO2 Mineralization with Sustainable Brine Management, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-19695, https://doi.org/10.5194/egusphere-egu26-19695, 2026.

EGU26-19695

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Transitioning to low-emission energy systems increasingly relies on subsurface technologies such as carbon capture and storage (CCS), geological hydrogen storage, and the sealing and abandonment of legacy hydrocarbon wells. All these technologies require reliable long-term containment, which depends strongly on the sealing capacity of caprocks. Shales commonly form the primary barrier above storage reservoirs, benefiting from their very low permeability and relatively ductile deformation behavior. During injection, as the pore pressure in the storage reservoir increases and injected fluids start to invade the shale caprock, pressure-driven changes in pore structure and saturation state may directly impact transport pathways, potentially increasing leakage risk. Given the critical role of shale caprocks in preventing CO₂ migration, laboratory core-scale measurements are essential to assess any such changes in caprock properties.

This study presents a laboratory experimental program designed to quantify how CO₂ and CO₂–water flow alters shale core plug permeability and pressure response. Cylindrical shale core plugs are assembled in an experimental cell with controlled confinement, and permeability is determined from continuous monitoring of inlet and outlet pressures, differential pressure, and flow rate during constant volumetric injection. In the first set of tests, CO₂ is injected CO₂ is injected through shale core plugs under different confining pressures to evaluate how changes in external loading and flow conditions influence measured permeability and pressure transients. These measurements provide insight into stress-sensitive flow behavior and whether permeability changes are reversible or exhibit hysteresis after pressure cycling.

In a second set of experiments, a three-step injection sequence will be performed to mimic saturation-history effects relevant to CO₂ storage. Starting with a water-saturated sample, first CO2 will be injected, followed by water, and then CO2 again. Throughout the sequence, pressure evolution and permeability estimates are tracked to evaluate how switching between injected fluids, and fluid–rock interactions influence transport. The CO₂–water–CO₂ protocol is used to assess whether water introduction modifies flow pathways, and whether the subsequent CO₂ reinjection restores, further reduces, or permanently alters the permeability relative to the initial CO₂ baseline.

The resulting dataset links injection history and confining-pressure changes to permeability evolution in shale caprock analogs, providing experimental constraints for evaluating caprock performance in CCS. In addition, the measurements will be used to calibrate numerical models of flow in low-permeability caprock, strengthening model and improving predictive capability for caprock integrity assessment under realistic injection scenarios.

How to cite: Huseynov, F., van Noort, R., Branvoll, Ø., Yarushina, V., and Kiss, D.: Assessing shale caprock permeability evolution during CO₂ injection and multiphase flow, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-20057, https://doi.org/10.5194/egusphere-egu26-20057, 2026.

EGU26-20057

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Underground hydrogen storage in salt caverns is increasingly recognised as a critical component of future low-carbon energy systems, due to the low permeability and favourable mechanical properties of evaporite formations. However, evaporites commonly exhibit significant internal heterogeneity, including sulphate-bearing salts and siliciclastic interlayers, which may influence cavern stability, gas purity, and long-term operational performance. In particular, hydrogen-rock interactions may promote sulphate reduction and H₂S generation, posing potential technical and safety risks.

This study investigates the geological and geochemical controls on hydrogen storage in salt caverns, focusing on the Z2 cycle of the Zechstein Formation as a candidate for large-scale hydrogen storage. The approach integrates detailed geological characterisation, laboratory-based batch reaction experiments, petrophysical analysis, and geochemical modelling to assess both storage suitability and key uncertainties. Lithological variability, mineralogical composition, and geochemical reactivity are systematically evaluated, with particular emphasis on sulphate-rich intervals and siliciclastic interbeds.

To address challenges associated with evaporite heterogeneity, the study develops a semi-automated workflow for wireline log analysis, enabling improved identification and characterisation of lithological variability in evaporite formations. Experimental and modelling results are used to constrain potential reaction pathways and assess their implications for cavern integrity and gas quality.

By combining geological, experimental, and geochemical modelling approaches, this work provides new insights into hydrogen-rock salt interactions for both onshore and offshore Zechstein salt caverns. The results contribute to improved risk assessment, site selection, and operational strategies for underground hydrogen storage, supporting both scientific understanding and industrial deployment.

How to cite: Skupinska, M.: Geological and Geochemical Controls on Hydrogen Storage in Zechstein Salt Caverns, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-20386, https://doi.org/10.5194/egusphere-egu26-20386, 2026.

EGU26-20386

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Carbfix is an Icelandic carbon sequestration company contributing towards global CCS efforts; they have been injecting CO₂ and H₂S into porous basalt at Hellisheiði, Iceland since 2012. The compounds are dissolved in H₂O and injected to depths of 500-800 m where temperatures range from 20-50 °C [1] at a 3:1 ratio of CO₂ to H₂S [2]. Once injected, the CO₂ dissociates into bicarbonate and carbonate ions which react with Ca²⁺, Mg²⁺ and Fe²⁺ ions present in the basalt, causing carbonate minerals to precipitate [3]. 95% of CO₂ mineralises within two years [4], and almost all H₂S mineralises to pyrite within four months of injection [1]. These short timescales make this process a valuable asset for rapidly reducing atmospheric CO₂ levels. The carbonate minerals are locked in solid form for geologically significant timescales, eliminating risk of leakage from the reservoir.

This style of reactive CCS can be considered anthropogenic alteration and analogous to low temperature alteration observed in many mineral deposits. As with mineral deposits, the location of mineral precipitation is governed by fluid chemistry, the reactivity of the rock mass, and crucially the porosity and permeability of the rock mass. Specifically in the case of CCS, we seek to understand not only where these minerals will precipitate, but additionally the potential storage capacity of the reservoir and how this changes over time. Callow et al. [5] concluded that Hellisheiði reservoir has a storage capacity of 0.33 Gt based on analysis of a single core sample. The heterogenous nature of Hellisheiði reservoir indicates that one sample is not representative of the whole reservoir.

This project aims to enhance understanding of the preferential fluid pathways and storage capacity at Hellisheiði reservoir using a range of samples and techniques including X-ray CT scanning and laboratory experiments to understand porosity and permeability, and optical microscopy, XRD and analytical SEM to understand mineralogy. This poster presents current analysis and findings from X-ray CT, optical microscopy and laboratory experiments.

References:

[1] Snæbjörnsdóttir S Ó et al. (2017) Int J of GHG Control 58:87-102

[2] Clark D E et al. (2020) Geochimica et Cosmochimica Acta 279:45-66

[3] Matter J M et al. (2011) Energy Procedia 4:5579-5585

[4] Matter J M et al. (2016) Sci 352:1312-1314

[5] Callow B et al. (2018) Int J of GHG Control 70:146-156

How to cite: Mottram, R., Mitchell, T., Armstrong, R., Snæbjörnsdóttir, S. Ó., and Stanton-Yonge Sesnic, A.: How much CO2 can Hellisheiði reservoir, Iceland store? A multiscale characterisation of porosity and permeability in basaltic rocks., EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-20430, https://doi.org/10.5194/egusphere-egu26-20430, 2026.

EGU26-20430

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CO₂ geological storage generally involves the injection of a captured CO₂ stream into a suitable reservoir overlain by a low permeability seal or cap-rock formation.  The risk of significant leakage out of the storage site is expected to be very low in well characterised and managed operations.  However, a stakeholder perceived risk factor is the potential for leakage and contamination to overlying drinking water aquifers via faults, legacy well bores, or leaky seals.  A pilot injection site in Queensland, Australia was planned in a low salinity aquifer.  The CO₂ was sourced initially from a coal fired power plant containing SOx, NOx and O₂.  Overlying aquifers were part of the Great Artesian Basin in Australia, which is one of the largest artesian aquifer systems in the world. 

Drill core and cuttings from various Great Artesian Basin aquifer formations were characterised from potential CO₂ injection and monitoring bores in Queensland, Australia.  The Hutton Sandstone aquifer contains potentially reactive minerals including calcite, siderite, plagioclase and chlorite.  Sandstones and mudstones were reacted at subsurface conditions of 75°C and 15 MPa with synthetic Hutton Sandstone aquifer formation water and either a pure supercritical CO₂ stream or an impure CO₂ stream composition of CO₂-O₂.  While dissolved concentrations of elements such as Ca, Ba, Sr, Rb, REE varied with rock type.  Dissolved Fe was affected by the addition of O₂ in the gas stream with Fe-oxyhydroxide/Fe-oxide precipitation re-sequestering metals.  Dissolved lead concentrations remained favourably low, with arsenic showing a decreasing trend after CO₂ addition, likely through Fe-oxide precipitation and absorption.  Several potential isotope tracers including ⁸⁷Sr/⁸⁶Sr, δ¹³C-DIC, δ¹³C-CO₂, δ¹⁸O-H₂O and δ²H-H₂O were also analysed during CO₂-water-rock experiments.                 

How to cite: Pearce, J., Dawson, G., Matsui, M., Brink, F., Golding, S., and Chen, Z.: Impure CO2 storage and potential groundwater leakage indicators, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-3672, https://doi.org/10.5194/egusphere-egu26-3672, 2026.

EGU26-3672

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Well-connected basalt sequences as potential reservoirs for large-scale carbon sequestration revealed by strontium isotopes

Ingar Johansen¹, P. Craig Smalley², Vani N. Devegowda¹, John M. Millett^3,4,5, Marija P. Rosenqvist⁴, Mohamed Mansour Abdelmalak⁴, Sverre Planke^3,4, Stéphane Polteau^1*,

1 –Institute for Energy Technology, Kjeller, Norway

2 –Imperial College London, London, UK

3 – Volcanic Basin Energy Research, Oslo, Norway

4 - University of Oslo, Oslo, Norway

5 - University of Aberdeen, Aberdeen, UK

Basalt complexes can cover hundreds to thousands of km2 and be several km thick; with an estimated global capacity of 40 Tt for carbon storage, they represent a solution for the large-scale injection of CO₂ to reach the 2050 emission targets. However, the hydraulic conductivity of basalt sequences is difficult to predict because it has never been the focus in basalt research. In this contribution, we evaluated for the first time the vertical fluid connectivity of a basalt sequence using the Sr isotope composition of pore waters, sampled using the strontium residual salt analysis (SrRSA) method. Thirty-seven samples were collected in the U1571A borehole (IODP Expedition 396 on the Skoll High, offshore Mid-Norway). Sampling of the well targeted the most representative lithologies in the core and hence included vesicular and tight basalt. The SrRSA method measures the ⁸⁷Sr/⁸⁶Sr ratio in the salt residue that precipitated in the pores of core samples after the pore water evaporated, and the value measured in the laboratory should accurately reflect that of the in-situ pore water. However, since the well was drilled using seawater with barite and sepiolite additives, each sample was washed in de-ionized water to reduce potential contamination. The samples were subsequently dried, crushed, the salts were leached, the leachate filtered, and the strontium analyzed using a MC-ICPS-MS. The results show that the Sr concentrations are very low: 1-35 ppb in vesicular basalt samples and up to 2 ppb in tight basalt samples. The ⁸⁷Sr/⁸⁶Sr ratio of the vesicular basalt varies little away from the average value of 0.7085, while the values of tight basalts show more variability with an average of 0.7093. The SrRSA pattern vs. depth for the vesicular basalt samples is smooth, indicating limited contamination from drilling fluids, and further suggesting a good vertical connectivity. On the other hand, the pattern of the tight basalts is shifted towards heavier values similar to modern seawater, suggesting the SrRSA for these samples to be contaminated by the drilling fluids. In addition to the residual salts, we are currently analyzing the ⁸⁷Sr/⁸⁶Sr in carbonate vesicles and in basalt, which together represent the three main reservoirs of strontium in the samples. These additional results should help us constrain the source of the strontium in the pore system (i.e.:  external, flowing or diffusing through the sequence). These results further show that the fluid connectivity of basalt sequences can be characterized using the SrRSA method by focusing the analyses on vesicular basalt samples. Finaly, this study will provide additional constrains to follow-up numerical models simulating the injectivity and capacity of intra- and inter-basalt reservoir units.

How to cite: Johansen, I., Smalley, C., Devegowda, V., Millett, J., Rosenquist, M. P., Abdelmalak, M. M., Planke, S., and Polteau, S.: Well-connected basalt sequences as potential reservoirs for large-scale carbon sequestration revealed by strontium isotopes, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-7035, https://doi.org/10.5194/egusphere-egu26-7035, 2026.

EGU26-7035

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Emission-intensive sectors (e.g., cement, steel, refractories) have a high demand for decarbonization technologies and Carbon Capture and Storage (CCS) is widely regarded as the most important contributor to rapid and large-scale CO₂ mitigation. While shared CCS networks serving multiple emitters are favoured for their economies and scalability, dedicated CCS projects targeting individual companies remain critical and currently constitute the majority of operational CCS sites worldwide. The ultimate success of such localized CCS projects is strongly constrained by the geological prerequisites in the vicinity of the emission source. This work presents a regional geological screening for CCS potential tailored to a refractory manufacturing plant in the Anhui Province, China. A workflow was developed integrating both geologic and logistic factors, enabling a first-order assessment of both storage feasibility and associated transport costs. The geological screening covers a wide range of technological readiness levels from early-stage laboratory research to mature industrial applications, including saline aquifers, reservoirs associated with oil and gas operations (e.g., depleted fields or enhanced oil recovery), coalbed formations (e.g., enhanced coal bed methane recovery), as well as in-situ mineralization in basaltic rocks. Based on an extensive review of the literature and available reports, ten sedimentary basins and five abandoned coalfields were identified as promising storage options. A GIS-based database was constructed to visualize and compare all storage scenarios. For each candidate site, the shortest CO₂ transport pathway was determined using network-based proximity analysis of existing truck and railway infrastructures. Two sedimentary basins and five coalfields are located within 50 km of the plant, and another two sedimentary basins lie within 100 km. Transportation costs were subsequently estimated using published unit costs for truck and rail transport (EUR/km). Key parameters (e.g., porosity and permeability) of the four closest sedimentary basins were compared with those of international CCS demonstration projects (e.g., Sleipner and Ordos). The results show that for localized, single-emitter CCS projects, geological thresholds such as minimum storage depth and source-sink distance are critical determinants of feasibility, whereas reservoir petrophysical thresholds appear largely project dependent. In particular, while successful CCS projects provide useful benchmarks for porosity and permeability, these parameters alone should not be used as exclusion criteria for CCS deployment in site-specific assessments.

How to cite: Shi, X., Misch, D., Pischler, M., Goetschl, K., Zhang, K., and Pan, Z.: How to select potential sites for geologic CO2 sequestration? A CCS screening workflow, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18984, https://doi.org/10.5194/egusphere-egu26-18984, 2026.

EGU26-18984

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As part of a three-year government assignment to evaluate the potential for geological storage of carbon dioxide in Sweden, the Geological Survey of Sweden has carried out geophysical and geological investigations of deep saline aquifers and caprocks in two areas offshore southern Sweden with very different geological settings: (1) the Lower Palaeozoic succession southeastern Baltic Sea investigations have been focused on offshore the island of Gotland, and (2) the  Upper Mesozoic succession of the southwestern Baltic Sea, offshore Scania – the southernmost part of Sweden. Here we present the results from the two areas are based on two new core drillings in each area combined with onshore and offshore legacy core and seismic data, newly acquired deep seismics from onshore Gotland and Scania as well as offshore Scania. The caprocks in both areas have thicknesses exceeding several hundreds of meters, with low porosities and permeabilities, however, the potential reservoir units present two very different case studies. The Faludden Member consists of homogenous medium-grained quartz arenite with high porosity and permeability, and patchy dolomite cement, while the Arnager Greensand is heterogenous with a lower textural and compositional maturity, consisting of poorly sorted fine- to medium-grained glauconitic sandstones, with varying degrees of consolidation due to intervals of phosphorite concretions and varying content of detrital clay minerals. Despite the difference of the two reservoirs, both are considered suitable candidates for geological storage and further investigations are warranted. Implementation of national CO₂-storage sites would contribute to Sweden's goal of net zero greenhouse gas emissions in 2045 and EU's goal to be climate neutral by 2050.

How to cite: Lindström, S., Andersson, M., Andolfsson, T., Dahlqvist, P., Erlström, M., Lindgren, P., Persson, L., Sopher, D., Wahlquist, P., Wickström, L., and Yotis, L.: Characterization and evaluation of two deep saline aquifers and caprock for carbon dioxide storage offshore Sweden, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-21426, https://doi.org/10.5194/egusphere-egu26-21426, 2026.

EGU26-21426

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Underground hydrogen storage is emerging as a key component of future energy systems, but its deployment in deep geological formations requires a thorough understanding of subsurface structural complexity and fault-controlled reservoir behavior. In tectonically deformed settings, pressure changes associated with cyclic fluid injection and withdrawal may interact with pre-existing structures, potentially affecting reservoir-seal system integrity and fault stability. This study presents first-step results focused on the construction of a static geological model within an integrated geological/fluid-flow/geomechanics modelling workflow developed to assess deep saline aquifers as potential candidates for underground hydrogen storage. The Rivara site was selected as a pilot area based on geological criteria and the availability of extensive datasets, and it is used as a reference case to test the workflow for similar geological settings in Italy and across Europe.

The Rivara area is located in the transition zone between the outer sector of the Northern Apennines (Italy), formed during the Miocene–Lower Pliocene, and the Po Valley. The Rivara Reservoir was previously studied by ERS (Erg Rivara Storage) for a CH₄ storage project, later abandoned. In this work, documentation published by ERS (seismic interpretation, structural maps, petrophysical analyses, etc.) was integrated with public geological databases (ViDEPI) and geological literature. The investigated system consists of a condensed carbonate reservoir (Calcari Grigi Group) overlain by low-permeability marly units (Basinal Formation) acting as a regional seal, within a compressional tectonic framework. Seismic interpretations indicate a structural decoupling between shallow stratigraphic units and deeper levels hosting the reservoir, suggesting that reservoir-scale deformation is governed by a distinct fault system.

Based on available data, we carried out a full modelling workflow. Geological surfaces (associated to the seal and reservoir) were refined through contouring and gridding procedures constrained by explicitly modelled fault traces, preserving fault-related discontinuities. Major compressional structures, including a basal thrust, associated splay and back-thrust elements, and minor faults, were reconstructed in three dimensions and integrated into a comprehensive structural framework. The resulting structural model defines distinct compartments and captures fault offsets and geometries throughout the reservoir volume. The framework was discretized into a three-dimensional geocellular grid through depositional space calculations and structural refinement, and populated with petrophysical properties including interval velocity distributions, porosity, and permeability. A first-pass fracture intensity model was also developed to generate a dual-porosity geological model accounting for tectonic structures and the associated increase in porosity and permeability in their proximity. Finally, formation water salinity was characterized through detailed petrophysical analysis to assess interactions between waters of varying salinity and hydrogen molecules, supporting the evaluation of reservoir suitability for underground hydrogen storage. Overall, the resulting three-dimensional geological model provides a robust basis for investigating subsurface response to hydrogen storage operations in deep saline aquifers.

How to cite: Chiacchieri, D., Vadacca, L., and Lipparini, L.: Understanding Subsurface Deformation Induced by Hydrogen Storage Operations: A Static Geological Model of the Rivara Area (Central Po Plain, Italy), EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-7507, https://doi.org/10.5194/egusphere-egu26-7507, 2026.

EGU26-7507

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As global decarbonization efforts accelerate, hydrogen (H₂) is emerging as a key energy carrier in the transition toward a low-carbon economy. Storing surplus energy is essential to mitigate the intermittency of renewable sources, and underground hydrogen storage (UHS) has therefore attracted growing interest as a cost-effective and scalable solution.

This study investigates the evolution of mineralogical, pore system, and elastic properties (Young’s modulus and Poisson’s ratio) of salt rocks from deep evaporitic deposits in the Ebro Basin (Spain), exposed to hydrogen in an autoclave under controlled batch conditions (4.5 MPa, 30 ºC, 1 cycle of 30 days). Samples were characterized before and after exposure using optical microscopy (OpM), digital image analysis (DIA), scanning electron microscopy (SEM), and P- and S- wave velocity measurements. The combined use of these techniques provides a comprehensive approach to assess the effects of hydrogen on rock properties.

The samples are predominantly composed of white-grey halite (NaCl), with minor impurities of celestine (SrSO₄), anhydrite (CaSO₄), sylvite (KCl), and silicates. Following hydrogen exposure, the samples were re-evaluated to examine potential microstructural and physical modifications, as well as the behaviour of the impurity phases under the imposed experimental conditions. These preliminary findings provide a basis for discussing hydrogen-rock interactions in evaporitic formations and their relevance for assessing salt deposits as potential reservoirs for underground hydrogen storage (UHS)

The research was conducted within the Project PIEMAX-GEO4TREE and the Format-GEO collaboration network (Ref. LINCGLOBAL 25008).

How to cite: Roces, S., Kovács, T., Díaz, C., Suárez-García, F., Ordoñez-Casado, B., Llana-Fúnez, S., and Berrezueta, E.: Salt rock exposure to hydrogen: evolution of mineralogical, pore-system, and elastic properties, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-3898, https://doi.org/10.5194/egusphere-egu26-3898, 2026.

EGU26-3898

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Depleted hydrocarbon reservoirs represent promising candidates for subsurface heat storage due to their well-organized geological architecture and long production history. However, effective reuse of many mature fields is hindered by incomplete or missing well log data sets, especially in older wells where data only exists in paper-based form. In this study, we present an integrated, data-driven workflow that leverages artificial intelligence (AI) to reconstruct missing petrophysical logs and reassess reservoir properties for geothermal heat storage applications. The approach has been demonstrated in a depleted field in Germany's Upper Rhine Graben – one of the most promising geothermal provinces in Europe.

Older well logs were systematically digitized, standardized, and subjected to rigorous statistical data cleaning to remove collection artefacts while preserving the underlying geological signal. Lithological information was obtained through multi-log cross-plot analysis and coded as an additional input function in the machine learning model. This step proved to be important in limiting petrophysical variability and reducing non-uniqueness in predictions. Several supervised machine learning algorithms were evaluated. Hyperparameter optimization was performed for each algorithm to identify the optimal model configuration and significantly reduce overfitting.

Due to a lack of data availability, only two modern wells with complete log suites were available. One well was used for model training and internal validation, while the other well was reserved exclusively for blind testing. The results show strong predictive performance across key petrophysical logs, with independent testing confirming the robustness and generalizability of the well model. Inclusion of lithological descriptors resulted in significant improvement in prediction accuracy and significant reduction in uncertainty compared to models based only on continuous log input.

The proposed workflow highlights the value of combining revitalization of legacy data with interpretable, well-constrained AI models. It provides a transferable methodology for unlocking the geothermal potential of depleting hydrocarbon reserves and supports data-driven decision-making for sustainable subsurface energy storage.

How to cite: Tolba, A. T., Garipi, X., Schill, E., and Kohl, T.: Artificial Intelligence–Driven Reconstruction of Legacy Well Logs to Unlock Heat Storage Potential in Depleted Hydrocarbon Reservoirs: A Case Study from the Upper Rhine Graben, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-5223, https://doi.org/10.5194/egusphere-egu26-5223, 2026.

EGU26-5223

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The development of a UK hydrogen economy requires storage solutions that are flexible, scalable, and deployable in the near term. While large-scale interseasonal hydrogen storage is expected to rely on salt caverns and depleted hydrocarbon fields, lined rock caverns represent a promising intermediate-scale alternative capable of bridging short-term surface storage and long-term seasonal storage as the hydrogen economy grows. To date, a systematic national assessment of lined rock cavern site suitability has been lacking.

This study presents a geospatial methodology for identifying potential sites for subsurface hydrogen storage within lined rock caverns that can be applicable on a national scale. The methodology integrates geological, geographical, and infrastructural constraints using a multi-criteria screening approach. National datasets describing bedrock lithology, rock competence, structural complexity, land-use constraints, and proximity to existing energy and relevant infrastructure were combined and analysed to identify regions for further exploration for hosting lined rock caverns.

Using the UK as a case study, the results demonstrated that there were substantial areas across the UK that met the fundamental requirements for lined rock cavern-based hydrogen storage, particularly in regions underlain by mechanically competent crystalline rock, critically near regions of high industrial demand and energy infrastructure. Scenario-based assessments indicated that individual lined rock cavern installations could provide hydrogen storage capacities sufficient to supply regional industrial demand for several days to weeks, depending on cavern dimensions and operating conditions.

These findings confirmed that lined rock caverns constitute a technically viable storage option for near-term hydrogen deployment in the UK. The presented methodology provides a transparent and transferable framework that could support the future development of lined rock caverns and support strategic planning and policy decisions regarding hydrogen storage in the UK and beyond.

How to cite: Edlmann, K. and Hemming, C.: Site screening for lined rock caverns – A UK based case study, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-21776, https://doi.org/10.5194/egusphere-egu26-21776, 2026.

EGU26-21776

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Craton margins represent long-lived lithospheric weak zones that host a disproportionate share of the world’s sediment-hosted Pb–Zn and Cu resources, yet the geodynamic conditions that distinguish fertile from barren margins remain poorly constrained. Here, we test the hypothesis that subduction dynamics exert a first-order control on craton-margin metallogenesis by integrating a 1.8-billion-year global plate motion model, machine learning–derived craton boundary mapping from full-waveform seismic tomography, a global database of age-coded sediment-hosted deposits, and numerical geodynamic simulations.

Spatiotemporal analysis reveals that mineralised craton margins systematically cluster within 2000 km from active subduction trenches at the time of deposit formation—a spatial signal absent from 90,000 randomly generated craton-margin locations propagated through deep time. More than 90% of the total contained metal endowment of the analysed deposits lies within this 2000 km threshold, demonstrating that trench proximity is a robust discriminator between fertile and barren craton edges. This relationship is consistent across three supercontinent cycles and multiple deposit types, including Pb–Zn clastic-dominated, Mississippi Valley–type, and sediment-hosted Cu systems. Kinematic analysis further shows that deposits formed preferentially during episodes of moderate trench retreat, indicating that the overriding plate migrates oceanward and repositions cratons over previously subducted domains.

Numerical geodynamic models reproduce a comparable spatial scale, with subduction-driven mantle return flow generating lithospheric strain-rate maxima at craton margins approximately 2000 km from trenches. These results indicate that subduction transmits stresses thousands of kilometres into the overriding plate, localising deformation at craton edges while preserving craton interiors. There is a slight offset between observed deposit clustering and modelled strain peaks, likely reflecting inherited lithospheric heterogeneity and three-dimensional mantle flow effects not captured by simplified two-dimensional models. Strain localisation enhances permeability, facilitating long-term metasomatic enrichment of the subcontinental lithospheric mantle by slab-derived fluids.

Subduction-derived volatiles and ligands—including halogens, carbon, and reduced sulphur—play a critical role in metallogenic fertility by increasing the capacity of basinal brines to dissolve, transport, and precipitate metals. Episodes of trench retreat position cratons over previously enriched mantle domains, promoting the ascent of metal-bearing fluids and partial melts into sedimentary basins and triggering short-lived mineralisation events. This mechanism provides a physical explanation for the temporal clustering of giant sediment-hosted deposits during supercontinent breakup phases, when rollback-driven extension and back-arc processes were widespread.

Together, the convergence of global reconstructions, statistical analyses, and geodynamic modelling demonstrates that subduction is a fundamental driver of craton-margin metallogenesis. By quantifying a predictive distance window linking subduction, mantle flow, and lithospheric weakening, this study provides a physically grounded framework for mineral exploration and reveals how deep-Earth dynamics regulate the long-term distribution of critical metal resources throughout Earth history.

How to cite: Shirmard, H., Mather, B., Farahbakhsh, E., O'Neill, C., and Muller, R. D.: A subduction distance control on craton-margin metallogenesis, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-6192, https://doi.org/10.5194/egusphere-egu26-6192, 2026.

EGU26-6192

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The worldwide demand for low-emission hydrogen is expected to rise by ca. 500 % in the time span from 2023 to 2030 due to recent governmental mandates and incentives (IEA Global Hydrogen Review 2024). Aquifers are a widespread and resource-efficient underground hydrogen storage (UHS) possibility, which are - under certain conditions – easier to explore and scale than salt caverns and depleted gas fields. In this study, we quantify the sensitivities of an aquifer UHS model concerning uncertain parameters, the understanding of which is a prerequisite for optimizing operational conditions (e.g. rates and well configurations) and assessing risks for safety and revenue.

A model using Darcy’s law for flow is investigated that describes the motion of two phases (liquid and gas) and three components (water, methane, hydrogen). The model geometry, boundary conditions and parameter distributions are chosen based on real data of a multi-layer sandstone aquifer. The numerical model is implemented in DuMu^X and includes real gas behavior and the computation of gas mixture viscosities.

The following tendencies are observed in the simulations: (1) Dirichlet boundary conditions influence dynamic well pressures if the domain size is chosen too small; (2) converged gas plumes require very fine grid resolutions in some places, which constitutes a large computational cost using regular grids; (3) the caprock’s curvature and dip promote vertical and horizontal motion, respectively; (4) the containment of gases is predominantly controlled by entry pressures; (5) higher heterogeneity in porosity and permeability fields increases gas spreading in all directions and reduces hydrogen recovery. The uncertainty of all of these factors and of petrophysical parameters (porosity, permeability, anisotropy) need to be considered in a future global sensitivity analysis. 

How to cite: Schmidt, G. and Neuweiler, I.: Parameter and Grid Sensitivities of Aquifer Models for Underground Hydrogen Storage, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-1354, https://doi.org/10.5194/egusphere-egu26-1354, 2026.

EGU26-1354

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Salt tectonics is a three-dimensional and time-dependent process strongly influenced by intra-salt heterogeneity and base-salt relief. This study investigates the geometry, internal deformation, and kinematic evolution of layered Aptian salt structures and associated minibasins in the northern Santos Basin, offshore Brazil, using a ca. 3,700 km² post-stack depth-migrated (PSDM) 3D seismic dataset (Franco–Iara survey). Seismostratigraphic analysis enabled the identification of five key seismic surfaces and four chronostratigraphic units within the salt and post-salt succession. Top- and base-salt horizons were mapped across the entire area, while intra-salt reflectors were interpreted in cross-sections to characterize internal deformation, including folds, faults, and shear zones. Salt bodies were classified in terms of their external geometry, maturity, and kinematics based on plan-view and cross-sectional morphology, top-salt concordance, and autochthonous versus allochthonous character. The Aptian layered salt displays strong thickness variations, ranging from ~120 m underneath minibasins to >3.4 km within diapirs. Salt structures include walls, stocks, and anticlines, commonly affected by intra-salt shear-zones and/or faults, and exhibit a basinward decrease in diapir maturity. The Northern Domain of the studied area is dominated by E–W-oriented discordant structures (salt walls and stocks) with E-W upright intra-salt folds and thrusts in their upper most heterogeneous portion that indicate salt transport from north to south. The Northern Domain also displays salt welds, eroded culminations, and features indicative of extensional diapir collapse (e.g., mock-turtle anticlines). In contrast, the Southern Domain is dominated by concordant salt structures, N–S-trending salt anticlines with intra-salt asymmetric fold-and-thrust systems indicating transport from west to east. Base-salt mapping reveals a non-planar surface with dip angles up to ~30°, defining structural highs and lows that exert a first-order control on minibasin localization and salt migration pathways. The spatial correlation between base-salt relief, salt structures, and minibasin architecture supports a conceptual model for the evolution of salt tectonics in the area. Spatiotemporal variations in salt deformation reflect changes in sedimentary loading and transport directions during the Albian–Maastrichtian, followed by waning salt tectonic activity in the Cenozoic. These results highlight the strong coupling between layered salt rheology, base-salt relief, and minibasin evolution, providing new 3D insights into salt tectonic processes in passive margin basins. Understanding salt tectonics in heterogenous settings is critical not only for the oil and gas industry, where salt provides an effective regional seal, but also for emerging energy-transition applications, including subsurface carbon capture and storage.

How to cite: Rebelo Diório, G., Trzaskos, B., Muniz Pichel, L., da Silva Reis Assis, V., and Leon Dias, S. F.: Kinematic Evolution of Layered Aptian Salt in the Northern Santos Basin: Insights from 3D Seismic Data, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-13527, https://doi.org/10.5194/egusphere-egu26-13527, 2026.

EGU26-13527

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Ensuring the secure underground storage of hydrogen (H₂) is crucial for future energy systems. Shallow aquifers, as gas retention areas for leaks from deeper reservoirs, are key monitoring zones. The ANR Hystoren project aims to understand the impact of H₂ leakage into the biogeochemistry of a shallow carbonate aquifer. A controlled leakage simulation was conducted at the experimental Saint-Emilion site (France) injecting water in equilibrium with H₂ and tracer gases (Krypton and Helium). Direct and indirect parameters such as concentrations of dissolved H₂, CO₂, CH₄, He, Kr, isotopic C and H compositions, water physico-chemical parameters and microbial communities were tracked on monitoring wells over a scale of several meters for a week. Here we will focus on the geochemical results to identify the most sensitive parameters indicative of H₂ leakage. On-site H₂ concentrations, measured with Unisens© probes, allowed direct observation of the H₂ plume across µM to mM scales. Laboratory analyses confirmed but showed lower concentrations, indicating reduced sensitivity method to monitor dissolved H₂. The evolution of krypton concentrations (ex-situ measurements) correlate closely with H₂ concentrations. The integration of these methodologies highlighted the complementarity of in-situ and ex-situ approaches and their importance in detecting early signs of leakage.

How to cite: Guelard, J., Noirez, S., Patrigeon, C., Martin, F., Beibacar, Y., Muller, E., Blanquet, S., Michel, T., Dallongeville, A.-S., Marais, A., Rupasinghe, S., Favier, S., Wavrer, J., Loisy, C., and Cerepi, A.: Geochemical monitoring for H2 leakage: Impact of dissolved H2 injection into biogeochemistry of a shallow chalky aquifer, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18262, https://doi.org/10.5194/egusphere-egu26-18262, 2026.

EGU26-18262

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Basaltic rocks host abundant pore space and reactive mineral phases that make them attractive targets for CO₂ storage via mineral trapping, yet their seismic response presents significant challenges for monitoring due to strong scattering and wavefield complexity. Within the framework of the PERBAS project (Permanent sequestration of gigatons of CO2 in continental margin basalt deposits), we assess the potential for high-resolution time-lapse (4D) seismic methods to detect subsurface changes in a basalt-dominated offshore setting and to inform efficient monitoring strategies applicable to future CO₂ storage operations.

We analyze two P-Cable high-resolution 3D seismic volumes acquired over Skoll High in the Vøring Basin (mid-Norwegian margin), a 2022 baseline and a 2024 repeat survey that reoccupied 17 of 26 original sail lines. Both datasets used consistent acquisition parameters and were processed with a uniform workflow incorporating geometry assignment, noise attenuation, amplitude correction, and high-resolution binning (6.25 × 6.25 m). A key objective was to maximize seismic repeatability as a prerequisite for robust 4D analysis in basaltic terrain.

Time-lapse calibration included cross-correlation for phase and time shifts, shaping filters, cross-correlation statics, and amplitude cross-normalization. Different calibration windows were defined above the top basalt and including the top basalt sequence in order to analyze  the impact of non-repeatable signal variability within the volcanic complex. The normalized root-mean-square (NRMS) metric was used to quantify repeatability across the repeat survey area.

Our initial results indicate that high spatial repeatability is attainable with P-Cable 3D seismic data in a basalt setting when acquisition and processing are carefully controlled, though areas of complex basalt morphology and structural heterogeneity exhibit higher NRMS values. Difference volumes highlight regions of anomalous repeatability that correlate with geological features. These findings underscore both the promise and limitations of time-lapse seismic monitoring in basaltic reservoirs and contribute to establishing realistic detection thresholds and optimized survey designs for CO₂ storage monitoring.

This study expands the understanding of seismic repeatability in volcanic margin environments and provides groundwork for advancing cost-effective monitoring strategies in basalt-hosted storage projects.

How to cite: Bünz, S., Yu, J., Leiknes Sivertsen, A., Lebedeva-Ivanova, N., and Planke, S.: Time-lapse  seismic analysis over basaltic rocks at Skoll High (Vøring Basin) to support CO₂ storage monitoring strategies, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-18769, https://doi.org/10.5194/egusphere-egu26-18769, 2026.

EGU26-18769

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As part of the PERAS project, basaltic complexes relevant to potential CO₂ storage on the mid-Norwegian margin have been investigated. IODP Sites U1571A and U1572A sample two contrasting volcanic domains: based on seismic interpretations, site U1571A is located on a faulted lava-flow field, whereas site U1572A to the west is located on a younger pitted surface interpreted to reflect the interaction of lava with wet substrate during the original emplacement. These domains also differ in structural deformation, with abundant local NS–oriented normal faults in the eastern flow field, and comparatively minor faulting in the western pitted domain.

We present first results of controlled-source electromagnetic (CSEM) experiments acquired during cruise MSM140 (4.9–9.10.2025) across the Vøring Plateau, offshore Norway. To investigate how emplacement style and deformation influence basalt structure, two CSEM experiments were carried out covering the area around sites U1571A and U1572A. A third experiment was measured along a profile line connecting the two sites. In addition, two experiments were carried out around ODP Site 642E to provide a regional reference and to assess regional lateral homogeneity of the basaltic complex.

For measurements we used the towed transmitter system CAGEM, which allows for measurements with two horizontal transmitter polarizations. For each of the five experiments, 12 seafloor receivers nodes (OBEMs) were deployed onto the seafloor. This allowed us to collect data in both inline and broadside configurations, improving sensitivity to resistivity anisotropy and 3D structural variability.

How to cite: Jieyu, T., Sebastian, H., Ingo, K., Friedrich, B., Joshua, C., Jan, S., Hanna, Z., Jesse, W., Martin, W.-V., and Jörg, B.: Marine controlled source electromagnetic experiments at potential CCS sites on basalt complexes of the Vøring Plateau offshore Norway , EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-19438, https://doi.org/10.5194/egusphere-egu26-19438, 2026.

EGU26-19438

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Carbon storage in basaltic formations is regarded as one of the safest and most stable long-term sequestration strategies, because mineralization immobilizes CO₂ in solid form. The global abundance of basalts also implies substantial storage potential at very large scales, especially in marine settings where potential usage conflicts would be avoided. However, reliable monitoring is required to confirm storage performance and integrity. In the marine environment, controlled-source electromagnetics (CSEM) is sensitive to subsurface resistivity variations and, therefore, offers a potential means to monitor resistivity changes associated with CO₂ injection and subsequent mineralization processes.

In the PERBAS project we investigate the basalt formations of the Vøring Plateau, offshore Norway. There, borehole data show that several hundred-meter-thick target basalt units consist of interchanging layers of basalt and sedimentary layers with individual thicknesses of several meters. While resolving these layers individually is beyond the resolution of CSEM experiments, the strong layering of resistors (basalts) and conductors (sediments) should result in a significant anisotropic effect on CSEM data.

For a modeling study, we consider three different scenarios: (1) the pre-injection stage represented by the background resistivity distribution, (2) the injection stage, where the CO2 is mainly propagating in the sedimentary layers and (3) the post-injection stage, where the CO2 might have migrated into the basalt layers to form stable minerals. Based on resistivity-logs from boreholes, we constructed a simple 1D anisotropic pre-injection model (stage 1). For the injection scenario before mineralization (stage 2), Archie’s law was used to estimate resistivity increases in sediment layers. For the mineralization scenario (stage 3), resistivity changes in the basalt were estimated based on the current literature and in-situ information from drill holes in the working area. We then calculated time-domain CSEM electric field responses for both, inline and broadside source–receiver configurations, analyzed electric fields changes between the different scenarios and configurations, and evaluated how the electrical anisotropy is affected and best resolved in terms of CSEM measurements and measurements configurations.

The modelling indicates that both inline and broadside configurations are sensitive to CO₂ mineralization (stage 3) and yield clear difference between pre- and post-injection. However, only the broadside configuration can clearly distinguish pre- and post-injection states where CO₂ stays unmineralized in the sediments (stage 2). In summary, our results suggest that measuring both inline and broadside components in CSEM measurements can yield insights into monitoring mineralization processes in anisotropic basalt–sediment systems.

How to cite: Hölz, S. and Tan, J.: Monitoring sequestration related mineralization processes in basalts using marine controlled source electromagnetics, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-19681, https://doi.org/10.5194/egusphere-egu26-19681, 2026.

EGU26-19681

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The long-term storage of gigaton-scale volumes of CO₂ in basaltic formations is widely discussed as a promising strategy for mitigating anthropogenic CO₂ emissions. Offshore basalt deposits are of particular interest as they are distant to urban areas and other resources. In Europe the Vøring Plateau offshore Norway represents a large igneous province called the North Atlantic Igneous Province (NAIP) formed during the breakup of the North Atlantic approximately 56-58 Ma ago. Our research focuses on the lava flows associated with the seaward-dipping reflectors (Planke et al., 2000).

Two sites, previously investigated during ODP and IODP expeditions, on the Vøring Plateau were studied using ocean-bottom seismometers (OBS) and 2D multichannel seismic (MCS) data during cruise MSM140 aboard R/V Maria S. Merian, as part of the multinational PERBAS project. OBS arrays were deployed in a cross-shaped geometry on the seafloor above ODP Site 104–642 and IODP Sites 396–U1571/72. OBS data record both reflected and refracted seismic waves, providing complementary subsurface information to conventional MCS data. In addition, analysis of P-waves and converted S-waves enables detailed velocity modeling and improved characterization of lava flow properties.

Preliminary interpretation of the OBS data and forward modeling allows the identification and narrowing down of a subsurface layer package that appears suitable for potential future CO₂ injection.

How to cite: Sokolkova, E., Soleimani Monfared, M., Lebedeva-Ivanova, N., Klaucke, I., Bialas, J., Dannowski, A., Tan, J., and Hölz, S.: Investigating Seaward-Dipping Reflectors for CO₂ Sequestration on the Vøring Plateau: Preliminary Results from Cruise MSM140, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-19682, https://doi.org/10.5194/egusphere-egu26-19682, 2026.

EGU26-19682

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Hydrogen has increasingly gained attention in the energy transition due to its potential to store intermittent renewable energy and enhance energy system flexibility. In this context, the Netherlands has advanced policies and strategic roadmaps for underground hydrogen storage in depleted gas fields. Alongside these developments, leakage of hydrogen has emerged as a critical environmental and societal risk. The literature on the causal relations governing such uncertainty-driven risks arising from multiple interacting mechanisms remains limited. This study proposes an uncertainty-driven risk characterisation and prioritisation framework to address this gap for underground hydrogen storage in depleted gas fields. It combines a structured pathway identification, Delphi-based expert elicitation through structured questionnaires, a risk matrix, and a site characterisation tool. Possible causes of hydrogen leakage are categorised into caprock, fault/fracture zones, well system, and overall storage structure, and labelled according to their underlying mechanisms. Experts are selected purposely based on their expertise level, and questionnaires assess the importance of each cause and the degree of certainty associated with this assessment. The most relevant causes are then prioritised using a risk matrix. Site characterisation is considered to contextualise how prioritised causes may manifest across different storage settings. The prioritised risks are subsequently represented using bow-tie and fault tree diagrams. Overall, this study provides a structured investigation of the causal relations underlying uncertainty-driven hydrogen leakage risks in Dutch depleted gas fields. 

Keywords: underground hydrogen storage, uncertainty-driven risks, expert elicitation

How to cite: Aydin, M., Miocic, J., Kilic, O., Turhan, E., and Zuidema, C.: Linking Uncertainty and Risk in Underground Hydrogen Storage: An Expert-Elicited Causal Approach, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-20104, https://doi.org/10.5194/egusphere-egu26-20104, 2026.

EGU26-20104

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Hydrogen energy storage in geological formations is increasingly regarded as a key component of a future low-carbon energy system. Among potential reservoir rocks, salt formations are particularly attractive due to their extremely low permeability, low chemical reactivity, and self-healing behaviour, all of which favour long-term storage integrity. However, natural salt deposits differ in genesis, texture, and impurity content, which may influence their geochemical response to underground hydrogen storage (UHS) conditions.

This study compares the chemical–mineralogical reactivity of rock salt formations of different origins when exposed to hydrogen. Three salt types were studied: the Oligocene Barbastro Formation (Ebro Basin, Spain), the Triassic Atauri Formation (Basque-Cantabrian Basin, Spain), and a commercially available Himalaya salt. Owing to their distinct depositional environments and post-depositional histories, these materials exhibit subtle differences in texture and mineralogical composition. Samples were exposed to hydrogen gas under representative UHS conditions in a high-pressure vessel (p = 10 MPa, T = 60 °C) for 30 days under batch conditions. Pre- and post-exposure characterisation was performed using X-ray diffraction and scanning electron microscopy to assess potential mineralogical and textural changes.

The results indicate that all three salt types undergo only minor alterations under the investigated conditions and timescale, confirming the overall chemical stability of halite in a hydrogen storage context. The only notable differences in reactivity are associated with the presence of gypsum as an accessory phase, which locally influences mineralogical responses. These findings support the suitability of a wide range of natural salt formations for underground hydrogen storage, while highlighting the importance of impurity phases in site-specific assessments.

The research was conducted within the Project UES365, the Project H2Salts and the Format-GEO collaboration network (LINCGLOBAL 25008).

References:

Kovács, T., Mediato, J., Ordóñez, B., Garcia-Mancha, N., Santolaria, P., Calvín, P., Sanchez Guzman, J., Gracia, J., Roces, S., Mata Campos, P., and Berrezueta, E.: Preliminary laboratory studies on hydrogen storage in a salt cavern of the Eocene Barbastro Formation, Southern Pyrenees, Spain, Adv. Geosci., 67, 15–24, https://doi.org/10.5194/adgeo-67-15-2025, 2025.

How to cite: Kovács, T., Mediato, J., Ordóñez, B., Del Moral, B., Roces, S., and Berrezueta, E.: Reactivity of Natural Rock Salts of Different Genesis under Underground Hydrogen Storage Conditions, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-5005, https://doi.org/10.5194/egusphere-egu26-5005, 2026.

EGU26-5005

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Underground hydrogen storage (UHS) is a central aspect of Germany's national hydrogen strategy. Hereby, existing salt caverns in Northern Germany are considered for UHS, even though porous formations comprise approximately one third of Germany's in-place capacity for natural gas storage. In addition, first tests in the German and Austrian parts of the North Alpine Foreland Basin showed promising results for UHS in porous formations. The undeformed part of the North Alpine Foreland Basin in SE Germany hosts 58 oil and gas fields, with 5 still actively producing and another 5 converted to natural gas storage sites. The latter currently provide 30% of Germany's in-place natural gas storage capacity in porous formations.

We investigated the static hydrogen storage capacity of all 58 oil and gas fields on the basis of oil and gas production data. We considered ambient densities based on average hydrocarbon compositions and pure hydrogen, and calculated subsurface hydrogen and hydrocarbon densities as a function of temperature and pore pressure gradients, both of which are varying with depth and laterally. Finally, we assumed a range of working-gas-to-cushion-gas ratios which resemble the current natural gas storage sites in the area to estimate static hydrogen storage capacities for each field.

Our results show that the cumulative hydrogen storage capacity in the SE German part of the North Alpine Foreland Basin is close to the capacity of salt caverns in Northern Germany. Hereby, the 5 active natural gas storage sites comprise around 40% of the overall storage capacity, which - by building on the existing infrastructure - would allow for a fast and smooth implementation of additional and spatially diversified UHS capacities in Germany.

How to cite: Drews, M., Misch, D., Able, L.-M., Aconcha, E., Babaie, P., Bensing, J., Breitsameter, J., Duschl, F., Mahmoodpour, S., and Skerbisch, L.: Static underground hydrogen storage capacities of oil and gas fields in the North Alpine Foreland Basin, SE Germany, EGU General Assembly 2026, Vienna, Austria, 3–8 May 2026, EGU26-16391, https://doi.org/10.5194/egusphere-egu26-16391, 2026.

EGU26-16391

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