Accumulations of large volumes of CO2 related to mantle degassing, metamorphic reactions or magmatic processes have been found in many oil-gas bearing basins around the world . The Huangqiao area of the Lower Yangtze Plate hosts the largest CO2 gas field on mainland China. Throughout geological history, a significant influx of deep mantle-derived CO2 fluid occurred in this area. Understanding the timing of these CO2 charge and their effects on crude oil reservoirs is crucial for interpreting the distribution of present-day resources. The Cenozoic was long believed to be the only period during which CO2 charging occurred in the Huangqiao area, primarily because evidence of earlier CO2 fluid charges had been scarce. To address this, a comprehensive study utilizing petrography, cathodoluminescence, fluorescence and Raman spectrum of fluid inclusions, in-situ U-Pb dating, and basin modeling was conducted to elucidate the timing and interactions between crude oil and deep mantle-derived CO2 in the Permian Qixia Formation of the Huangqiao area. Three distinct phases of calcite veins were identified and dated: 251.7 ± 1.8 Ma, 124.16 ± 1.46 Ma, and 97.68 ± 1.20 Ma to 96.75 ± 0.25 Ma. The earliest CO2 charge, occurring around 251.7 ± 1.8 Ma, corresponds to a period when supercritical CO2 extracted low molecular-weight hydrocarbons from the S1g source rock. This timing aligns with the mass extinction event (251.4 ± 0.3 Ma), a rapid rise in atmospheric CO2 levels, and volcanic activity in the Permian Gufeng and Longtan Formations of the Lower Yangtze Plate, suggesting that the CO2 influx was volcanically driven. Between 124.16 ± 1.46 Ma and 96.75 ± 0.25 Ma, significant portions of the CO2 and crude oil within the Qixia Formation escaped due to tectonic uplift and erosion associated with the collision between the Yangtze Plate and the North China Plate. This research provides the first documentation of early mantle-derived CO2 fluid charges and their role in crude oil extraction from source rocks during transport from the mantle to the Earth's crust. Additionally, the study reconstructs the processes of CO2 and oil accumulation and leakage from the Indosinian to the Yanshanian periods, offering new insights into the evolution of hydrocarbon reservoirs in the Huangqiao area of Lower Yangtze Plate.
How to cite: Chen, J., Guo, X., and Huang, Y.: Calcite U-Pb dating and fluid inclusions reveal late Permian deep mantle CO2 fluid activity in the East China basin and its effect on crude oil within source rock: A case study from Huangqiao area of Lower Yangtze Plate, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7585, https://doi.org/10.5194/egusphere-egu25-7585, 2025.
The Sichuan Basin is a superimposed basin in southwestern China, primarily consisting of marine craton and foreland basin stages. Many sets of organic-rich shales have been deposited, enriching natural gas resources due to their high levels of thermal maturity. The Sichuan Basin has experienced multi periods of tectonic uplift event, accompanied with multiple hydrocarbon accumulation and phase transitions processes in the deep and ultra-deep reservoirs. The formation of paleo-oil reservoir plays an important role in the distribution of present-day gas fields, yet many records of early oil reservoirs have been destroyed. A series of methods including, petrography, cathodoluminescence, fluid inclusion, in-situ U-Pb geochronology, and basin modeling, were used to determine the multistage oil charge process in the Ediacaran Dengying Formation of the Weiyuan area, SW Sichuan Basin. The lace-like dolomite lamination and three stages of dolomite cement were petrographically, and geochronologically distinguished in the Dengying Formation, dated at c. 542 Ma, 486 ~ 482 Ma, 410 Ma, and 270 Ma, respectively. Three stages of bitumen in the Dengying reservoir indicated three episodes of oil charge. The first and second oil-charging events occurred at 500 ~ 486 Ma and 410 ~ 400 Ma, by combining the modeled timing of oil generation with mineral ages of the two generations before and after the solid bitumen. The modification of the Weiyuan paleo-oil pool occurred during the Caledonian tectonic uplift, after the second oil-charging event. The timing of the third oil charge was at 270 ~ 230 Ma, according to the Th value of aqueous inclusions coeval with secondary bitumen inclusions in the stage 3 dolomite cement (CD-3), close to the timing of main oil generation for the Lower Cambrian source rocks. The first oil charge may be a contribution from the Doushantuo source rock, and the Lower Cambrian source rocks provide the major contribution for the third oil charge. This research reveals the timing of multistage oil charging events in the southwest Sichuan basin, and provides a further method for determining the timing of oil charge in multi-cyclonic composite basins.
How to cite: Luo, T. and Guo, X.: Determination of multistage oil charge processes in the Ediacaran Dengying gas reservoirs of the southwestern Sichuan Basin, SW China, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-6758, https://doi.org/10.5194/egusphere-egu25-6758, 2025.
Natural gas as a viable alternative to reducing dependence on coal and oil in the process of energy restructuring and carbon neutrality goals. The efficient development of tight sandstone gas requires accurate evaluation of reservoir fracability and selection of layers and segments for fracturing. This study takes the tight sandstone in T area of Sichuan Basin, China as the research object. To achieve the fracturing goal of constructing a complex artificial fracture network, the key parameters affecting the comprehensive fracability of the reservoir are selected based on the fusion analysis of geological, logging, seismic, geomechanical, and microseismic monitoring information. In addition, the weights of each influencing factor are also clarified. The evaluation model of reservoir comprehensive fracability index and the grading evaluation standard of engineering sweet spot are constructed. Combined with geological framework, logging data, seismic attributes, and geomechanical 3D models, the longitudinal and spatial distribution characteristics of reservoir fracability and engineering sweet spot are analyzed. The research results show that high brittleness index, low horizontal minimum principal stress, high fracture density, low horizontal stress difference, low elastic modulus, and high Poisson's ratio are the key of "high sweetness value" of engineering sweet spot in the study area. The evaluation model of comprehensive fracability index (FI) of reservoir is established based on these six key indicators. The brittleness index, horizontal minimum principal stress, and fracture density are the three most critical factors identified by grey correlation method. The results of reservoir comprehensive fracability logging prediction and 3D comprehensive fracability field prediction show that the comprehensive fracability of the reservoir in the study area is non-uniform in the longitudinal, transverse, and spatial distribution, which can provide support for the selection of high fracability intervals and engineering sweet spots.
How to cite: Wan, Y., Liu, X., Liang, L., and Jing, R.: Fracability analysis and comprehensive evaluation of engineering sweet spot of tight sandstone gas reservoir in T area of Sichuan Basin, China, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13692, https://doi.org/10.5194/egusphere-egu25-13692, 2025.
Overpressure is a common feature in the Huangliu Formation of the Ledong Slope Zone, Yinggehai Basin, with pressure coefficients reaching up to 2.31. In this study, overpressure mechanisms in mudstone intervals of the Huangliu Formation (Upper Miocene) are investigated and their importance reconstructed in time. Acoustic and resistivity logs reveal characteristic responses to overpressure in mudstones, leading to its accurate prediction. As a result, this study shows that hydrocarbon generation is responsible for the recorded overpressures as proven by several lines of evidence. First, overpressured mudstones in the Huangliu Formation have anomalously high acoustic and low resistivity values. Low density values are not recorded suggesting that disequilibrium compaction is not responsible for the observed overpressure. A positive correlation is also lacking amongst vertical effective stress, acoustic velocity and density values - overpressured mudstones recording low effective stress and high density – a character indicating that overpressure is mainly caused by fluid expansion. Overpressured mudstones deviate from the normally loading curve and fall on the unloading curve. Secondly, overpressured mudstones are buried at depths above 3300-4300 m, and subjected to formation temperatures of 135-200℃. Corresponding vitrinite reflectance equivalents are 0.7%-1.3%, supporting that mudstones are in the oil generation window and generate large quantities of hydrocarbons. Overpressured reservoirs are also charged by gas/water mixtures and gas; overpressure among these reservoirs is attributed to pressure transfer during gas charge. Thirdly, the depth for transformation of clay types do not correlate with overpressure generation in the mudstones, suggesting that clay transformation is not the main mechanism promoting local overpressures. Models of maturity and hydrocarbon generation history for the study area show that the source rocks within the Huangliu Formation started to become overpressured at 3.5 Ma and that pore pressure is still increasing. Overpressure increased rapidly between 2.5 Ma and 1.0 Ma, and modelling results are consistent with the present-day values recorded on acoustic logs. For different types of inclusions, we established different paleo-pressure restoration model to quantitatively recover the trapping pressures of reservoir fluid inclusions. The reconstructed paleo-pressures for the four stages of natural gas charging are 29.5 – 41.5 MPa, 45.03 – 47.94 MPa, 35.0 – 100.7 MPa, and 97.22 – 104.31 MPa, with the paleo-pressure coefficients of 0.84 – 1.19, 1.31 – 1.39, 1.41 – 2.32, and 2.38 – 2.56, respectively. Quantitative models further indicate that the mudstones of interest can generate large quantities of hydrocarbons at present to maintain the recorded pore overpressures.
How to cite: Zhang, X. and Guo, X.: Mechanisms and evolution of overpressure for Miocene Huangliu Formation in the Ledong Slope Belt,Yinggehai Basin, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-8025, https://doi.org/10.5194/egusphere-egu25-8025, 2025.
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.
Veins featured by heterogeneous mineral components compared to the host rock are thought to give rise to the heterogeneous stress and strain during rock deformation, thereby impacting rock fracture behavior. To study the influence of veins on the mechanical and fracturing behavior of shale reservoir rocks, a series of triaxial compression tests were performed on different shale samples at room temperature and a constant confining pressure of 30 MPa. Samples contained either carbonate-rich veins or were vein-free. For the characterization of local strain within veins and host rock and the evolution of micro-fracturing during bulk sample deformation, we employed local strain gauge measurements, ultrasonic P-wave velocities, and acoustic emission monitoring. The peak stresses of bulk samples containing veins are generally lower, compared to their vein-free counterparts. For the samples with a vein, the spatiotemporal distribution of AE activity shows that fracturing was initiated in the vein, consistent with a pronounced decrease in the trace of P-wave velocity traveling through the vein. The final trajectory of fracture was either confined within or through the vein. We attributed this contrasting behavior to the varying vein geometry and the mechanical contrast of elastic moduli between the vein and host rock. This study underscores the role of veins in determining shale rock mechanical properties and fracturing behavior, which is important for the treatment of unconventional reservoirs and other relevant rock engineering projects.
How to cite: Chen, S., Wang, L., Rybacki, E., bonnelye, A., Wang, H., Zhou, T., Zeng, H., and Li, F.: Effects of veins on mechanical deformation and fracturing behavior of shale rocks under triaxial compression stress states: Insights from local strain measurements, P-wave velocities and acoustic emission activity, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-19466, https://doi.org/10.5194/egusphere-egu25-19466, 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 δ13CVPDB 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 δ18OVPDB 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.
In the development of tight oil reservoirs, wettability determines the distribution and flow behavior of oil and water during reservoir development and enhanced oil recovery. However, accurately assessing wettability is highly challenging due to the strong heterogeneity of the mineralogy and pore structures in tight sandstone reservoirs and the complex interactions between minerals and fluids. Traditional studies often focus on the average wettability evaluation at the macro scale; however, such local bulk wettability often overlooks the inherent micro- and nanoscale heterogeneities of tight oil reservoirs. They thus cannot properly represent the true wettability in highly heterogeneous and low-permeable tight sandstones. In this study we employed a multi-scale comprehensive approach to evaluate reservoir wettability of an Eocene tight sandstone reservoirs from the Bohai Bay Basin. An environmental scanning electron microscopy was firstly used to determine wettability at the pore scale through analyzing the condensation patterns of water vapor on pore walls. Contact angle measurements were then employed to quantitatively assess the mesoscopic wettability characteristics of tight sandstone surfaces. Finally, a combination of Nuclear Magnetic Resonance and spontaneous imbibition experiments were carried out to evaluate the distribution characteristics of oil and water across different pore sizes and determine the overall wettability of samples. We have found that significant fractional wettability and mixed wettability are present in the tight oil sandstones. Different minerals and various parts of individual minerals can exhibit distinct wettability characteristics. The fractional wettability of tight sandstone is primarily influenced by clay mineral types and morphology; grain-coating illite and grain-coating chlorite tend to show oil-wet characteristics, while dispersed sheet-like chlorite and rosette chlorite are more likely to be water-wet. The mixed wettability in tight sandstones is mainly controlled by pore sizes: for oil-wet samples, pores larger than 0.1 μm are generally oil-wet, while those smaller than 0.1 μm are predominantly water-wet. For water-wet samples, the pore-size threshold between oil-wet and water-wet pores is around 1 μm. The wettability of tight sandstone reservoirs in the study area is primarily controlled by pore sizes ranging from 0.1 μm to 1 μm. This finding provides critical pore size thresholds for accurately describing reservoir wettability characteristics and is essential for understanding and predicting fluid behavior within tight oil reservoirs. The integrated multi-scale method proposed here allows a more precise and reliable wettability assessment, offering a viable workflow for wettability evaluation of tight oil reservoirs.
How to cite: Chen, J. and Liu, K.: Scale-dependency Wettability of Tight Sandstone: Insights from an Eocene fluvial sandstone reservoir in the Bohai Bay Basin, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-109, https://doi.org/10.5194/egusphere-egu25-109, 2025.
The structure of coal bodies is the product of brittle or ductile deformation in coal reservoirs under tectonic stress, serving as a crucial parameter influencing pore distribution characteristics, permeability, adsorption-desorption capacity, and mine safety in coal reservoirs. It holds significant research importance for the exploration and development of coal resources and coalbed methane (CBM). Under stratigraphic temperature and pressure conditions, the chemical structure and physical properties of coal reservoirs undergo corresponding deformation and evolution, leading to changes in the stress field surrounding the coal reservoir, as well as alterations in coal rock strength, pore characteristics, adsorption-desorption capacity, and permeability. Seismic data encompasses various attributes such as amplitude, frequency, and phase, with distinct differences in rock physics attributes among different coal body structures, which are closely related to seismic attributes. Through multi-attribute analysis, seismic attributes associated with coal body structures can be extracted. Machine learning is capable of processing and interpreting the nonlinear relationships between vast amounts of seismic data and rock physics attributes. By establishing a coal body structure prediction model based on machine learning technology, the accuracy of coal body structure predictions can be enhanced, allowing for an understanding of the distribution characteristics of tectonic coal in the study area and providing a reference for CBM (methane) extraction, thereby effectively improving the efficiency of CBM (methane) mining.
How to cite: Wang, X., Tian, F., Sadik, A., Yuan, X., and Yang, Z.: Study on Coal Body Structure Prediction Method Based on Machine Learning and Multi-Attribute Seismic Data Integration, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-4939, https://doi.org/10.5194/egusphere-egu25-4939, 2025.
Large-scale methane releases from geological hydrocarbon seepage and the dissociation of subseafloor gas hydrates under shallow waters are important drivers of atmospheric methane concentration increases and global warming. However, the processes, timescales, and fluxes involved in such emissions remain insufficiently constrained. In this study, we redeploy historic oil and gas industry datasets—including well logs, seismic data, as well as reservoir temperature and pressure data—to reveal reservoir-scale methane leakage, storage and release dynamics in the Håkjerringdjupet area at the offshore continental margin of Norway beneath the past Fennoscandian ice sheet during the last glacial maximum.
Our numerical approach considers glacial loading causing the overpressurization of a shallow gas reservoir, driving the expulsion of methane-rich fluids through faulted zones and into subglacial sediments. Glacially-driven pressure increments led to extensive methane hydrate formation within these sediments, storing carbon and significantly improving basal traction. Laboratory shear-strength measurements (Spangenberg et al., 2020), integrated with subglacial hydrate formation modelling (Li et al., 2022, 2023), indicate a minimum hydrate saturation to regulate glacial flow, with the subglacial hydrate system storing ~0.48 Gt of methane in Håkjerringdjupet. During deglaciation, we estimate that ~120–240 Tg of methane released by hydrate dissociation may have reached the atmosphere shortly after the last glacier retreated (about 16,000 years before the present).
Our findings highlight how legacy industry well data and conventional oil and gas technologies can be harnessed to advance understanding of subglacial carbon storage and fluid migration in response to climate change. Our work provides an insightful Pleistocene analogue for studying contemporary ice-sheet-driven methane storage and release, informing strategies for sustainable carbon management in the transition towards net zero emissions.
References:
Li, Z., Spangenberg, E., Schicks, J. M., and Kempka, T.: Numerical Simulation of Coastal Sub-Permafrost Gas Hydrate Formation in the Mackenzie Delta, Canadian Arctic, Energies, 15, 4986, https://doi.org/10.3390/en15144986, 2022.
Li, Z., Chabab, E., Spangenberg, E., Schicks, J. M., and Kempka, T.: Geologic controls on the genesis of the Arctic permafrost and sub-permafrost methane hydrate-bearing system in the Beaufort–Mackenzie Delta, Front. Earth Sci., 11, 1148765, https://doi.org/10.3389/feart.2023.1148765, 2023.
Spangenberg, E., Heeschen, K. U., Giese, R., and Schicks, J. M.: “Ester”—A new ring-shear-apparatus for hydrate-bearing sediments, Review of Scientific Instruments, 91, 064503, https://doi.org/10.1063/1.5138696, 2020.
How to cite: Li, Z. and Kempka, T.: Quantifying past subglacial methane storage and emissions under the Fennoscandian ice sheet by means of historic data from hydrocarbon industry, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-9227, https://doi.org/10.5194/egusphere-egu25-9227, 2025.
GEOMODELATOR is a Python-based Open Source software package for translation of static geologic models into regular structured simulation grids considering element partitioning by complex model geometries (Nakaten, 2024; Nakaten and Kempka, 2023). In view of the vast legacy data available from geologic and hydrocarbon exploration, it provides a basis for site-specific assessments of geologic subsurface utilisation in terms of risk assessments, as well as operational design and optimisation.
We have further developed the GEOMODELATOR software package to fit into a modular client-server based architecture for a more robust modelling workflow, which allows to transfer heavy computational workloads to dedicated servers providing adequate resources and memory. Consequently, models with high grid element counts can be developed on low-memory client systems like laptops. Furthermore, a Graphical User Interface (GUI) has been developed to allow modellers to implement static models and directly review the results without the need for data conversion for its visualisation in third-party software packages such as Paraview (Utkarsh, 2015).
The present contribution shows the application of GEOMODELATOR to generate a numerical grid for a simulation study on fluid flow and halite transport to account for potential impacts of geologic subsurface utilisation.
References:
Nakaten, B. (2024): GEOMODELATOR - A python library to generate simple structured 2d+ and 3d cell-based VTK models/files. V. 1.0. GFZ Data Services. https://doi.org/10.5880/GFZ.3.4.2024.003
Nakaten, B., Kempka, T. (2023): GEOMODELATOR – from static geologic models to structured grids for numerical simulations, EGU General Assembly 2023, Vienna, Austria, 24–28 Apr 2023, EGU23-2016, https://doi.org/10.5194/egusphere-egu23-2016
Utkarsh, A. (2015): The ParaView Guide: A Parallel Visualization Application, Kitware Inc., United States.
How to cite: Nakaten, B., Chabab, E., and Kempka, T.: GEOMODELATOR reloaded – now with GUI and client-server architecture, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-10442, https://doi.org/10.5194/egusphere-egu25-10442, 2025.
The ongoing structural transformation from the hydrocarbon industry to sustainable green energy is one of the challenges Europe is facing recently.In Germany, there are about 15,000 boreholes with depths ≥ 400 m (deep wells).Transgeo, a transnational project funded by the EU-program Interreg, aims to identify the potential of such boreholes for geothermal energy extraction in Germany and four other Central European countries.One of the main aspects of the project is the collection of data from deep wells, which will then be compiled into databases and fed into a web-based IT tool to demonstrate to potential investors the possible deep wells for geothermal energy extraction.The reuse of old boreholes, especially former oil or gas wells, is particularly attractive, as it can potentially reduce the costs of otherwise very costly geothermal drilling while making use of existing infrastructure.
The deep drillings in the eastern part of the North German Basin are mostly several decades old, as economic independence was sought especially during the GDR era and great efforts were put into the exploration and mapping of national raw material deposits. Hence, several comprehensive studies and data collections are still available in the archives. The value of analyses of taken samples, measured parameters, among other things is priceless. Such data is the basis for modelling, and also for the validation of existing models. Parameters here displayed, include temperature, porosity and permeability in identified pay zones within formations interesting for geothermal energy extraction. Also, the technical data about the borehole construction, as well as the detailed information about the location of cement bridges (abandoned wells), and geological or technical issues during, or after the drilling process are crucial, if considering a reuse or planning a new drilling project nearby an existing borehole.
How to cite: Sieron, K., Weinert, S., Vogel, F., and Hoeding, T.: Re-evaluation of data from old deep boreholes with the aim of possible reuse for geothermal energy – advances in the TRANSGEO project, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-19652, https://doi.org/10.5194/egusphere-egu25-19652, 2025.
Geothermal energy has gained significant attention over the years as a renewable alternative to traditional fossil fuel energy systems. Non-producing oil and gas wells may be repurposed as geothermal wells for heating or electricity generation. Converting non-producing oil and gas wells into geothermal energy production can offset the costs of drilling new geothermal wells and provide an incentive for remediating non-producing well sites. However, the absence of regulations for geothermal well conversion in North America and Europe leaves many unresolved questions about the ownership and financial responsibility of the wells. Here, we present an analysis of non-producing well attributes, such as depth, location, type, and proximity to geothermal boreholes, and well integrity indicators, including methane emission measurements and surface casing vent flows, to identify suitable sites for geothermal energy conversion in the United States and Canada. We also explore various case studies of geothermal well conversion from around the world, comparing different geothermal systems and their applicability to Canada. The findings from this research will be useful in supporting policy development and regulatory frameworks for geothermal conversion projects in Canada, the United States, and around the world.
How to cite: Lamarche, B., Boutot, J., Prado, P., Zolfagharroshan, M., Vyriotes, D., Fogwill, A., Muehlenbachs, L., Sasmito, A., and Kang, M.: Converting Non-Producing Oil and Gas Wells for Geothermal Energy Production, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13332, https://doi.org/10.5194/egusphere-egu25-13332, 2025.
The decarbonization of communities and their energy supply is considered as a contemporary priority, although it poses many challenges. In this scenario, geothermal energy can cover a pivotal role in the energy transition and the possibility of reusing or modifying existing wells for geothermal purposes is becoming a hot and promising topic. In Italy for example, there are more than 4000 abandoned/inactive hydrocarbon wells, abandoned either for the end of the resource (exhausted well), or for the lack of finding the resource (barren well).These wells can represent a huge opportunity for geothermal resource exploration and exploitation, as historical well data can provide useful information on the underground conditions, reducing mining risk, and sometimes allow a direct access to the sub-surface heat energy.
This work aims to analyse the feasibility of retrofitting abandoned oil and gas wells to understand which the benefits of reusing old wells are compared to drilling new ones.
A finite element numerical model of a deep U-shape closed-loop Borehole Heat Exchanger (BHE) was implemented to evaluate the performance and efficiency in terms of energy production of this solution. Sensitivity analysis allows highlighting the main operational and environmental parameters involved in the heat exchange processes between the working fluid and the surrounding reservoir rocks, and particularly to quantify how the variation of design and geological parameters influences the outcome temperature of the working fluid and thus the energy efficiency and production of the BHE system.
After an initial round of simulations using purely conductive models, we investigated the potential for convective heat transfer within a geothermal reservoir, considering both porous and fractured media. Using the Nelson Diagram as a foundation, we assessed various permeability/porosity ratios to better understand how the interplay of these parameters influences system efficiency. Specifically, we explored whether fluid circulation within the reservoir enhances heat exchange over long-term simulations, potentially leading to improve system performance, particularly following extended periods of geothermal source exploitation.
How to cite: Facci, M., Di Sipio, E., Galgaro, A., and Bistacchi, A.: Reusing abandoned oil wells as deep closed-loop geothermal systems: FE multiparametric sensitivity analysis and the role of heat convection in fractured reservoirs , EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-16643, https://doi.org/10.5194/egusphere-egu25-16643, 2025.
Posters virtual: Mon, 28 Apr, 14:00–15:45 | vPoster spot 4
EGU25-2507 | Posters virtual | VPS16
oil and gas reserve prediction method based on Analytic Hierarchy Process and ARIMA algorithm: A case study of the Llanos Basin in South AmericaMon, 28 Apr, 14:00–15:45 (CEST) vPoster spot 4 | vP4.1
Oil and gas reserves are important resources for human survival, directly related to future oil and gas production and the sustainable development and utilization of energy. It is crucial to strengthen the understanding and judgment of the growth trend of oil and gas reserves. The prediction of the growth trend of oil and gas reserves is a forward-looking research work, and its prediction results will directly affect the direction of future oil and gas exploration and investment. To explore new methods for predicting oil and gas reserves, promote sustainable development and utilization of energy, and provide theoretical basis for oil and gas exploration and development. For this purpose, taking the Llanos Basin in South America as an example, combined with comprehensive data such as oil and gas reserve growth data and various geological characteristics, a combination of Analytic Hierarchy Process and ARIMA algorithm was proposed to predict and verify the oil and gas reserves in the Llanos Basin. Firstly, the Analytic Hierarchy Process is used to perform weight analysis on various geological factors in the Llanos Basin. Analysis shows that structural evolution factors have a significant impact on the growth of oil and gas reserves. On this basis, ARIMA algorithm is applied to perform hierarchical prediction verification on each construction unit of Llanos Basin. The results indicate that the combination prediction method has been validated to have good prediction performance.
How to cite: Li, H. and Zhang, L.: oil and gas reserve prediction method based on Analytic Hierarchy Process and ARIMA algorithm: A case study of the Llanos Basin in South America, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-2507, https://doi.org/10.5194/egusphere-egu25-2507, 2025.
Posters virtual: Thu, 1 May, 14:00–15:45 | vPoster spot 4
EGU25-3371 | ECS | Posters virtual | VPS17
The mechanism of differential enrichment of deep oil reservoirs in the southern part of the Panyu 4 depression in the Pearl River Mouth BasinThu, 01 May, 14:00–15:45 (CEST) vPoster spot 4 | vP4.1
In recent years, deep-seated hydrocarbon reservoirs have gradually become the focus of exploration and development. The distribution of deep-seated oil reservoirs in the southern part of the Panyu 4 depression in the Pearl River Mouth Basin shows the characteristics of more in the north and less in the south, and uneven in the east and west. The unclear causes of oil differentiation have constrained its exploration. This paper uses a combination of logging, seismic, and physical property data to analyze the reasons for oil enrichment differences from the perspectives of source-reservoir matching, dominant migration channels, and fault activity, and establishes an oil accumulation model.
Research findings indicate that: (1) Based on the matching relationship between hydrocarbon source rocks and reservoirs, the area can be divided three types of well areas: "near-source poor in sand", "near-source rich in sand", and "far-source rich in sand". The northern sand bodies close to the hydrocarbon source rocks and have a large scale, so the oil enrichment degree is relatively high. (2) The fault structure ridges are the preferred channels for lateral oil migration. The oil is more enriched in the well areas near the structure ridge, leading to differences in oil reservoir between adjacent well areas in the east-west direction. (3) The strength of fault activity controls the stratum of oil enrichment in different well areas. In the northern area, the fault activity is strong, and oil is distributed in multiple stratum. In the southern area, the fault activity is weak, and the oil is transported over long distances through the oil source fracture and the sand body of the Wenchang Formation to the high structural parts in the south, where they are trapped in the Wenchang Formation. (4) Based on the aforementioned research, two types of oil accumulation models were established: the "proximal fault multi-layer accumulation model" near the source and the "long-distance stepwise migration and accumulation model" far from the source, along the dominant migration channels. This study has significant guiding implications for the further exploration and development of the Panyu 4 depression oil reservoir.
Key words: Differential enrichment of oil; Source-reservoir matching; Dominant migration channel; Fault activity; Oil accumulation model.
How to cite: Wang, Q., Liu, H., Peng, G., and Long, Z.: The mechanism of differential enrichment of deep oil reservoirs in the southern part of the Panyu 4 depression in the Pearl River Mouth Basin, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-3371, https://doi.org/10.5194/egusphere-egu25-3371, 2025.
