Pressure and stress perturbations associated with volcanic activity and geothermal production can modify the porosity and permeability of volcanic rock, influencing hydrothermal convection, the distribution of pore fluids and pressures, and the ease of magma outgassing. However, porosity and permeability data for volcanic rock as a function of pressure and stress are rare. We focus here on three porous tuffs from the Krafla geothermal system (Iceland). Triaxial deformation experiments showed that, despite their very similar porosities, the mechanical behavior of the three tuffs differs. Tuffs with a greater abundance of phyllosilicates and zeolites require lower stresses for inelastic behavior. Under hydrostatic conditions, porosity and permeability decrease as a function of increasing effective pressure, with larger decreases measured at pressures above that required for cataclastic pore collapse. During differential loading in the ductile regime, permeability evolution depends on initial microstructure, particularly the initial void space tortuosity. Cataclastic pore collapse can disrupt the low-tortuosity porosity structure of high-permeability tuffs, reducing permeability, but does not particularly influence the already tortuous porosity structure of low-permeability tuffs, for which permeability can even increase. Increases in permeability during compaction, not observed for other porous rocks, are interpreted as a result of a decrease in void space tortuosity as microcracks surrounding collapsed pores connect adjacent pores. Our data underscore the importance of initial microstructure on permeability evolution in volcanic rock. Our data can be used to better understand and model fluid flow at geothermal reservoirs and volcanoes, important to optimize geothermal exploitation and understand and mitigate volcanic hazards.
How to cite: Heap, M., Bayramov, K., Meyer, G., Violay, M., Reuschlé, T., Baud, P., Gilg, A., Harnett, C., Kushnir, A., Lazari, F., and Mortensen, A.: Compaction and permeability evolution of tuffs from the Krafla geothermal system (Iceland), EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-2171, https://doi.org/10.5194/egusphere-egu25-2171, 2025.
Effective stress is known to be a key factor affecting permeability measurements under geological conditions. As effective stress increases, the permeability of rock containing micro-fractures will decrease significantly. Based on laboratory measurement data, several scholars have come up with empirical equations to describe permeability changes with effective stress and found that there generally exists an exponential or power-law relationships. In this study, the experimental sample is a tight sandstone formation containing microfractures from Kuche Depression in Tarim Basin, China, where gas is produced from deep reservoirs of over 6000 m. Permeability was measured using the conventional pulse-decay method using an in-house true triaxial stress cell with maximum confining pressure of 120 MPa, pore pressure of 100 MPa and axial pressure of 250 MPa. The tight sandstone contains micro-fracture and an ambient porosity of 5%. Under the condition of high pore pressure (up to 80 MPa), the Knudsen number Kn＜0.01, and the gas slippage effect appears to have little impact on the permeability, characteristic in the Darcy flow state. As the confining pressure increases, the gas permeability decreases significantly, whereas as the pore pressure increases, the gas permeability increases. It has been shown that as the effective stress increases, the gas permeability decreases, and ln(K/K0) shows an exponential relationship with (δ - δ0) (subscript 0 represents the initial state). As the effective stress decreases, ln(K/K0) shows a logarithmic relationship with (δ - δ0). Under the condition of equal effective stress, ln(K/K0) shows a linear relationship with pore pressure. In addition, we have also noticed a strong anisotropy in the permeability when differential axial stress was applied during the permeability measurement, reflecting a preferential distribution of microfractures in the tight sandstone measured.
How to cite: Yu, B., Liu, K., and Yu, L.: Experimental investigation of the relationship between permeability and effective stress for low-permeability sandstone with micro-fractures under high pressure, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7924, https://doi.org/10.5194/egusphere-egu25-7924, 2025.
We constructed a thermo-viscoelasticity equation based on Lord-Shulman (LS) thermoelasticity with the Kelvin-Voigt (KV) model for viscoelasticity. The plane-wave analysis predicts two compressional waves and a shear wave. These two compressional waves are the fast-P and slow-P diffusion/wave (the T-wave), which have similar characteristics to the fast- and slow-P waves of poroelasticity, respectively. To overcome the nonphysical phenomenon of high-frequency P-waves in the thermo-viscoelastic (KV model), we established the thermo-viscoelasticity equation by combining LS thermoelasticity and the Zener and Cole-Cole model of viscoelasticity. Plane-wave analysis predicts two inflection points on the dispersion and attenuation curves; these are mainly affected by thermal diffusion and viscoelasticity. The dispersion curves of both types of P waves have two-level limit velocities of high frequency, and their attenuation curves also feature two attenuation peaks. Selecting appropriate parameters can cause the two-level limit velocities of high frequency and attenuation peaks to move or overlap. Finally, we consider the experiment data of P-wave velocity varying with frequency of two kinds of sandstone. Indeed, a Cole-Cole fractional model is needed to obtain a good match. These results are helpful for studying the physics of thermo-viscoelasticity and for testing experimental data and numerical algorithms for wave propagation.
How to cite: wang, Z., Fu, L., and jose, C.: The behaviour of wave propagation in linear thermo-viscoelastic media, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-2734, https://doi.org/10.5194/egusphere-egu25-2734, 2025.
Porous reservoir rocks like sandstones have gained utmost importance in the last decade as a potential sink for CO2. Most of the targeted reservoirs are depleted oil and gas fields, which have caprocks to ensure the containment of the injected CO2. Injecting CO2 into porous reservoirs increases the pore pressure, reducing the effective horizontal and vertical stresses. Depending on the pre-injection stress condition and permeability of the reservoir, careful monitoring should be in place to define the upper limit of CO2 injection pressure to prevent any permanent damage to the reservoir, which can lead to leakage or induced seismicity. Lab-scale experiments provide key insights into the deformation behaviour of reservoir rocks under different stress conditions, which can be upscaled to understand reservoir-scale processes. To simulate the stress perturbation caused by CO2 injection operations, we have subjected porous reservoir rocks (core plugs) collected from different depths of offshore North Sea under realistic reservoir stress and saturation conditions, with liquid CO2 flow-through leading to failure. The P and S wave velocities along the core plugs were recorded every 15 s to assess the change in wave properties during deformation, fluid displacement and pore pressure build-up. It was observed that during each loading cycle, wave velocities are highest at the elastic-plastic transition zone, which can be attributed to the compression of pores and closure of microcracks perpendicular to the loading direction. The wave velocities and amplitudes decrease sharply after the onset of plastic deformation, which can be attributed to the formation of microcracks in the coreplug due to increasing load. During displacement of brine with CO2, velocities and amplitudes drop sharply. These indicators are used to develop a traffic light scenario for CCS operations to maintain safe stress conditions in the reservoir. The consistent correlation between the wave properties and mechanical response of the reservoir rocks reveals that constant monitoring of wave velocities during CO2 injection can act as a cheaper and more efficient tool for monitoring stress state and plume movement in the reservoir, facilitating safer CO2 storage operations.
How to cite: Chandra, D. and Barnhoorn, A.: Applicability of sonic velocities as a monitoring tool for subsurface CO2 plume migration and associated stress change, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-1802, https://doi.org/10.5194/egusphere-egu25-1802, 2025.
Feldspars are a common framework grain in sandstone reservoirs targeted for carbon capture and storage (CCS). They are mechanically weak under reservoir conditions and are very likely to react with CO2 injected into saline aquifers or depleted hydrocarbon reservoirs. Reactions could dissolve feldspar and precipitate new minerals to an extent that fundamentally changes reservoir properties and potentially mineralises injected CO2. The current general consensus is that these features are unlikely to impact fluid migration during the injection lifespan of any CCS project. However, the response of feldspars to saturation with aggressive CO2-enriched fluids under stressed reservoir conditions is poorly understood.
In this contribution, the magnitude of any “feldspar effect” is re-evaluated using sandstone samples obtained from the Lower Cretaceous Captain Sandstone in the Central North Sea, which is the target reservoir for CO2 injection in the Acorn Project (UK).
Firstly, using petrography, SEM analysis and Pb isotopic compositions of detrital feldspars, sediment provenance and subsequent diagenesis are shown to be significant drivers on feldspar composition and texture prior to injection. This is important because it is already understood that different feldspars react with CO2-rich fluids at different rates: thus any feldspar effect could significantly vary within a reservoir with mixed provenance and burial history on a sub-basin scale. Secondly, we conducted a suite of novel reaction experiments conducted using a triaxial ‘Nimonic’ deformation rig to investigate chemical dissolution in sandstone core plugs saturated with both CO2-enriched fluids and water under subsurface conditions. Experiments were run at CCS reservoir pressures (70MPa confining pressure, 50MPa pore fluid pressure) and a range of temperatures (80°C – 550°C) to accelerate reaction rates and promote geological reactions in a short timescale. Microstructural and elemental analysis of post-mortem experimental samples showed enhanced fracturing and dissolution of certain feldspars along with precipitation of secondary minerals, whereas other feldspars were apparently unaffected. Experiments performed above 400°C showed replacement and dissolution of K-feldspar grains with Ca-rich plagioclase and K-bearing clays.
The outcome of our re-evaluation is that the impact of feldspars in CCS reservoirs has likely been overlooked, but until further experimental work is carried out to constrain how quickly feldspar interactions will impact fluid flow within the reservoir, uncertainties will remain with regard to their impact on CO2 injectivity and storage capacity.
How to cite: Farrell, N., Yang, L., Flowerdew, M., Badenszki, E., Mark, C., Ardo, B., Taylor, K., Waters, J., Hughes, L., and Paul, L.: Experimental and microstructural analysis of feldspar solubility in CCS reservoirs, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-11208, https://doi.org/10.5194/egusphere-egu25-11208, 2025.
Though the energy transition aims to phase out fossil fuels while continuing to exploit the subsurface for other storage solutions (e.g. geological CO2 storage, temporary hydrogen storage), natural gas, as a low-carbon energy carrier, will continue to play a role in our energy mix for the foreseeable future. In general, human activities in the subsurface change the physical and chemical environment, which in turn can lead to surface subsidence and induced seismicity. These phenomena may continue even after activities have stopped, as observed for natural gas extraction from the giant Groningen Gas Field in the Netherlands. They are largely caused by deformation in the reservoir rock, driven by fluid pressure changes. However, in-situ strain measurements from the Groningen Gas Field demonstrate that the clay-rich over- and underburden formations of the reservoir are also affected by these fluid pressure changes, displaying slow compaction. To make accurate predictions of reservoir deformation and to allow reliable assessment of the associated surface subsidence and induced seismicity, a detailed understanding of the deformation processes controlling deformation in these clay-rich formations is needed. Understanding which processes caused deformation in past (hydrocarbon) operations will help in understanding what may happen now that we plan to store other fluids in the subsurface.
We performed rock mechanical experiments at in-situ conditions on the Opalinus Claystone (Switzerland), an analogue to the Groningen over- and underburden claystones, to assess the grain-scale mechanisms responsible for deformation. We designed an innovative and comprehensive multi-step experimental procedure that provides new, coherent data on the time-dependent deformation of clay-rich rocks. The experiments were performed in a triaxial compression apparatus, applying systematic steps of constant stress while controlling the pore fluid pressure in the sample. These steps were either stepped up or down in differential stress during an experiment. At each differential stress we systematically analyzed the instantaneous and time-dependent deformation.
We observed general compaction of the samples upon increasing stress, and time-dependent expansion of the sample when stepping down in stress. Our results demonstrate that deformation in clay-rich rocks is strongly affected by the fluid-transport properties of the rock. We infer that sorption of fluids to the clay-rich matrix plays an important role in the deformation of clay-rich rocks, along with frictional slip controlling grain rearrangement. However, matters are complicated by slow diffusion of pore fluid pressure, which leads to an additional time-dependent component. Overall, our results demonstrate that over half of the observed deformation is permanent, even at low differential stresses. A detailed understanding of the time-dependent deformation of clay-rich rocks is crucial for accurate predictions of the impact of human activities in the subsurface, as sorption of fluid to the clay material may also be important during CO2 and hydrogen storage.
How to cite: Sep, M., Hangx, S., and de Bresser, H.: Time-dependent deformation of clay-rich rocks enveloping reservoirs exploited for geo-energy purposes, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-11807, https://doi.org/10.5194/egusphere-egu25-11807, 2025.
The quality of the sandstone reservoir is critically influenced by the presence of clay coatings on the surfaces of quartz grains. These coatings play an essential role in determining porosity and permeability, key parameters that govern the storage and flow potential of sandstone reservoirs used for geothermal energy, groundwater, and hydrocarbons. This study employs a multiphase-field model, a versatile tool widely used in materials science, to simulate the complex interplay of interface motion and phase transitions within geological systems. By generating a detailed three-dimensional digital representation of sandstone, the model provides precise control over quartz grain coatings and composition, enabling a thorough investigation of their impact on reservoir properties. Two central aspects are explored: (1) the effect of varying clay coating coverage on quartz grains, and (2) the influence of coating distribution on the evolution of porosity and permeability during quartz precipitation. Computational fluid dynamics (CFD) simulations further quantify the changes in permeability at different stages of grain growth, revealing intricate relationships between the distribution of the coating, the properties of the rock, and the dynamics of fluid transport. The findings show that sandstones with a higher proportion of coated grains exhibit enhanced permeability due to the cement growth limiting effects of clay coatings on quartz grains. These insights provide a deeper understanding of the mechanisms that govern sandstone reservoir quality and offer practical implications for optimizing applications in geothermal energy, water resource management, and carbon and hydrogen storage.
How to cite: Kumar, A., Prajapati, N., Schneider, D., Busch, B., Hilgers, C., and Nestler, B.: Revealing the Hidden Dynamics of Clay-Coated Quartz Grains in Sandstone with Multiphase-Field Modeling, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-3471, https://doi.org/10.5194/egusphere-egu25-3471, 2025.
This study integrates 3-D seismic reflection and petrophysical data to investigate the Lopingian bedded salt formations of the Delaware Basin, part of the Greater Permian Basin in the United States. Focusing on the Castile and Salado Formations, the analysis identifies a zone of thickened and deformed strata associated with an intra-salt fold-thrust belt in the southwestern portion of the seismic volume. Adjacent to this fold-thrust belt lies a geophysically distinct region termed the buffer zone.
Petrophysical analysis of the Castile Formation within the buffer zone reveals a unique composition, deviating from the expected cyclical anhydrite-halite members. Instead, this zone consists exclusively of anhydrite. This compositional anomaly challenges previous interpretations that halite absence results from dissolution, suggesting instead that gypsum deposition followed by conversion to anhydrite may have occurred.
The overlying Salado Formation displays significant heterogeneity and karst features, highlighting potential geohazards and complexities for underground energy storage. These findings emphasize the necessity of combining geophysical and petrophysical approaches to accurately characterize subsurface conditions, assess risks, and optimize the placement of salt caverns for energy storage applications.
How to cite: Schuba, N., Moscardelli, L., Dooley, T., Martinez-Doñate, A., and Melani, L.: Geophysical and Petrophysical Insights into Bedded Salt Formations: Implications for Underground Energy Storage in the Delaware Basin, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-14303, https://doi.org/10.5194/egusphere-egu25-14303, 2025.
Seismoelectric (SE) methods are potentially interesting for subsurface characterization by exploiting the coupling between seismic waves and electromagnetic fields in fluid-saturated porous media. While traditional SE techniques have primarily focused on body-wave-induced signals, recent research has highlighted the significant advantages of surface wave-induced SE signals, including enhanced amplitudes and increased sensitivity to near-surface heterogeneities. These characteristics make surface wave-induced SE signals particularly valuable for detailed subsurface investigations.
We conducted controlled laboratory experiments using a water-saturated sandstone sample (19.7% porosity, 310 mD permeability) and a planar acoustic source to generate surface waves at a water-sandstone interface. SE signal variations were systematically measured as a function of receiver distance from the interface, and array-based measurements were performed to analyze the velocity and characteristics of the induced SE surface waves. High signal-to-noise ratio SE surface waves were successfully measured across multiple excitation frequencies (100 kHz, 200 kHz, 300 kHz, 400 kHz, and 500 kHz), demonstrating the robustness of the phenomenon across a broad frequency range.
Our results show that SE signals were only observed in the presence of the porous medium, confirming that they originate from the fluid-porous interface. The SE signal amplitude decayed rapidly with increasing distance from the surface, which is consistent with surface wave behavior. Notably, the SE waveforms exhibited propagation velocities matching those of acoustic surface waves. They showed significantly shorter durations and different frequency content than the corresponding acoustic signals, indicating potential for enhanced spatial resolution in subsurface imaging. Ongoing work focuses on extracting the dispersion and attenuation characteristics of the measured SE surface waves across different frequencies. These findings will provide a foundation for more effective geophysical workflows, particularly in scenarios requiring detailed near-surface characterization.
How to cite: Liu, Y. and Smeulders, D.: Acoustically Induced Seismoelectric Surface Waves at a Fluid-Saturated Sandstone Interface: Multi-Frequency Experimental Observations, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13204, https://doi.org/10.5194/egusphere-egu25-13204, 2025.
The Grande Oolithe is an oolitic limestone from the Middle Jurassic, present at various depths within the Upper Rhine Graben (Alsace, France). It has been identified as a prospective target for geothermal energy extraction. A comprehensive evaluation of the geothermal potential of this formation hinges on a detailed understanding of its mechanical and physical properties, in particular permeability. Previous studies on porous carbonates highlighted the diversity and the microstructural complexity of this rock type. Permeability could be strongly influenced in particular by the degree of cementation and the proportion of macro and micropores in limestones, which often have a dual porosity structure. To identify the parameters controlling fluid flow in the Grande Oolithe, we initiated a systematic study to map its permeability over the entire Upper Rhine Graben and quantify its possible variations with pressure.
Cylindrical samples were prepared from 18 blocks collected from several outcrops in Alsace. Porosity measured on 90 samples span from 4 to 26% for the different blocks, while permeability was found to range from 10⁻15 to 10⁻18 m². Our preliminary microstructural analysis and X-ray Computed Tomography data revealed a high degree of cementation in most of our samples and that the pore space is dominated by micropores, mostly of submicron sizes. For high-pressure experiments, we targeted so far the high-porosity/high permeability end-members, from Bouxwiller (GO) and Gueberschwihr (GU), with respective porosity of 25 and 20%. Both limestones are made of 99% calcite. Conventional triaxial experiments were performed at room temperature on water-saturated samples, in drained conditions with a constant pore pressure of 10 MPa and at effective pressures up to 100 MPa. The experiments were performed at a constant strain rate of 10-5 s-1 and permeability was measured using steady-state flow technique at different stages of deformation.
Under hydrostatic compression, permeability was found to decrease moderately in both GO and GU during the poroelastic stage and then more significantly beyond the onset of pore-collapse. The total permeability decrease was more pronounced in GO than in GU. At an effective pressure of 100 MPa, inelastic compaction resulted in a permeability reduction of a factor 15 in GO and a factor 4 in GU, while respective porosity reduction was 7.8% and 2.5%. Under triaxial compression, the permeability measured in samples deformed at various effective pressures showed somehow similar variations, in qualitative agreement with previous studies on permeability in porous carbonates under triaxial compression.
How to cite: Mammadov, S., Baud, P., Heap, M., Schuster, M., and Reuschle, T.: Permeability of oolitic limestones from the Upper Rhine Graben, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-484, https://doi.org/10.5194/egusphere-egu25-484, 2025.
Digital rock models are becoming increasingly important in addressing the challenges of transitioning to sustainable energy. While traditionally employed to model fundamental petrophysical and geomechanical processes, their utility is expanding into critical applications such as carbon capture and storage (CCS), geothermal energy development, and subsurface energy storage. By using advanced imaging, simulation, and multi-scale analysis techniques, digital rock models provide a detailed understanding of pore-scale properties and their implications for fluid flow, geomechanics, and geochemistry. These insights are essential for optimizing low-carbon energy systems and ensuring reservoir integrity during energy storage and CO2 sequestration. This work highlights some of the recent advancements in digital rock technologies and their contributions to innovative solutions in sustainable energy development.
Estimating the physical properties of rocks, a crucial and time-consuming process in the characterization of geothermal reservoirs, CCUS, and other renewable energy resources, has seen a shift from traditional laboratory experiments to the increasing use of digital rock physics. A key requirement of many forms of pore structure image analysis is that they require binary images to distinguish pore-space from non-pore-space (mineral phases). These are often obtained by thresholding grayscale SEM or X-ray tomographic images. In this study, we present the collection and processing of exceptionally high-quality two-dimensional images of carbonate rocks, with a resolution of 16-bit density and dimensions of 29056 × 22952 pixels. This dataset, subdivided into 155 smaller images of 2048 × 2048 pixels each, was further enhanced using data augmentation techniques such as rotation and reflection, creating a diverse and non-redundant set of training images.
The objective of this work is to train a machine-learning model capable of predicting porosity directly from the images. A convolutional neural network (CNN) was developed and modified for this purpose, using 60% of the dataset for training. The training process involves pre-labeled images, which are used to optimize the weights of the neural network. So far, the CNN has achieved an accuracy of 89.55% in predicting porosity during the training phase. Validation and testing datasets were employed to evaluate and refine the model’s performance, with ongoing efforts aimed at surpassing 95% accuracy in testing. Furthermore, we are working on analyzing the relational characteristics of porosity to expand the applicability of this approach. Initial work in 2D and 3D that has the power to discriminate between mineral phase, between connected and unconnected porosity, and to quantify the pore fluid-mineral surface area, are also in progress. This latter property is extremely relevant to CCS targets where the area for CO2 adsorption is an important parameter which is difficult to assess.
This research not only enhances our ability to quantify key petrophysical properties but also contributes to the development of sustainable energy technologies. The work has significant potential to enhance geothermal resource evaluation and advancing carbon capture and storage (CCS) initiatives, playing a critical role in the transition to low-carbon energy solutions.
How to cite: Alwan, W., Glover, P., and Collier, R.: Quantification of the microstructural properties of CCS and radioactive waste target rocks using Convolutional Neural Networks, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-11103, https://doi.org/10.5194/egusphere-egu25-11103, 2025.
Carbon Capture and Underground Storage (CCUS) is not simply the reverse of the hydrocarbon extraction process. The injection of supercritical CO2 involves different flow regimes (viscous, slip, Knudsen, and molecular diffusion) and the adsorption of CO2 to mineral surfaces. Small pressure differences control the distribution of the gas and gravity controls the overall gas distribution. Under these circumstances reservoir heterogeneity strongly controls where the CO2 goes. Consequently, it is important to have a quantitative description of this heterogeneity. Leeds University Petrophysics Group has been working on using fractals to describe heterogeneity and anisotropy of reservoirs at all scales for the past decade and to develop fractal reservoir models that account for flow at scales smaller than the seismic resolution. In this presentation we show how the fractal dimension of a bounded dataset can be measured, and the main influences on the accuracy of the measurement, taking account of the systematic uncertainties imposed by the finite boundary conditions, scale-dependent effects, and multifractal behaviour.
The approach has been used to carry out digital ‘logging’ of several reservoirs including the Chandon field (Offshore NW Australia) and is currently being implemented for the CCUS testbed Sleipner reservoir (UK North Sea). This logging differs from wireline logging in that it is carried out over an predefined area or seismic data as a function of depth. For the Chandon field, depth-averaged measurements have produced a fractal dimension of 2.15±0.18 (arithmetic mean±standard deviation) over the entire scale range. It is recognised that the fractal dimension of this reservoir is multifractal, with a fractal dimension of 2.06±0.19 in the 70-150 m scale range and 2.62±0.07 in the 200-400 m scale range. Hence, the reservoir is more heterogeneous at the larger scale. This work also has the advantage of providing a fractal dimension value as a function of depth. Our results show in each case that the fractal dimension varies significantly with depth and is dependent on lithofacies. The fractal dimension at both scales picks out apparent lithofacies, with the coarsening-up sequence in the top part of the reservoir (1950-2020 m, all depths TVDSS) associated with a decrease in fractal dimension, shalier units (2020-2035 m and 2080-2125 m) exhibiting high fractal dimensions, and cleaner units (2035-2080 m) showing much lower fractal dimensions. This is good evidence that this new Seismic Fractal Heterogeneity Log (SFHL) represents a measure of rock heterogeneity to horizontal flow at each depth. Work is ongoing concerning the discrimination of different fractal dimensions as a function of azimuth as well as vertically, which is especially important in reservoirs used in CCUS applications.
It is hoped that the new SFHL can provide the sought after quantitative measure of heterogeneity for use in quantifying and modelling CO2 injection into CCUS reservoirs. The real advantage of this approach is that it can be applied to existing 3D and 4D seismic datasets in order to extract from them extra information and extra value. Future work will be aimed at developing the approach further.
How to cite: Yaghoobpour, M., Glover, P., and Lorinczi, P.: Measuring the Fractal Dimensions of Reservoirs: A New Seismic Fractal Heterogeneity Log for Application to CCUS Prospects, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-20882, https://doi.org/10.5194/egusphere-egu25-20882, 2025.
Lithium is a critical mineral in the fight against climate change: it is used in electrical batteries for computing, in electric vehicles, and as local electrical storage for smoothing flow from intermittent sustainable power sources. According to the IEA, in 2023 lithium supply was mainly limited to China, Chile and Australia (85% for mining and 96% for refining), associating lithium supply with high geopolitical risk; a risk to which the UK and EU are exposed.
The UK has a world-class lithium resource in Cornwall, as mineable granite, but lithium is also dissolved in geothermal brines occupying fractures. These fluids have lithium concentrations at approximately 100 ppm (at 2000 m), but they also have order of magnitude lower levels of Na+, Mg2+ and Ca2+ compared with other brine deposits, which makes lithium extraction simpler. Furthermore, the geothermal nature of the brines may allow production plants to be powered by sustainable energy. The question remains, how much lithium-rich brine can be extracted? Here petrophysical fracture modelling can help.
This research reports on some of the modelling technology that can be used to understand lithium-rich brine flow during extraction. It is important to consider aspects of fracture connected volume and connectivity, and to find pragmatic quantitative methods for assessing and reporting such data. Fracture connectivity depends on the number of nodes where fractures interact, and the distance between nodes. Studies of these have been found to be fractal. If that is the case in Cornwall, it implies that aspects of the fracture network at different scales can be fractally extrapolated from measurements made at smaller or larger scales. Connected fracture volume is controlled by fracture length and aperture. These are also fractally distributed. Consequently, a reasonably reliable multiscale 3D model can be constructed in Fracman or FracpaQ.
The aperture, and to some extent the fracture length, changes as the stress regime changes. For example, significant brine drawdown could reduce the flow rate because external stress acts to close fractures when the fracture fluid pressure is reduced, and hence also reduce connectivity. By contrast, a significant injection of brine from which lithium and heat has been extracted would have the opposite effect. Quantification of this can be carried out using electrical methods as well as non-invasive 3D imaging (CT or micro-CT). Consequently, it is important for the fracture model to be responsive to the changing stresses in the model that might result from different stress tensors and production scenarios.
Finally, geothermal brine flow is also controlled by the roughness of fracture surfaces, especially as fractures close during drawdown. The interacting asperities on the surfaces increase the tortuosity of fluid flow significantly, but they also prop fractures open when they would otherwise close. The fracture surfaces are also fractal, and this work shows both models of fractal fracture surfaces and the fluid flow through them. Examples are given which show that uncompressed fractal fracture surfaces with a fractal dimension of 2.349 can reduce fluid flow, in our scenario by 28%.
How to cite: Glover, P., Brabin, J., Torvela, T., and Yeomans, C.: Fracture Modelling and Geothermal Lithium, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-9935, https://doi.org/10.5194/egusphere-egu25-9935, 2025.
Domestic production of lithium is central to the UK’s industrial strategy. This will facilitate the energy transition and will be essential to safeguard lithium supply against geopolitical developments. To this end, two different styles of lithium extraction are being developed in Cornwall: (1) open-pit ‘hard-rock’ lithium mining at two locations in the St Austell Granite and (2) Li-enriched geothermal fluids produced through fracture-controlled fluid-rock interaction and flow. The latter resource is being evaluated for Direct Lithium Extraction (DLE) at multiple locations.
The work undertaken here will largely concern the geothermal lithium resource. In an early phase of research, the petrophysical properties of significant lithologies will be investigated, focusing on variation due to alteration around fractures. This will involve measuring the permeability, porosity, and electrokinetic properties (streaming potential and zeta potential) of core plugs; impedance spectrometry will also be carried out. Additionally, petrographic imaging, focused ion beam SEM imaging, and a combination of micro- and nano-CT scanning will be performed. Information gained in this phase of work will enhance interpretation of geophysical data and feed into prospectivity modelling. A subsequent phase of this research will, therefore, concern the analysis of pre-existing geophysical data, plus the acquisition and processing of new, pertinent geophysical measurements. Furthermore, petrophysical characterisation will permit modelling of the expected geophysical signatures of prospects of varying size, geometry, and potentially effective grade.
The formation and behaviour of the Cornish geothermal lithium resource will also be explored. Geochemical study will elucidate the chemical development of lithium-bearing groundwaters and may suggest the physicochemical consequences of water extraction at different rates. Self-potential signals will be used to recognise patterns of groundwater flow, feeding into a broader model of Cornish geothermal circulation.
Considering Cornwall as a case study, this work is expected to inform regional prospectivity for lithium-bearing geothermal brines; it could also enhance estimates of the geothermal energy potential of the region.
How to cite: Brabin, J. T., Glover, P. W. J., Torvela, T. M., Green, C. M., Shail, R. K., and Yeomans, C.: Developing methods for the location and characterisation of Li-bearing geothermal waters in Cornwall, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-6979, https://doi.org/10.5194/egusphere-egu25-6979, 2025.
Abstract
The rapid escalation of global warming, driven by anthropogenic carbon dioxide (CO₂) emissions, underscores the necessity of carbon capture and storage (CCS) technologies as a critical strategy for mitigating atmospheric CO₂ levels. Shale reservoirs, characterized by their extensive nanopore networks and heterogeneous pore structures, hold significant promise for CO₂ sequestration. This study investigates the storage and sequestration potential of shales from two distinct formations: the Lower Silurian Longmaxi Formation (TY1 group) and the Lower Cambrian Niutitang Formation (N206 group). A comprehensive suite of experiments, including XRD analysis, mercury intrusion porosimetry (MIP), low-pressure gas adsorption (N₂ and CO₂), field-emission scanning electron microscopy (FE-SEM), and mineralogical analysis, was employed to characterize pore structure, adsorption behaviour, and mineralogical controls on CO₂ storage. Moreover, a novel fractal parameter, succolarity along with conventional mass and surface fractal dimensions were used to depict the pore systems of the two groups.
Results reveal that the TY1 samples exhibit higher total organic carbon (TOC; up to 7.58%), greater microporosity, and stronger CO₂ adsorption energies (up to 34 kJ/mol) compared to the N206 samples, which display a more mesopore-dominated system and lower adsorption energies (28–30 kJ/mol). The Longmaxi Formation demonstrates superior pore connectivity and pore size distribution (PSD) homogeneity, enhancing both CO₂ retention and transport. Its higher carbonate content also suggests potential for mineral trapping through carbonation reactions. In contrast, the Niutitang Formation is characterized by higher total porosity (up to 2.4%) and mesoporous contributions, favouring rapid injection but limiting long-term retention. Meanwhile, the FE-SEM observations revealed that many authogenic minerals such as quartz, pyrite and rutile occupy the pore space in organic matters. It is much more prevalent in the N206 samples, which may be responsible for its lower microporosity.
Key findings include a strong correlation between TOC and micropore volume, as well as between clay minerals and mesopore-macropore attributes. These correlations highlight the dual role of organic matter and mineral content in determining gas adsorption capacity and flow dynamics. The TY1 group’s balanced micropore and mesopore contributions make it ideal for long-term CO₂ sequestration, while the N206 group’s larger pore sizes enhance its suitability for rapid injection and enhanced gas recovery (EGR) applications.
This study provides critical insights into the interplay of organic matter, mineral composition, and pore structure in controlling CO₂ storage potential in shale reservoirs. The findings emphasize the Longmaxi Formation's superior suitability for CO₂ storage and EGR, with implications for optimizing CCS strategies in similar shale systems globally.
How to cite: Bo, L., Bingsong, Y., Glover, P., Lorinczi, P., Kejian, W., and Panaitescu, C.: Comparative Analysis of CO₂ Sequestration Potential in Shale Reservoirs: Insights from the Longmaxi and Niutitang Formations, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5004, https://doi.org/10.5194/egusphere-egu25-5004, 2025.
Pore structure is a critical factor in evaluating the quality of a reservoir or cap layer, influencing storage capacity, fluid flow efficiency, and reaction rates. Standard approaches, including Mercury Intrusion Porosimetry (MIP), Gas Pycnometry, and Brunauer-Emmett-Teller (BET) analysis, provide essential information; they are limited in their ability to capture pore connectivity and pathway complexity. X-ray Computed Tomography (CT) provides a distinct perspective, enabling three dimensional visualization of pore structures and insights into pore connectivity within 3D images. Accurate porosity analysis using CT, however, depends on careful evaluation of the segmentation process, especially the selection of thresholding methods, which can introduce biases and impact the reliability of the results. To address these challenges, this study introduces a new workflow leveraging grey-level terrain parameters from CT images as a reference index. Interbedded samples of muddy sandstone and siltstone are analyzed, with CT-derived porosity compared to experimental results obtained from an AccuPyc Helium Pycnometer. This comparison assesses the reliability and accuracy of the data-driven approach. By reducing uncertainties associated with porosity thresholding, the proposed workflow aims to establish a robust framework for CT-based pore structure analysis. It highlights the ability of CT imaging to deliver detailed 3D pore analysis, thereby supporting improved predictions of reservoir properties and resource management.
How to cite: Liu, Y.-M., Kioka, A., and Huang, J.-J. S.: Data Driven Porosity Measurement for Non-homogeneous Sandstone, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-15144, https://doi.org/10.5194/egusphere-egu25-15144, 2025.
Hydrate-based CO₂ sequestration in marine gas hydrate reservoirs is a promising dual-purpose strategy for carbon storage and energy recovery. However, geomechanical stability remains a critical challenge for ensuring safe geo-engineering operations, as it directly influences risks such as wellbore destabilization, subsea subsidence, and submarine landslides. Despite significant advancements, a systematic understanding of the geomechanical responses of marine hydrate reservoirs under CO₂ injection is still lacking. This study provides a comprehensive review of the formation stability associated with hydrate-based CO₂ sequestration, adopting a cross-scale and multi-method perspective. Three distinct storage strategies are discussed: (1) CO₂ sequestration above the hydrate zone, forming an artificial hydrate cap; (2) sequestration within the hydrate zone through immediate CH4-CO2 exchange; and (3) sequestration within the hydrate zone via later-stage replacement, producing mix-hydrates. We further evaluate experimental, numerical, and molecular-scale studies that investigate the geomechanical behavior of hydrate reservoirs across these scenarios. Key findings reveal several unresolved issues, including the debated mechanical superiority of CO₂ hydrates compared to methane hydrates and the absence of quantitative relationships linking hydrate saturation to reservoir mechanical performance. Additionally, commercial viability remains a significant hurdle, with integrated approaches such as the co-production of gas hydrates, shallow gas, and deep gas proposed as potential solutions. This review highlights critical knowledge gaps and identifies future research directions to advance hydrate-based CO₂ sequestration. By addressing these challenges, this work aims to support the safe and sustainable implementation of this emerging carbon storage technology.
How to cite: Zhang, Q., Song, Z., Chen, D., and Zi, M.: Is CO2 Sequestration in Marine Hydrate Reservoirs Geomechanically Stable? , EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-10606, https://doi.org/10.5194/egusphere-egu25-10606, 2025.
Shale oil reservoirs are extremely tight, making it fundamental to evaluate their physical properties to exploration and development efforts. These properties are closely linked to the rock components (RC) and pore structure (PS). The significant complexity and heterogeneity inherent in the RC and PS pose considerable challenges for assessing the physical properties of these reservoirs. In specific depositional environments, a matching relationship between RC and PS exists. Identifying this relationship and associating microscale PS attributes with macroscale physical properties can expose substantial variations within shale oil reservoirs, aiding in the selection of optimal layers for exploitation and improving development efficiency.
This study focuses on the shale oil reservoirs of the Lucaogou Formation (P2l) in the Jimusar Sag, marked by mixed-source sedimentation. Using a combination of thin section observations, XRD, TOC analysis, and EDS analyses, it characterizes the RC within the designated area. Moreover, the investigation employs LTNA experiments, MICP tests, and SEM to detail the PS attributes. Based on these experiments, the research analyzes the matching relationship between RC and PS in the shale oil reservoirs and the connection between microscale PS and macroscale physical properties, highlighting the control of physical properties by RC and PS. The findings reveal that pore types in these shale oil reservoirs predominantly consist of small pores and mesopores. Small pores, developed within K-feldspar, quartz, and clay minerals, are chiefly dissolution pores; mesopores occur between dolomite or plagioclase grains, characterized by a regular pore morphology. Porosity is governed by the presence of micropores, mesopores, and macropores, while permeability is principally influenced by mesopores and macropores. This established relationship between RC and PS in this study offers a reference for the efficient development of the P2l shale oil reservoirs and can serve as a foundation for research into fluid-solid interaction and flow characteristics in porous media.
How to cite: Song, Z., Li, J., and Xiao, D.: Control of Physical Properties by the Matching between Rock Components and Pore Structure in Shale Oil Reservoirs, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-2429, https://doi.org/10.5194/egusphere-egu25-2429, 2025.
Posters virtual: Tue, 29 Apr, 14:00–15:45 | vPoster spot 2
EGU25-17658 | ECS | Posters virtual | VPS28
Determination of Lithofacies and Elastic Behavior Modeling in Columbian River Basalt Group (CRBG) FormationsTue, 29 Apr, 14:00–15:45 (CEST) | vP2.1
Efficient handling of climate change issues in order to mitigate its negative impact of the flora and fauna of the earth, or on the pace of industrialization, is a big challenge in every disposition around the world. Amongst the many options available, geological storage of CO2 in the basalt formations is proving to be a promising one due to its large and pervasive occurrence, to facilitate stable carbonation of the sequestered CO2, and with ready access to the basalt deposits for operational requirements. Laboratory testing and a few field implementations showed that carbon dioxide injected in basalts would form stable carbonate minerals, keeping the substance in place for thousands of years.
This work applies the machine learning applications aimed at the classification of different facies in basalts, particularly flow tops and flow interiors, towards the selection of a sequestration site based on their relevant petrophysical characteristics.
After the facies were identified, several rock physics models were run with an outlook of predicting the elastic properties of basalt. Based on our results, we found the Differential Effective Medium (DEM) model enables the most accurate prediction with the least error as compared to Self-Consistent Approximation and Kuster-Toksӧz model. This finding provides a foundation for using the DEM model to create an initial reservoir matrix, which can be applied to simulate geomechanical changes upon CO2 injection in Basalt. Additionally, facies classification aids in delineating zone boundaries within basalt flows, allowing for the selection of optimal injection sites based on their petrophysical properties.
How to cite: Nagarkoti, N., Kumar, T., Panwar, N., and Sharma, R.: Determination of Lithofacies and Elastic Behavior Modeling in Columbian River Basalt Group (CRBG) Formations , EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-17658, https://doi.org/10.5194/egusphere-egu25-17658, 2025.
EGU25-4896 | ECS | Posters virtual | VPS28
Intelligent Pore Recognition Method for Carbonate Rock Electrical Image Logs Based on Deep LearningTue, 29 Apr, 14:00–15:45 (CEST) | vP2.2
Electrical image logs can intuitively reflect the development status and characteristics of dissolution pores, which is of significant importance for the development of oil and gas resources. However, traditional methods for identifying pores in electrical image logs are not only cumbersome and labor-intensive but also incapable of distinguishing between different types of pores. Moreover, the strong heterogeneity and dissolution effects in carbonate reservoirs result in significant variations in pore size and complex, diverse pore morphologies, making it difficult to extract pore parameters. To address these issues and challenges, this paper proposes a semantic segmentation model, FILnet, designed using computer vision technology and deep learning frameworks. This model aims to achieve intelligent recognition and segmentation annotation of pores of different scales in the wellbore region of electrical image logs. The data selection process involved using a sliding window to choose electrical log images containing dissolution pores and caves. Image processing techniques were then applied to complete and augment the images, thereby enhancing data diversity. Furthermore, a dual-attribute dataset was created using dynamic and static images from electrical image logs to assist the model in learning the semantic features of pores. Finally, the proposed model was compared with traditional pore identification methods, such as threshold segmentation. The results showed that FILnet demonstrated significant performance advantages on the dual dataset, with a mean intersection over union (MIoU) of 85.42% and a pixel accuracy (PA) of 90.54%. Compared to traditional pore identification methods, the deep learning semantic segmentation approach not only achieves recognition of different types of pores but also improves identification accuracy. This indicates that the network model and data processing methods proposed in this paper are effective and can achieve intelligent recognition and accurate segmentation of pores in electrical image logs.
How to cite: Zhuolin, L., Guoyin, Z., and Yifan, G.: Intelligent Pore Recognition Method for Carbonate Rock Electrical Image Logs Based on Deep Learning, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-4896, https://doi.org/10.5194/egusphere-egu25-4896, 2025.
