Based on PY-GC, Rock-Eval, TOC, burial history and thermal history data, the oil generating quantity can be calculated by chemical kinetic methods. The more oil is generated, the more oil is discharged, reflecting the stronger shale oil migration effect. Meanwhile, the in-situ oil content of shale increases, eventually reaching the upper limit of the reservoir and in dynamic equilibrium (Figure 1). And the content of non-polar and relatively low molecular weight saturated hydrocarbons in in-situ shale oil decreases (Figure 2). Based on chloroform asphalt A, group components, and pyrolysis data, the missing light and heavy hydrocarbons in experimental value S1 can be recovered to obtain the in-situ oil content of shale (Figure 3). From this, the hydrocarbon-expulsion efficiency (HEE) can be calculated. The research results indicate that, during the migration of shale oil, heavy isotope ¹³C with strong adsorption capacity is retained and enriched due to isotope fractionation, while light isotope ¹²C is more easily migrated and discharged. In order to eliminate the influence of kerogen type on carbon isotopes, the carbon isotopes of chloroform asphalt A, saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltene were subtracted from the carbon isotopes of kerogen. It was found that the difference (Δ δ¹³C) between them increased with the increase of HEE, indicating that the stronger the migration effect, the heavier the carbon isotopes of chloroform asphalt A, saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltene (Figure 4). Similarly, due to the geochromatography effect during the migration process, when the migration is strong, a large amount of tricyclic terpene with relatively low molecular weight will be discharged, and pentacyclic triterpene alkane will be relatively enriched, resulting in a decrease in the ratio of tricyclic terpene to pentacyclic triterpene alkane (RTP) (Figure 5). Non-polar and relatively low molecular weight saturated hydrocarbons are prone to migration, while non-hydrocarbons and asphaltenes have high relative molecular weight and contain a large number of heteroatom components, resulting in high adsorption and difficulty in migration. This leads to a decrease in the ratio of saturated hydrocarbons to aromatic hydrocarbons (RSA), as well as the ratio of saturated hydrocarbons and aromatic hydrocarbons to non-hydrocarbons and asphaltenes, as migration increases (Figure 6). The primary migration of crude oil within source rocks leads to differential enrichment of shale oil. The increase in HEE indicates a stronger migration of shale oil, leading to a decrease in the in-situ unit organic carbon oil content of shale and a decrease in shale oil saturation index (Figure 7). The light components with weak polarity and relatively low molecular weight in shale oil decrease with increasing migration, while the heavy components with relatively high polarity are relatively enriched, leading to a decrease in shale oil mobility.

How to cite: You, H. and Li, J.: Effects of Crude Oil Generation and Primary Migration on Shale Oil Enrichment and Mobility: A Case Study of Biyang Depression in the Nanxiang Basin, China, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-15167, https://doi.org/10.5194/egusphere-egu25-15167, 2025.

Shales, particularly lacustrine shales, are known to have undergone frequent changes during deposition and are highly sensitive to climate fluctuations, bioturbation, and other environmental factors. The mineral compositions, sedimentary structures, mixing patterns, and vertical sequences of shales exhibit high complexities and pronounced heterogeneities. The strong heterogeneity poses challenges in shale reservoir characterization. Previous studies have mostly examined variations in scale-specific shale parameters, often lacking integrated macro- and micro-scale analyses, while few have investigated the controls on shale heterogeneities across scales. One-dimensional XRD and XRF data from homogenized, pulverized samples may obscure valuable information with extraneous details, limiting the ability to capture shales’ intrinsic heterogeneities. In this study, we employed 2D micro-XRF imaging and SEM-AMICS (Automated Mineral Identification and Characterization System) scanning to characterize mesoscale mineral heterogeneities in lacustrine shales. Applying the box-counting principles and chemo-sedimentary facies analysis, we are able to identify representative elementary areas (REAs) at the mesoscale, which can be used to facilitate a more effective link between macroscopic and microscopic heterogeneities. Guided by the REA sizes and locations, we performed micro-drill sampling for low-temperature nitrogen adsorption and high-pressure mercury intrusion experiments, enabling effective characterization of pore structure heterogeneities and the determination of the influencing factors. Using mixed lacustrine shales from the Subei Basin, China, we evaluated the effects of depositional environments on heterogeneities and revealed the primary mineral factors that influence in situ pore structures. Our findings indicate that frequent changes in water depth and climate are major controls on the lamina formation in the Subei Basin mixed shales, thereby exacerbating shale heterogeneities. Clay minerals contribute strongly to micropore heterogeneities, while felsic and carbonate minerals predominantly influence the mesopore heterogeneities. Macropore heterogeneities are primarily controlled by felsic minerals. These insights advance our understanding on the primary factors influencing shale heterogeneities under complex, multifactorial conditions. Integrated across-scale information allows us to better inform shale reservoir characterization and development strategies.

How to cite: Guo, Z. and Liu, K.: Unraveling the Complexity of Lacustrine Shales via an integrated Macro- and Micro-Scale Characterization, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-108, https://doi.org/10.5194/egusphere-egu25-108, 2025.

Tight reservoir wettability directly influences the flow and storage characteristics of fluids within pores, which is crucial for evaluating the mobility of oil and water during tight reservoir oil reservoir development, as well as analyzing the storage capacity of carbon dioxide and hydrogen in tight reservoir reservoirs. However, the low porosity and permeability of tight reservoir, coupled with its complex pore network structure, significantly increase the difficulty of wettability assessment. Traditional methods struggle to achieve accurate quantification of the volumes of pores with different wettability types in tight reservoir, relying more on qualitative or indirect evaluations. This study proposes a novel quantitative method for characterizing tight reservoir wettability types based on alternating spontaneous imbibition combined with nuclear magnetic resonance (NMR) fluid quantification. Through a series of alternating imbibition experiments—oil imbibition (SI-O), water imbibition (SI-W), secondary oil imbibition (SI-2O), and secondary water imbibition (SI-2W)—coupled with dynamic T2 and T1-T2 NMR monitoring, the changes in fluid content and distribution within tight reservoir pores during imbibition were elucidated. The results indicate that tight reservoir pores can be categorized into oil-wet, water-wet, and mixed-wet types, each exhibiting distinct pore size distribution characteristics. The SI-O and SI-W stages represent the fluid filling phase, during which tight reservoir pores are rapidly saturated with oil and water, respectively. In contrast, the SI-2O and SI-2W stages represent the fluid equilibrium replacement phase, where the total fluid content in the pores remains unchanged, and only the fluids in mixed-wet pores are replaced according to the imbibition fluid type. Based on the differences in tight reservoir pore wettability, an alternating imbibition model was developed and validated through T2 NMR analysis and fluid content changes. Using this model, the volumes of the three wettability types of pores were quantified, and their pore size distribution characteristics were further clarified through T2 projection spectrum analysis. Compared to traditional methods, this approach addresses the gap in quantifying and analyzing pore size distributions of different wettability types in tight reservoir, significantly improving the accuracy and reliability of tight reservoir wettability assessment. It provides a new perspective for wettability analysis and quantification in tight reservoir.

How to cite: Yu, C. and Wang, M.: Quantitative Characterization and Pore Size Distribution Analysis of Tight Reservoir Wettability Using Integrated Alternating Spontaneous Imbibition and Nuclear Magnetic Resonance Techniques, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-4079, https://doi.org/10.5194/egusphere-egu25-4079, 2025.

Hydraulic fracturing or fracking for shale gas and oil production is a water intensive and environmentally damaging process. It is often blamed for groundwater contamination and artificial earthquakes. Therefore, cryogenic fracking using liquid nitrogen (LN₂) has recently emerged as much safer and greener alternative. This novel process enhances rock permeability by creating thermal fractures by subjecting hydrocarbon-bearing rocks to repeated freeze-thaw cycles. However, the extent and efficiency of this process depends on the constituent minerals of the rock. Clay minerals such as montmorillonite and kaolinite constitute on average approximately 30 to 35 % of shale. These phyllosilicate group of minerals, despite their common layered structures, vary in composition and arrangement, resulting in distinct properties. Therefore, total adsorption of LN₂ in the clay minerals of shale must combine insights on their individual adsorption responses. It is essential to estimate the total and residual LN₂ volumes trapped in pores that will impact the mobility of hydrocarbons. In this work, we studied adsorption behaviour of nitrogen inside the montmorillonite and kaolinite nanopores using Grand Canonical Monte Carlo (GCMC) simulations. The slit pores, with 5 nm, 8 nm, and 12 nm opening were simulated for reservoir pressures ranging from 50 to 95 MPa and temperatures from 300 to 355 K. The influence of pore size, composition, pressure, temperature, and fluid type were studied to understand the relationship between adsorption isotherms and excess properties. The Canonical Ensemble simulations were performed in conjunction with Widom’s insertion technique performed to estimate the average chemical potential and interaction among the N₂ molecules calculated via pair distribution function. The N₂ was precisely represented by TraPPE force field model. The simulated bulk phase densities of N₂ were observed to be in good agreement with literature values. As shown by the pair correlation function obtained from the Canonical Ensemble simulations, the bulk phase N₂ was in a supercritical thermodynamic state at rock-fluid equilibrium temperature and pressure. The results indicated that the pore volume on both surfaces played a crucial role in the behaviour of N₂ adsorption. It was observed that the adsorption capacity of N₂ was affected by the amount of available pore space, revealing insights into interactions between pore surface and adsorbed N₂. Additionally, the study also confirmed that the extent of adsorption was dependent on surface area and morphology of the material. The adsorption isotherms exhibited a well-defined relationship with excess properties of adsorbed N₂. Further, these simulations analysed the thermodynamic nature of adsorbed fluid within the pores using the molecular density distribution profiles across the height of the pore.

How to cite: Singh, A., Sengupta, A., and Guha Roy, D.: Adsorption Isotherms Analysis of Liquid Nitrogen inside Montmorillonite and Kaolinite Rock Pores using Molecular Simulations, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5108, https://doi.org/10.5194/egusphere-egu25-5108, 2025.

Fault seismic interpretation is a decision-making process that heavily relies on the choices of interpreters - it is a multi-solution problem. However, how do interpreters ground their decisions? To understand the foundations of interpreter decision-making, this works explores how newcomers develop competence in fault seismic interpretation. Building on the first author's journey of acquiring fault seismic interpretation skills during her PhD, this study highlights the interplay between individual and social factors in the development of subsurface interpretation expertise. Through a detailed analysis of the first author's journey, including stages of becoming a competent Petrel user, developing a reproducible workflow, and gaining insights into the uncertainties and biases in fault interpretation, this study examines how expertise evolves and how social interactions impact methodological choices.

The results presented in this work stem from the first author's PhD research, which covered learning to interpret faults using seismic images. The findings reveal how the author's interpretative choices aligned with established practices, informed by a thorough literature review and guidance from her supervisor. Initially, her interpretation of normal faults mirrored the simplified, planar structures commonly depicted in existing literature. This approach changed and the author acquired more consciousness about uncertainty and biases in seismic interpretation when returning to fieldwork and realising the inadequacy in interpreting normal faults with simple planar geometries. The inherently uncertain nature of the subsurface prevents the exclusion of potential interpretations, making its characterisation through seismic image interpretation a multi-solution problem rather than one with a single, definitive solution.

The insights gained from this analysis, particularly during the COVID-19 isolation period, underscore the importance of recognising and addressing biases and uncertainties in seismic interpretation. This study highlights the influence of social learning, the limitations of established practices, and the importance of considering multiple potential solutions. By understanding the human element in seismic interpretation, we can improve future training, workflows, and the overall reliability of subsurface models. By encouraging self-reflection among interpreters and advocating for a broader range of structural models, this work aims to enhance the field of subsurface studies response to the evolving demands of the Energy Transition Industry and improve the overall management of uncertainty and biases in seismic fault interpretation.

How to cite: Robledo Carvajal, F. F., Butler, R., and Bond, C.: Developing Competence in Fault Seismic Interpretation: A Personal Reflection, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-6879, https://doi.org/10.5194/egusphere-egu25-6879, 2025.

Acid fracturing is a key technology in the development of fractured carbonate reservoirs, and the conductivity of acid-etched fractures is one of the critical indicators for evaluating the effectiveness of acid fracturing. However, current conductivity calculation models for acid-etched fractures primarily focus on single, regular fractures of small dimensions, which differ significantly from the morphology of real fractures. Moreover, calculation models for the conductivity of complex fractures are relatively scarce.

This study establishes a conductivity calculation model for complex acid-etched fractures based on large-scale acid fracturing physical model experiments, filling a research gap in the field of conductivity calculation models for complex fractures. The research first conducted large-scale physical model acid fracturing experiments (dimensions: 2m × 2m × 1m) and accurately obtained the etched morphology data of the generated complex fractures using three-dimensional laser scanning technology. Based on these data, the concept of contact ratio was introduced using linear elastic theory to calculate the deformation of acid-etched fracture surfaces under the influence of closure stress, determining the width distribution of the deformed fractures. Subsequently, a conductivity calculation model for complex fractures, accounting for natural fractures and multi-branch fractures, was constructed. Based on this model, the effects of various influencing factors on the conductivity of acid-etched fractures were systematically analyzed.

The study indicates that in complex fracture networks, fracture density, orientation, and length significantly influence conductivity. When the fracture density is high, the interconnectivity between fractures is greatly enhanced, forming an efficient flow network that substantially improves overall conductivity. Additionally, when the fracture orientation is parallel to the main fluid flow direction, the fractures provide the shortest and most unobstructed flow paths, achieving maximum conductivity. In contrast, when the fracture orientation is perpendicular to the flow direction, the contribution of the fractures to conductivity is significantly reduced, serving only a limited auxiliary role at fracture intersections or within the fracture diffusion range. Meanwhile, long fractures enhance overall reservoir conductivity by connecting more reservoir regions, whereas short fractures struggle to connect distant reservoir areas, resulting in poorer localized conductivity.

The complex fracture conductivity calculation model proposed in this study is more closely aligned with field conditions and holds significant value for the design and optimization of acid fracturing in reservoirs with well-developed natural fractures, addressing a critical gap in existing research.

How to cite: Zhang, L., Guo, X., Huang, Z., and Zhou, T.: Investigation on the Conductivity of Complex Acid-Etched Fractures Based on Large-Scale Mine Acid Fracturing experiments, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-14711, https://doi.org/10.5194/egusphere-egu25-14711, 2025.

Fibrous veins are frequently observed in organic-rich shales in sedimentary basins worldwide. The formation mechanism of these fibrous veins remains a subject to debate. This study, based on core and microscopic observations, and employing techniques such as XRD, SEM, EPMA, fluid inclusions, stable isotopes, and rock pyrolysis, investigated the fibrous calcite veins in the Eocene of the Dongying Sag, Bohai Bay Basin, and analyzed the main controlling factors for their emplacement. The fibrous veins are bed-parallel, consisting of parallel aligned, fibrous calcite crystals. The median zone is composed of granular calcite containing wall-rock fragments and bitumen. The fluorescence colors of hydrocarbon inclusions in the fibrous veins are mainly orange-yellow, yellow, and yellow-green, with homogenization temperatures (Th) closely ranging from 74.5℃ to 86.4℃. The δ¹³C_VPDB values of the fibrous veins and the wall-rocks are between -2.37‰ and -5.02‰ and between -2.31‰ and -3.97‰ respectively, while the δ¹⁸O_VPDB values are between -9.59‰ and -11.56‰ and between -6.70‰ and -9.75‰. Our results suggest that the fibrous veins were formed through the combined effect of hydrocarbon-generation-induced overpressure and crystallization pressure. The hydrocarbon generation-induced overpressure drives the opening of the vein to form the middle zone. The fibrous crystals grow in an antitaxial direction from the middle zone towards the wall rock. They grow continuously driven by the chemical potential gradient as the vein forming materials diffuse and migrate from the wall rock to the vein surface.  Bedding, TOC, and mineral composition are the controlling factors for the formation and development of the fibers. fibrous veins are more likely to form in intervals dominated by carbonate minerals, with high TOC (＞2wt.%) and well-developed laminations.

How to cite: Li, T. and Meng, Q.: Calcite beef veins in oil shale, Bohai Bay Basin, China , EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-14855, https://doi.org/10.5194/egusphere-egu25-14855, 2025.

The oil and gas extraction industry is at the forefront of today’s energy transition, balancing the need to meet global energy demands while addressing the urgent challenge of reducing greenhouse gas (GHG) emissions. There were 12,874 oil and gas fields in operation worldwide between 2010 and 2021, with a significant aggregation of large GHG emitters. The key drivers and characteristics of GHG emissions in the global oil and gas extraction industry (considering resource type, geolocation, and decision-makers) remain poorly understood, yet are crucial for identifying key emitters and supporting targeted emission reductions. Here, we developed a field-level time-series global inventory of GHG emissions from oil and gas production to evaluate the emission reduction potential of key contributors from 2010 to 2021. Our findings reveal that 55.9% of cumulative emissions are financed by investors from high-income countries, though since 2014, lower-income countries have increasingly self-funded their emissions. Just 20 fields (0.2% of all fields) are responsible for 21.2% of cumulative emissions, located primarily in the Middle East & North Africa and Other Europe & CIS regions. These key emitters, primarily backed by high-income investors, are characterized by aging infrastructure and high depletion ratios, contributing to high carbon intensities. Our results highlight the importance of tailored, field-specific measures—considering geolocation, resource type, field age, and terrain—to achieve substantial, targeted reductions in global oil and gas emissions.

How to cite: Lei, T. and Guan, D.: Greenhouse gas emissions from global oil and gas fields: Field-level inventory and analysis of key drivers, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5240, https://doi.org/10.5194/egusphere-egu25-5240, 2025.

The ever-expanding oil refining sector, a significant source of industrial emissions, is pursuing decarbonization aligned with the 1.5-degree climate change goal. Despite the discussion at national and global levels, the success of implementation hinges on technically and economically feasible mitigation action at individual plants. Here we develop a plant-level low-carbon pathway model for the oil refining industry by integrating the operating details of refineries (plant status, processing units, age, configuration, etc) and dynamic costs of low-carbon technologies. We find that global oil refining industry can achieve substantial decarbonization through carbon capture and storage technologies (CCS) and clean hydrogen production technologies, concentrated on deep conversion refineries. The large differences in the distribution of age and configuration of refineries across regions lead to heterogeneous decarbonization pathways. In China, 57.6%~58.6% of mitigation costs for deep conversion refineries are associated with decarbonization technologies on furnaces and boilers, especially oxy-combustion CCS, while in the United States, over 40% of mitigation costs for such refineries are linked to biomass gasification. Consequently, mitigation costs per ton of CO₂ for deep conversion refineries in the United States are only 68.6%~74.8% of those in China. Simultaneously shortening the retrofitting cycle and using bio-crude oil can further enhance cumulative mitigation by 52.6 Gigatonnes and achieve negative CO₂ emissions in the oil refining industry. Our results provide cost-effective insights into the diverse and feasible mitigation strategies of individual refineries and accelerate climate action.

How to cite: Ma, S., Meng, J., and Guan, D.: The plant-level decarbonization pathways and mitigation cost of global oil refineries, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-307, https://doi.org/10.5194/egusphere-egu25-307, 2025.

Time-lapse seismic monitoring of CO2 geological sequestration activities is a crucial process to ascertain continued containment and conformance of CO2 within the subsurface storage site. Time-lapse seismic monitoring produces a 3D image of the injected CO2 plume within the subsurface, helping to identify CO2 migration pathways and determine if and where leakage has occurred. Planning a time-lapse seismic campaign is a site-specific process that involves a multidisciplinary effort in building geological computational models, reservoir fluid flow simulations and time-lapse seismic modelling. It is a common workflow in oil and gas production activities and can be redeployed for CO2 geological sequestration. However, CO2 storage involves fluid physics processes that are more complex than most oil and gas conditions, which requires the use of specific physics models to properly predict fluid flow and seismic monitoring behaviour. These complexities are mainly related to the fact that CO2 is highly miscible in formation water, oil and hydrocarbon gas. For this reason, compositional fluid flow simulations must be used to model CO2 injection, rather than the simpler black-oil fluid models more commonly used for oil and gas production. Current commercial reservoir simulators are well capable of such complex simulations. However, this dissolution process must also be modelled in detail in the seismic modelling workflow, and this is largely neglected in time-lapse seismic feasibility studies. We first present a workflow for taking CO2 dissolution processes into account in time-lapse seismic modelling. Then we present a full time-lapse feasibility workflow applied to two different North Sea reservoirs, a saline aquifer and a depleted hydrocarbon gas reservoir. We show the importance of taking such detailed physics processes into account in these two different storage situations. As well as show the importance of time-lapse seismic feasibility studies for planning CO2 monitoring campaigns, in order to achieve the desired objectives and necessary requirements to verify CO2 containment and conformance.

How to cite: Côrte, G., Kopydlowska, B., Toh, S. Y., Landa, J., Pickup, G., Heidari, H., and MacBeth, C.: Time-lapse seismic feasibility studies for planning CO2 geological sequestration monitoring campaigns, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13505, https://doi.org/10.5194/egusphere-egu25-13505, 2025.

Urbanization and its associated energy demands are among the critical challenges of our time, emphasizing the need for innovative and sustainable strategies. A deep understanding of the energy performance of the building stock, particularly through the analysis of building age, is essential. Building age not only reflects insulation properties but also plays a central role in energy models that guide decision-making processes. However, the lack of data on this parameter remains a widespread obstacle.

This study aims to address this gap by developing a semi-automatic methodology that combines georeferencing and classification of historical maps to extract and analyze data on building characteristics. The city of Parma serves as a case study, where maps from the Italian Istituto Geografico Militare (IGM), often overlooked, are revitalized through digital tools to reveal historical urban transformations. Using GRASS GIS software, the proposed workflow segments and classifies cartographic data, filtering textual annotations, boundaries, and roads in order to isolate built structures and estimate their construction periods.

In this context, these maps offer a window into past urban landscapes, allowing us to trace their evolution and extract meaningful information about the energy characteristics of the building stock.

The proposed approach provides critical insights into urban energy systems by bridging historical and modern datasets, supporting the development of sustainable energy models. Through the application of multidisciplinary techniques, this research contributes to a deeper understanding of urban energy dynamics, aiming to address economic, environmental, and social challenges.

Keywords: Energy efficiency, Building stock, Building age, GRASS GIS, Historical maps, Cartographic classification, Multidisciplinary approach, Urban transformation

How to cite: Dalle Vedove, L., Dalle Nogare, G., Dalla Vecchia, C., and Vigato, T.: Mapping Building Age for Sustainable Urban Energy Systems: Georeferencing and Classifying IGM Maps with GRASS GIS, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-11770, https://doi.org/10.5194/egusphere-egu25-11770, 2025.

The Jeanne d’Arc Basin, within the Grand Banks of offshore Newfoundland and Labrador, Canada, holds prolific oil and gas fields and is currently being assessed for its CO₂ sequestration potential. Several factors, including the presence of existing infrastructure from conventional energy production, volume of available datasets, and favourable geologic conditions for storage, make the Jeanne d’Arc Basin and sequestration target areas in the basin attractive as CO₂ injection sites. We are assessing subsurface geologic conditions in areas of interest for CO₂ sequestration to determine the geologic risks and benefits of a variety of targets.

The target strata for CO₂ sequestration in this assessment are predominantly in post-rift sequences, sedimentary units that have not experienced complex extensional stress regimes and that mostly lack delineated vertical fluid flow pathways. However, a major consideration for targeting potential sequestration formations is understanding how sequestered fluids will behave and identifying possible migration pathways within and between the reservoir units. Understanding how the subsurface changes on a fine scale may become important for ongoing assessments, target ranking, and injection strategies. However, well data constraints are not distributed uniformly across the basin and seismic data are often too coarse to capture the fine details of the subsurface or are non-unique.

This presentation documents factors that we are considering for geologic assessment of the CO₂ storage potential in the Jeanne d’Arc Basin, such as changes in depositional regimes, fluid migration pathways (both vertical and horizontal), stress regimes and data quality/coverage. We also discuss the uncertainties and potential risk mitigation for storage targets.

How to cite: Waghorn, K., Welford, J. K., Sinclair, I., and James, L.: Assessing Geologic Uncertainty of CO2 Sequestration Targets in the Jeanne d’Arc Basin, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5266, https://doi.org/10.5194/egusphere-egu25-5266, 2025.

This study explores the concept of an innovative underground storage facility for liquefied natural gas (LNG), utilizing repurposed post-mining shafts. The design incorporates segmental cryogenic tanks, enabling safe and efficient storage of LNG in a structurally optimized environment. This facility also serves as a potential regional transshipment hub, supporting gas distribution to southern Poland and neighbouring countries, while leveraging existing mining infrastructure.

Key technical aspects of the design include the adaptation of abandoned shafts, the installation of reinforced concrete foundations to support substantial loads, and the placement of cryogenic tanks within self-supporting steel frames. The study addresses technical challenges such as shaft geometry constraints, geomechanical stability, and thermal management for cryogenic conditions.

The storage system offers significant capacity over 2000m³, with a single shaft section accommodating LNG volumes equivalent to dozens of transport tankers. This concept demonstrates the technical and economic benefits of reusing mining infrastructure, including reduced construction costs and maximized spatial efficiency. Moreover, it aligns with the principles of sustainable development and supports the just transition of post-mining regions.

How to cite: Kołodziej, K. and Lutyński, M.: Innovative Use of Mining Infrastructure: LNG Storage in Repurposed Shafts, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-17869, https://doi.org/10.5194/egusphere-egu25-17869, 2025.

Geologically known for its ability to host significant oil and gas reserves in Northeast India, the Upper Assam Basin is a category-I petroliferous basin.  The study is aimed to utilise geothermal energy extraction of the Lakadong+Therria Formation in the Upper Assam Basin's depleted hydrocarbon wells.  The wells have recorded high bottomhole temperatures (BHTs) ~90 to 130 ̊C within the depth range of 3579 m to 4603 m. The feasibility of harnessing geothermal energy from these wells with high BHTs and correspondingly high geothermal gradient (>0.024 ̊C/Km) in the Lakadong+Therria Formation, is assessed in this work. The Monte-Carlo simulation study was performed to assess few wells with high heat flux in terms of stored Heat-in-Place (H.I.P), with the cumulative geothermal potential of 15.5*10^14 J.   The study would enable a comprehensive understanding to implement different geothermal energy extraction technologies to determine the viability of pilot-scale operations in the Upper Assam basin for electricity production or other greenhouse gas or district heating applications. This could start the energy transition pathway in the basin from fossil-based resources to low-carbon emission resources.

How to cite: Dutta, A. J., Mishra, C., Gogoi, N., and Kulkarni, S. D.: A Study on Geothermal Energy Production in Depleted Hydrocarbon wells of Upper Assam Basin India, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-21860, https://doi.org/10.5194/egusphere-egu25-21860, 2025.