This session invites contributions from diverse research communities to explore new petrophysical models, numerical simulations, laboratory experiments, and field case studies. We aim to foster interdisciplinary discussions on advancing petrophysical relationships and improving our understanding of complex subsurface processes across a wide range of natural and engineering settings, including low-carbon energy technologies and subsurface storage solutions. We encourage submissions focused on georeservoir studies that combine insights from geomechanics, geochemistry, petrophysics, and material science. Additionally, we welcome submissions on the development of cutting-edge experimental apparatus, novel sensor technologies, and innovative methods for simulating in-situ conditions.
The time dependent Vp/Vs ratio (Scholz et al., 1973), preslip (Dieterich, 1978), and cascade models (Ellsworth and Beroza, 1995) are popular geophysical models used as earthquake precursors. Such geophysical models have generally focused on the physics of earthquake source regions (Yamashita et al., 2021). However, the physical properties of the off-fault region are also related to earthquake mechanics (Gudmundsson, 2004), which are strongly affected by the presence of fractures (Jayawickrama et al., 2024). While the presence of fractures affects the physical properties of rocks, inarguably, they alter the transport properties as well. In this investigation, it is speculated that such changes in the transport properties coupled with the seismic velocity in the off-fault regions could be used to develop an earthquake precursor model. To this end, cyclic deformation experiments were conducted on thermally cracked (at 800oC) Aji granite, in analogy to damage, while simultaneously measuring the water permeability and the seismic velocity. However, unlike the conventional cyclic experiments, a stationary time was employed between each cycle (loaded to 0.6C, 0.7C, 0.8C, and 0.9C) around 0.1C (C: peak stress), in analogy to a stress relaxation period before the stress accumulation for the next event. With the initial stress build up, the seismic velocity increases while the permeability drops until the onset of dilation, where the trend is reversed from there onwards. Once the axial stress is released gradually, followed by an initial increase, the permeability becomes relatively stable, while the seismic velocity continues to drop. During the stationary period, a noticeable compaction was observed along with a seismic velocity increase and a permeability drop. Hence, indicated an overall healing in the damaged sample, under relaxed stress conditions. The dynamic crack density evolution also provides critical evidence for this. Moreover, with each cycle, the magnitude of velocity increment and the permeability drop becomes lower. Subsequent to the healing process as the stress builds up, the seismic velocity and the permeability follow a similar trend to the previous cycle. Hence the repeated compaction and dilation that the sample suffers with stress cycles is reflected by the seismic velocity and the permeability evolution. As such, the current investigation has proven the possibility of utilizing the evolution of permeability coupled with seismic velocity in the off-fault regions as a possible precursor to earthquakes.
How to cite: Jayawickrama, E. and Katayama, I.: Permeability and seismic velocity evolution of thermally cracked Aji granite during cyclic loading, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-804, https://doi.org/10.5194/egusphere-egu25-804, 2025.
The mechanical properties and elastic anisotropy of shale oil reservoirs are influenced by factors such as lithology, pore structures, and fluids. Studying the dynamic and static elastic properties is crucial for predicting geological and engineering “sweet spots” in these reservoirs. While there has been extensive research on the static properties of shale, dynamic multi-frequency elastic anisotropy remains under-explored. This study investigates the anisotropic dispersion mechanism of favorable lithofacies (lamellar dolomitic shale with vertical and horizontal bedding) in the inter-salt shale oil reservoir of the Qianjiang Formation, by using multi-frequency measurement techniques including low-frequency stress-strain and high-frequency ultrasonic tests. Key findings include: 1) Terrestrial shale exhibited stronger elastic property dispersion than marine shale, attributed to high viscosity medium oil. Lamellar structures and interbedded fractures significantly contributed to this anisotropy; 2) Elastic property dispersion in partially oil-saturated states decreased from strong to weak with increasing frequency, likely driven by wave-induced fluid flow or intrinsic dissipation; 3) Elastic parameters measured perpendicular to bedding showed greater dispersion and pressure sensitivity than those measured parallel, with higher anisotropy and sensitivity at seismic frequencies; 4) Fluid saturation reduced pressure sensitivity of elastic parameters in the vertical direction while increasing it in the parallel direction; 5) Anisotropic Gassmann theory effectively explained P-wave velocity at low frequencies, though predictions for S- and P-wave velocities at higher frequencies were less accurate. This study provides a solid reference for understanding frequency-dependent properties of azimuthal anisotropy and offers valuable insights for seismic prediction of “sweet spots” in shale oil reservoirs.
How to cite: Zhao, J.: Experimental Studies on Anisotropic Dispersion of inter-salt Shale Oil, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-3795, https://doi.org/10.5194/egusphere-egu25-3795, 2025.
The EU-funded project GeoHEAT aims to develop new time- and cost-efficient methods for geothermal exploration. One part will be a georadar probe that can be used to characterize geological structures at elevated ambient temperatures. As the permittivity of the surrounding rock mass is of great importance for the optimal use of this probe, we are investigating the possibility of estimating this dielectric property using digital rock physics (DRP) and drill cuttings. With the latter being a by-product of exploration drilling, they represent a further potential approach at saving both time and costs, without the added expense of core sampling. Here we want to present the current state of our research and give an overview of preliminary insights and future challenges.
In order to determine the effective permittivity using DRP, a pore scale model is required. For this purpose, nano-computed tomography images are created and then segmented, whereby different phases are assigned to the gray value intensities of the scanned sample. The model is finalized by attributing physical properties to individual material particles in the location-dependent volume and is subsequently used to compute the effective permittivity with a solver utilizing the finite volume method. To optimize this process, standardized granite core samples from the Bedretto Lab in Switzerland are used, and the results are validated by comparing them to laboratory measurements of the same rock type for accuracy.
Since the extraction of these kinds of samples is expensive, requires interruption of drilling and can only be carried out for limited boreholes and depth sections, the next step is to investigate the use of cuttings, which are generally produced during drilling and transported to the surface with the drilling mud. We analyze to what extent the precision of the obtained results is affected by this more economic approach.
The analysis of core samples has yielded promising results, demonstrating a high level of accuracy in estimating effective permittivity values using DRP. In addition, ongoing investigations into the use of rock cuttings as a substitute have shown great potential for significantly reducing cost and time, while maintaining reliability of the determined rock property. These advances could improve the practical application of georadar probes, offer a more efficient approach to geothermal exploration and provide deeper insights into the geology of the subsurface.
How to cite: Kerkmann, N., Siegert, M., Kouamo Keutchafo, N.-A., and Saenger, E. H.: Estimating Effective Permittivity using Digital Rock Physics and Drill Cuttings – Preliminary Insights and Future Challenges, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-6497, https://doi.org/10.5194/egusphere-egu25-6497, 2025.
GebPy is an open-source, Python-based tool developed to simulate synthetic geophysical and geochemical properties of minerals, rocks and entire rock sequences. It is based on the concept that the properties of a rock are fundamentally determined by its mineralogical composition and its interaction with fluids like water. By adopting a bottom-up approach, GebPy systematically builds from the mineral scale to the rock and sequence level, providing a robust framework for understanding and modeling geophysical and geochemical systems.
The modeling process begins at the mineral level, where properties such as density, volume, seismic velocity or gamma radiation are calculated based on chemical composition and fundamental physical and crystallographic principles. These properties are then combined to simulate the bulk properties of a rock, accounting for the proportional contributions of individual minerals. GebPy also integrates the effects of pore fluids, such as water, to provide a realistic representation of subsurface conditions.
One of the key strengths of GebPy is its scalability. Beyond individual minerals and rocks, the tool enables the simulation of entire rock sequences, generating idealized datasets that are highly valuable for geophysical applications. These include seismic modeling, well-log analysis and the evaluation of geophysical inversion techniques. This ability to model idealized systems provides insights into the fundamental principles governing geophysical and geochemical behavior, making GebPy a powerful resource for both theoretical and applied research.
The development of GebPy was inspired once by the study of well-log diagrams, which play a critical role in resource exploration. By generating synthetic well-log data under idealized conditions - free from natural imperfections such as fractures or measuring artifacts - GebPy provides a new perspective on how these diagrams might look in a perfect geological scenario. This approach not only enhances our understanding of the fundamental properties of rocks but also supports the development of advanced modeling techniques and the evaluation of uncertainty sources.
Looking ahead, GebPy’s development roadmap includes the integration of advanced techniques such as machine learning and the use of experimental data for calibrating input parameters like elastic properties of minerals. These enhancements will further expand its capabilities, enabling even more precise and comprehensive simulations. GebPy’s open-source nature ensures that it can be continuously improved and adapted by the geoscientific community, fostering collaboration and innovation.
GebPy represents an important step forward in the generation of synthetic geophysical and geochemical data. By providing a scalable and reliable framework for modeling minerals, rocks and sequences, it empowers researchers and practitioners to explore geological systems with precision and flexibility.
How to cite: Beeskow, M. and von Hagke, C.: GebPy - a Python-based, open source tool for the generation of synthetic geophysical and geochemical data of minerals, rocks and whole sequences, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-10743, https://doi.org/10.5194/egusphere-egu25-10743, 2025.
Water is ubiquitous in crustal rocks and has been independently shown to increase and decrease rock elasticity via adsorption-induced weakening and saturation-related stiffening. Yet, the interplay of how weakening and stiffening effects concurrently control the rock elasticity remains unclear. Here, we examine the acousto-mechanical behavior of a free-standing sandstone subjected to gradual water infiltration with a downward-moving wetting front over 7 days. Using time-lapse ultrasonic and digital imaging techniques, we observe elastic weakening ahead of the wetting front, which is explained by an analytical model linking P-wave velocity decrease, adsorption-induced expansion and surface energy decrease established at the grain scale. As the wetting front moves through the probed region, the weakening effect diminishes, and P-wave velocity begins to increase, consistent with findings in granite. This shift is attributed to saturation-related stiffening, supported by an analytical model of partial water saturation. A numerical model simulating the profile of water saturation and vapor further validates these observations. Our research sheds light on a key question in rock deformation: how weakening and stiffening effects jointly control rock deformation during progressive wetting.
How to cite: Gao, F., Kang, H., Wu, R., Peng, X., Dong, S., Zhao, C., Leith, K., Gurevich, B., Li, B. Q., Lei, Q., Gor, G., and Selvadurai, P. A.: Moisture dynamics controls rock elasticity from weakening to stiffening, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-9190, https://doi.org/10.5194/egusphere-egu25-9190, 2025.
Seismo-electromagnetic (SE) signals are created in fluid-saturated porous media by electrokinetic conversions at the pore scale. Two of these signals are frequently investigated: the first is a co-seismic wavefield, bounded to the propagating seismic waves, and the second is an electromagnetic (EM) wave created when a seismic wave passes through the interface between two porous media. Led by the effectiveness of SE phenomena in detecting thin layers (i.e., layers with thicknesses smaller than the seismic wavelength), many authors studied how a thin layer, or a combination of thin layers, can alter SE signals. In this context, the present work brings new experimental and numerical data as a means to further investigate the relation between the layer thickness and the EM interface-generated response. Particularly, we have noticed that the effect of layer thinning on the EM interface-generated waves is similar to what is observed for seismic waves, but with a maximum signal enhancing, due only to thickness, occurring when a layer has a thickness that is equal to half the wavelength of the P-wave impinging on the layer. We have also explored the effect of the pore-fluid electric conductivity on SE signals, since this parameter plays an important role on the SE fields. The fact that the EM interface-generated wave is very sensitive to contrasts of fluid conductivity, whereas seismic waves (and therefore the co-seismic) are, in effect, insensitive, is an appealing characteristic of SE exploration. By comparing experiments with simulations we have accessed the effect of fluid conductivity on SE wavefields, complementing previous studies with a quantitative analysis of the dependency of SE signals on this physical property. Moreover, we have evaluated the ability of the electrokinetic theory adopted in this study to predict our experimental data, and showed that it performs well in terms of waveform and amplitude behavior for all fluid conductivities considered.
How to cite: Martins-Gomes, V., Brito, D., Garambois, S., Barucq, H., Dietrich, M., and Bordes, C.: Experimental and numerical study of the seismo-electromagnetic signals created at thin porous-porous interfaces, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12039, https://doi.org/10.5194/egusphere-egu25-12039, 2025.
Accurate analysis of rock pore structures is pivotal for predicting their performance in geological applications, such as CO₂ storage, geothermal energy extraction, and radioactive waste disposal. Advanced imaging techniques, such as Digital Rock Physics (DRP), have transformed the characterization of porous media by providing detailed insights into microstructural properties.
DRP employs high-resolution X-ray computed tomography (CT) to scan rock samples, generating 3D images that reveal pore structures, mineral phases, and fracture networks. This enables the computation of key rock properties, including porosity, permeability, thermal conductivity, and elastic moduli. These properties are critical for applications in sustainable energy production and seismic hazard monitoring.
The classical five-step workflow of DRP begins with the preparation of a high-resolution X-ray computed tomography (CT) image. This is followed by tomographic reconstruction of the image using simple back-propagation techniques. Next, preprocessing operations are conducted to assess and manage artifacts before proceeding to the segmentation of individual phases. Based on the segmentation results, key rock properties such as thermal conductivity, permeability, and elastic properties are computed by solving the corresponding physical equations.
The accurate segmentation of digital rock models into different phases and features holds a significant importance and remains a formidable challenge, as it directly impacts the precise characterization of subsequent physical properties. However, most studies using classical segmentation techniques, such as grayscale histogram processing or watershed algorithms usually relied on a binary segmentation process. This means that rock samples are divided into just two phases: pore and solid. This oversimplifies the complexity of multiphase rocks, neglecting the heterogeneity of, i.e., granitic rocks and compromising the accuracy of reservoir characterizations.
This study presents a multiphase geological segmentation approach for the Rotondo Granite, integrating geological ground truth for potential machine learning applications. By accounting for every distinct mineral phase within a granitic reservoir rock, this method moves beyond traditional binary segmentation, enabling a more detailed and accurate representation of rock microstructures. The improved segmentation accuracy enhances the precision of DRP analyses, contributing to more reliable underground reservoir assessments and supporting the transition toward sustainable energy technologies.
How to cite: Keutchafo Kouamo, N.-A., Balcewicz, M., Siegert, M., and Saenger, E. H.: A Multiphase Geological Segmentation of the Rotondo Granite, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-11954, https://doi.org/10.5194/egusphere-egu25-11954, 2025.
Traditionally, resistivity well logs have been used to determine water saturation (Sw) in oil and gas reservoirs based on Archie's Law. However, the intricate pore structure of tight carbonates poses challenges, as their electric conductivity does not adhere to this law, thereby complicating the assessment of water/gas saturation in gas reservoirs. To address this, the study analyzed SEM images of carbonate samples to understand the pore structures. Utilizing the Slice-Gans model, 3D digital cores were constructed and resistivity was simulated.
The findings reveal that as porosity increases, the cementation exponent m in Archie's formula also increases. Theoretical derivations indicate that this is primarily due to changes in the PTRR as porosity varies. Dolomite and calcite are the primary minerals in the carbonates studied, and the PTRR differs between dolomite and calcite pores. Consequently, the m value varies depending on the mineral composition. By applying a parallel conductive model, the m value for cores with different dolomite and calcite volume fractions can be calculated.
Additionally, the study analyzed rock resistivity experiment results and found that the saturation exponent n's value also varies with porosity, with a fitted relationship established. This enabled the creation of a final variable m and n model. When applied to practical logging data, the calculated Sw values were found to be consistent with the bounded water saturation obtained from nuclear magnetic resonance (NMR) experiments in gas layers, validating the accuracy of the new model.
How to cite: Nie, X., Sun, C., Yang, S., Zhou, Y., Liu, S., and Mei, Q.: A novel water saturation well logging evaluation model for tight carbonate gas reservoir based on pore-throat radius ratio from SEM images, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-1565, https://doi.org/10.5194/egusphere-egu25-1565, 2025.
Advancing rock physics modeling is critical for understanding the physical properties of gas hydrate-bearing sediments and assessing hydrate reservoirs. This study presents a combined elastic and electrical rock physics framework to quantitatively characterize the morphology and distribution of pore-invasive gas hydrates, a dominant reservoir type in marine and permafrost environments. Elastic modeling, grounded in granular medium contact theory and Gassmann’s equation, reveals the influence of hydrate saturation and initial porosity on P- and S-wave velocities. However, these velocities alone are insufficient to uniquely constrain hydrate morphology. To overcome this limitation, we refined Archie's law by introducing an empirical ion concentration exponent, improving the sensitivity of electrical conductivity models to hydrate distributions within pores. By coupling these models, we simulate hydrate formation processes and evaluate their impact on seismic and resistivity properties. Our results highlight several key conclusions. First, experimental observations suggest that a uniform distribution of hydrates within the pore framework is most consistent with measured geophysical responses, despite the potential for ring-shaped saturation patterns during laboratory experiments. Second, we identify a distinct morphological evolution during hydrate growth: hydrate structures transition from grain-supporting to contact-cementing and finally to pore-filling morphologies as saturation increases. This progression is reflected in both velocity and resistivity trends, offering complementary insights into the hydrate formation process. This work not only advances the understanding of hydrate formation but also provides a robust framework for evaluating hydrate reservoirs, contributing to efforts in energy resource development and environmental management.
How to cite: He, T., Zhang, Q., Lu, H., Zi, M., and Chen, D.: Quantitative Characterization of Pore-invasive Gas Hydrate Morphology via Rock Physics Modeling, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-18980, https://doi.org/10.5194/egusphere-egu25-18980, 2025.
Heterogeneities control rock properties, especially hydraulic, reactivity, and geophysical properties. Complex systems typically include multiple porosities at embedded scales, from the micro/meso cracks and pores to geological macro-fractures and karsts. This complex network plays interdependent roles and introduces difficulties in the characterization of the whole formation, especially with difficulties extrapolating laboratory interpretation to field investigation. A general and comprehensive workflow of the upscaling processes needs to be developed.
Our study focuses on the platform “Observatoire des transferts dans la Zone Non-Saturée” (O-ZNS, Orléans, France), an artificial excavation in the karstified and fractured limestone formation of Beauce aquifer. The observatory is composed of an exceptional well (20 m-depth, 4 m-diameter) surrounded by 8 cored boreholes. During the development of this platform, we excavated metric heterogeneous blocks to investigate different properties at an intermediate scale between laboratory and field. Our aim is to characterize these samples thanks to direct (micro)structure observation and quantification compared to petrophysical property measurements (transport and acoustic properties) to define their representative elementary volume (REV). The though protocol is a repetitive process including series of 3D scans and petrophysical measurements followed by cutting blocks in smaller and smaller parts. In complement, 3D scans made from photogrammetric reconstruction of the blocks provides digital models at various scales that help us in locating the geophysical heterogeneities with respect to the observed geological features at various scales.
For the biggest blocks, the carrying out of this protocol is challenging and tremendous. The key methodologies still need to be confronted to discussion.
We started the investigation on some intermediate blocks (around 30 to 50 cm-size). We highlight the possibility of measuring acoustic at different frequencies even on the rough surface of the block. Permeability can be obtained with air-measurements using a tiny-perm apparatus. Porosity is more challenging. As a first approximation, we estimate it assuming a certain grain density, and by measuring its dry weight and volume. Finally, 3D scans allow us to describe the embedded structure of the block, and to count and measure pores and cracks sizes. The first series of results are coherent, and we will be able to go a step-down and tentatively obtain the REV for all these properties. The final objective would be to define the link between the REV of the different explored properties, considering the heterogeneities.
How to cite: Mallet, C., Laurent, G., and Azaroual, M.: Petrophysical characterization of multi-scale heterogeneities of a vadose zone within continental limestone formation, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-1285, https://doi.org/10.5194/egusphere-egu25-1285, 2025.
Reliable modelling of pore-scale network is critical to the understanding of fluid flow behaviour in a reservoir. This study presents the application of numerical techniques to high-resolution pore-network model derived from 3D micro-CT data obtained from scanning of core plugs of carbonate reservoirs from the Western Offshore basin. The methodology incorporates Direct Pore-Scale modelling, using computational fluid dynamics (CFD) techniques to solve flow field equations numerically, such as the Navier-Stokes equations. Adaptive mesh refinement within Finite Element Methods (FEM) and Finite Volume Methods (FVM) ensures accurate resolution of flow dynamics while maintaining numerical stability. Furthermore, the Lattice Boltzmann Method (LBM) is implemented to handle complex pore geometries and boundary conditions efficiently, with an advantage of large-scale parallelization to avoid interface tracking explicitly.
In parallel, Pore Network Models (PNMs) are integrated to represent pore spaces into simplified networks of pores and throats, preserving topological features for reconstructing the fabric of carbonate rock. These models are particularly effective to study collective behaviour across pores and complement direct methods by linking pore scale to sub-pore scale domain. Our approach addresses the computational intensity of sub-pore scale simulations and the limitations of network simplifications, that have implications on macroscopic properties such as Darcy-scale permeability for single-phase incompressible flows.
By integrating these approaches, we provide insights into accurate computation of mass fluxes and fluid-structure dynamics with high fidelity. Our results systematically analyse and compare numerical differences across methods to provide an understanding of the variability of computed properties, in our case single-phase incompressible absolute permeability. This facilitates in the resolution of complex fluid-structure dynamics and the development of optimized, stable, and consistent computational fluid dynamics (CFD) workflows for applications in enhanced hydrocarbon recovery and subsurface energy applications.
How to cite: Sulekh, K., Pandit, S., Shahi, A. K., and Singh, K. H.: Numerical analysis of pore scale processes in carbonate reservoirs from the Western Offshore basin in India, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12316, https://doi.org/10.5194/egusphere-egu25-12316, 2025.
The transport of heat from the Earth’s interior to its surface is the main
driving force for many geological processes, like e.g. lithosphere dynamics and
mantle convection. To understand these processes, it is essential to capture
the spatially and temporally dependent temperature field of the Earth’s crust.
The structure of this temperature field is largely determined by the thermal
properties of the rocks. One of the key thermophysical properties is thermal
conductivity, which plays a critical role in various scientific and economic fields,
such as the study of sedimentary basins and geothermal potentials.
To characterize the thermal properties of various lithologies, measurements
on core samples are of ultimate interest. However, as coring is highly expen-
sive, drill cores are not often taken during drilling campaigns. Nonetheless, drill
cuttings would be available from nearly all drill holes. The drill cuttings can
be ground and compressed to form measuring tablets for thermal conductivity
tests, which changes the rock structure and thus also the thermal properties. An
alternative could be to embed drill cuttings in materials of known thermal prop-
erties like resin to prepare samples ready to be used with the widely available
Thermal Conductivity Scanner (TCS).
In this study, we present an innovative method for determining the thermal
conductivity of drill cuttings using TCS by preparing various samples drill cut-
tings embedded in epoxy resin. We investigate how grain size of the encased
cuttings affects the estimation of thermal conductivity with the TCS. To test
this novel approach, we use artificially produced drill cuttings, mini-cores em-
bedded in epoxy resin, and undisturbed reference samples. Our investigations
suggest that grain size and thermal edge effects resulting from embedding the
samples in resin can be corrected with sufficient precision to enable accurate
conclusions about the thermal conductivity of the undisturbed rock.
How to cite: Schulz, A., Kasburg, V., Goepel, A., and Kukowski, N.: Thermal Conductivity Measurements of in Resin-Embedded Cuttings Using the Optical Scanning Method, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12870, https://doi.org/10.5194/egusphere-egu25-12870, 2025.
Understanding multi-phase pore-scale dynamics and their impact on bulk electrical properties is essential when monitoring reactive flow and transport processes in many applications. This study introduces a novel experimental setup combining simultaneously Spectral Induced Polarization (SIP) acquisition with X-ray micro-computed tomography (µCT) for real-time monitoring. This innovative approach enables spectroscopic measurements, from mHz to kHz, to be directly correlated with dynamic imaging of pore-scale fluid and grain distributions. The setup features a custom-designed flow cell capable of operating under controlled pressure (up to 120 bars) and temperature (up to 100°C) allowing for real-time monitoring of dynamic petrophysical processes such as multi-phase flow, reactive transport, and mineral precipitation and/or dissolution.
In this contribution, we validate the experimental set-up under variable saturation conditions. Using a medium-grained sand sample, we conducted a series of eight experiments transitioning from dry to fully saturated states, followed by three progressive partial desaturations steps via nitrogen gas injection and subsequent three progressive re-saturations. µCT scans were performed with 2001 projections and 17.21 µm voxel size resolution for each image. SIP data, spanning the 10 mHz – 45 kHz frequency range, were integrated with µCT-derived pore network models to analyze resistivity variations as functions of pore size, connectivity, and tortuosity.
Our results reveal that simultaneous Spectral Induced Polarization and X-ray micro-computed tomography measurements capture transient fluid redistribution processes, providing enhanced interpretability of bulk electrical responses. We observed significant hysteresis in Spectral Induced Polarization data during drainage and re-saturation cycles, linked to pore-scale fluid trapping and structural changes. Furthermore, resistivity predictions from the pore network model aligned closely with experimental data, validating the integration's robustness.
This novel experimental set-up lay the groundwork to the study of coupled structural and electrical dynamics in porous media, offering valuable insights into pressure and temperature dependant multi-phase subsurface processes including ones with mineral reactivity. By bridging the observation gap between pore-scale processes and bulk geophysical responses in 3D, this approach sets a new standard for experimental petrophysics.
How to cite: Omar, H., Bultreys, T., Rembert, F., Manoorkar, S., Caterina, D., Nguyen, F., and Hermans, T.: A Novel Experimental Set-up for Simultaneous Acquisitions of Spectral Induced Polarization and X-ray µCT Data in 3D Porous Media, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13878, https://doi.org/10.5194/egusphere-egu25-13878, 2025.
Drilled-core samples (21ESDP-205, 21ESDP-206) collected from off eastern Geoje Island (Korea Strait) were used to characterize physical properties of the area with respect to sedimentary depth. Laboratory analyses of the acoustic and physical properties of the samples were conducted and shear-wave velocity, velocity ratio, poisson’s ratio, and velocity anisotropy were calculated. In particular, lithological characteristics of two drilled-core samples were interpreted using both visual description and geoacoustic and physical property data. In addition to visual description, a relationship between mean grain size and dry bulk density was used to interpret lithological characteristics. In other word, the values greater than approximately 1 g/cm3 in dry bulk density may be corresponded toward coarse grained sediments, except for the relationship caused by compaction effect. As a result, geoacoustic and physical property data at the two sites were in correlation with lithological characteristics alternating (mainly between sandy mud and muddy sand) at sedimentary depth. The relationships between velocity and porosity showed better correlation than those of between velocity and wet bulk density. Geoacoustic units (GAUs) identified from sites 21ESDP-205 and 21ESDP-206 were divided into 12 and 14 units with sedimentary depth, respectively, and geoacoustic models were developed for the sedimentary layers around these sites. The upper sediments in the study area were largely originated and redistributed from the Nakdong River, caused by sea-level changes during the Quaternary. These results suggest that sedimentary physical properties in the region were primarily controlled by depositional processes linked to the river, and that sea-level changes played a significant role as a dominant sedimentary process during the Quaternary.
How to cite: Kim, G. Y., Park, K., Hong, S.-H., Lee, G. S., Yoo, D.-G., and Kim, S.-P.: Geoacoustic model based on physical property characterization of Quaternary sediments off eastern Geoje Island, Korea Strait, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-14022, https://doi.org/10.5194/egusphere-egu25-14022, 2025.
Over the past few years, several scientific projects at Bochum University of Applied Sciences have developed new methods and procedures for determining the petrophysical properties of small rock samples. These workflows, which are part of Digital Rock Physics (DRP) and have been published in peer-reviewed journals, are based on the non-destructive testing of samples using X-ray computed tomography.
After the subsequent semi-automated segmentation - i.e. the identification of the pore space and different minerals in the 3D scan - the thermophysical, hydraulic and mechanical properties of the rock sample relevant for geothermal projects are calculated using numerical methods. The method can be applied to cuttings (drill cuttings produced during the drilling process). The method thus offers the possibility of determining the relevant rock parameters over the entire drilling section and without the use of expensive core drilling methods, which can save costs on one hand and significantly improve the database for the subsequent numerical simulation of the geothermal plant on the other
We present the first results of the ongoing SimBoL-project. A selection of Carbonate cuttings were scanned with a high-resolution CT device. Those digital images were transformed into digital rock samples which are the basis of numerical simulations to determine the permeability, the heat conductivity and the mechanical rock properties. A first qualitative comparison with borehole data is presented.
How to cite: Serje Gutierrez, A., Balcewicz, M., and Saenger, E. H.: Physical Properties of Carbonate Rock Cuttings vs. Borehole Data: Insights from Ongoing Research, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-16147, https://doi.org/10.5194/egusphere-egu25-16147, 2025.
Tight sandstone reservoirs are a primary focus of research on the geological exploration of petroleum. However, many reservoir classification criteria are of limited applicability due to the inherent strong heterogeneity and complex micropore structure of tight sandstone reservoirs. This investigation focused on the Chang 8 tight reservoir situated in the Jiyuan region of the Ordos Basin. High-pressure mercury intrusion experiments, casting thin sections, and scanning electron microscopy experiments were conducted. Image recognition technology was used to extract the pore shape parameters of each sample. Based on the above, through grey relational analysis (GRA), analytic hierarchy process (AHP), entropy weight method (EWM) and comprehensive weight method, the relationship index Q1 between initial productivity and high pressure mercury injection parameters and the relationship index Q2 between initial productivity and pore shape parameters are obtained by fitting.Then a dual-coupled comprehensive quantitative classification prediction model for tight sandstone reservoirs was developed based on pore structure and shape parameters. A quantitative classification study was conducted on the target reservoir, analyzing the correlation between reservoir quality and pore structure and shape parameters, leading to the proposal of favourable exploration areas.The research results showed that when Q1 ≥ 0.5 and Q2 ≥ 0.5, the reservoir was classified as type I. When Q1 > 0.7 and Q2 > 0.57, it was classified as type I1, indicating a high-yield reservoir. When 0.32 < Q1 < 0.47 and 0.44 < Q2 < 0.56, was classified as type II. When 0.1 < Q1 < 0.32 and 0.3 < Q2 < 0.44, it was classified as type III. Type I reservoirs exhibit a zigzag pattern in the northwest part of the study area. Thus, the northwest should be prioritized in actual exploration and development. Additionally, the initial productivity of tight sandstone reservoirs showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. Conversely, it demonstrated a negative correlation with the median pressure and displacement pressure. The perimeters of pores, their circularity, and the length of the major axis showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. On the other hand, they exhibited a negative correlation with the median pressure and displacement pressure. This study quantitatively constructed a new classification and evaluation system for tight sandstone reservoirs from the perspective of microscopic pore structure, achieving an overall model accuracy of 93.3%. This model effectively predicts and evaluates tight sandstone reservoirs. It provides new guidance for identifying favorable areas in the study region and other tight sandstone reservoirs.
How to cite: Song, X., Feng, C., Li, T., Zhang, Q., Pan, X., Sun, M., and Ge, Y.: Quantitative classification evaluation model for tight sandstone reservoirs based on machine learning, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-122, https://doi.org/10.5194/egusphere-egu25-122, 2025.
The complex pore structure and diverse mineralogy of shale impart specific elastic properties to the saturated rock, characterized by notable heterogeneity and pronounced frequency dependence. These intricate elastic behaviors of shale present challenges to conventional rock physics-based quantitative interpretation of reservoirs. This study employed an integrated approach combining cross-band rock physics measurement, digital rock imaging, and numerical simulations. The research focused on the inter-salt shale oil reservoir of the Qianjiang Formation (Jianghan Basin, China), to investigate anisotropy and dispersion phenomena. Initially, various scanning imaging techniques were applied to analyze the microstructural features of natural rocks, leading to the creation of a set of virtual cores by numerical reconstruction. Subsequently, static and dynamic elastic simulations were performed to monitor wave-induced fluid flow, revealing the influence of microstructure, mineral composition, and physical properties on dispersion and attenuation. Finally, based on the simulations, the applicability of various rock physical theories was evaluated, and we proposed a set of anisotropic dispersion theory models consistent with the geological characteristics and elastic response rules of shale oil reservoirs. The results compare satisfactorily with ultrasonic velocity, well-logging data, and stress-strain measurements. This approach underscores the value of integrative research, combining experimental data, theoretical models, and digital rock physics techniques, offering new insights into the refinement of quantitative reservoir characterization in complex geological environments.
How to cite: Yan, B., Zhao, J., Li, J., Ma, M., Sun, Y., Xiao, Z., Lu, C., Luo, X., Ma, J., and Sun, L.: Application of digital rock characterization and elastic simulation to rock physics modelling in shale reservoirs, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7669, https://doi.org/10.5194/egusphere-egu25-7669, 2025.
Velocity dispersion and attenuation frequently occur in fluid-saturated reservoir rocks. However, most current reservoir prediction and fluid identification methods overlook the effects of seismic wave dispersion and attenuation. Instead, researchers primarily rely on frequency-independent elastic data and theoretical models. Frequency-dependent elastic parameters, in contrast, reveal more detailed information about reservoir fluids and significantly enhance the accuracy of fluid identification and reservoir prediction.Rock physics experiments and theoretical analyses have shown that rocks saturated with different fluids exhibit distinct velocity dispersion gradients. This finding underscores the potential of the velocity dispersion gradient as a reliable indicator for identifying target reservoirs. To extract the velocity dispersion gradient attribute, this study incorporates a frequency term into the Zoeppritz approximation and develops a frequency-dependent AVO inversion equation. The study applies time-frequency analysis to seismic data, deriving the time-frequency spectrum. By integrating the time-frequency spectrum with the frequency-dependent AVO inversion equation, the method extracts the velocity dispersion gradient attribute.The study further analyzes how various factors influence the accuracy of dispersion gradient attribute inversion, using theoretical models and seismic physical analyses. It validates the reliability of the dispersion gradient inversion method and demonstrates its effectiveness in delineating reservoirs and identifying fluids.This research provides a robust approach for improving the precision of reservoir prediction and advancing fluid identification techniques.
How to cite: Zhang, Y., Ouyang, F., Qing, Y., Zhao, J., Li, Z., Ma, M., Yan, B., and Sun, Y.: Fluid identification and reservoir prediction based on frequency-dependent AVO inversion, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7721, https://doi.org/10.5194/egusphere-egu25-7721, 2025.
The dolomite reservoir in the fourth member (Ma4) of the Ordovician Majiagou Formation is a significant gas reservoir in the Ordos Basin, China. It consists of thin layers within limestone, characterized by a mottled dolomitic limestone texture, with pores formed by complex diagenetic processes that result in low porosity values. These layers show minimal petrophysical contrast with the surrounding rock, complicating identification and property prediction using conventional elastic attributes like P- and S-impedances. To overcome this challenge, the study utilizes Lamé impedances (λρ and μρ), which expand the P- and S-impedance cross-plot space, enhancing the identification of reservoir zones. First, Lambda-rho and Mu-rho impedances were derived from logging data and cross-plotted to create a locally constrained rock physics template based on porosity and dolomite content along the vertical direction. This template was then applied to the Lambda-rho and Mu-rho attributes generated from seismic pre-stack inversion. The rock physics template (λμρ cross-plot) accurately predicted dolomite content and porosity from seismic data, achieving high precision compared to the conventional porosity and dolomite content logs. This study highlights the effectiveness of Lamé parameters (λμρ) in predicting and estimating reservoir property distributions, providing valuable insights into the geological origins of dolomite and advancing hydrocarbon exploration and development.
How to cite: Said, A., Zhao, J., Li, J., and Sun, Y.: Utilization of magic Lamé impedances on carbonate reservoirs' lithological and porosity characterization, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7725, https://doi.org/10.5194/egusphere-egu25-7725, 2025.
Seismoelectric phenomena, caused by electrokinetic coupling between seismic and electromagnetic fields, have attracted significant interest in geological reservoir characterization for their sensitivity to pore-fluid contrasts. Consequently, most studies have focused on seismic-to-electromagnetic conversions at fluid/poroelastic and poroelastic/poroelastic interfaces. However, when investigating permeable zones in unfractured media, often associated with geothermal reservoirs, poroelastic/elastic interfaces must be considered. To address this, we conducted laboratory and numerical experiments using a container filled with quartz sand saturated with a NaCl solution, with one of five thin layers made of different materials (four elastic and one poroelastic) embedded within the sand. Our numerical simulations assume an elastic medium as poroelastic using limiting values for certain physical parameters. The results confirm that seismoelectric conversion occurs at poroelastic/elastic transitions, showing a strong agreement between experiments and simulations. Furthermore, we inferred that the amplitudes of electromagnetic waves generated at poroelastic/elastic interfaces are mainly controlled by contrasts of dielectric permittivity.
How to cite: Brito, D., Bernardo, N., Martins-Gomes, V., and Bordes, C.: Seismoelectric conversion at poroelastic/elastic interfaces and the role of dielectric permittivity: experimental and numerical analysis, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12758, https://doi.org/10.5194/egusphere-egu25-12758, 2025.
Compared to shallow coal seams, deep coal bed methane (CBM) is characterized by a higher content of free gas, which typically exhibits the traits of “immediate gas production upon well startup and high output upon gas production.” It has become an important natural gas resource for China to optimize its energy structure and achieve carbon peaking and carbon neutrality goals. Cleats serve as the primary pathways for gas desorption and migration in deep coal seams and act as weak structural planes of coal rocks, playing a crucial role in controlling both wellbore wall stability during drilling and fracture propagation during hydraulic fracturing. Therefore, the degree of Cleat development is regarded as a critical indicator for the efficient development of deep CBM. At present, most Cleat evaluation methods in coal rocks are derived from shallow coal seam studies, which primarily rely on compressional wave velocity and shear wave velocity characteristics. However, in deep coal seams subjected to high stress and strong compaction, Cleats often exhibit low aperture, resulting in weak logging responses. This makes the methods developed for shallow coal seams inapplicable, highlighting the lack of effective approaches for evaluating Cleats in deep coal seams. This study begins by conducting experiments on 70 coal rock samples with varying degrees of Cleat development. Combined with numerical simulations of coal rocks with different Cleat apertures, the experimental and simulation analyses Cleatly confirm the effectiveness of acoustic attenuation in evaluating Cleat development in deep coal seams. Compared to velocity and anisotropy, attenuation is more sensitive to Cleats with low aperture or partial closure. Based on dual-porosity medium theory and squirt flow theory, a rock physics characterization model of Cleat-related acoustic attenuation in deep coal seams is established. Subsequently, an inversion method for Cleat development degree based on acoustic attenuation is developed using an iterative method and applied to actual well evaluations. The results demonstrate that the proposed logging evaluation method for Cleat development based on acoustic attenuation more accurately reflects the degree of Cleat development. Compared to the velocity-based methods for shallow coal seams, the relative error is reduced from 27% to 18%, indicating that attenuation is more effective than velocity in assessing Cleat development in deep coal seams.
fig1. Comparison of Logging Evaluation Results for Cleat Development in Deep Coal Rocks
fig2. Comparison of Relative Errors in Logging Evaluation of Cleat Development in Deep Coal Rocks
How to cite: Ni, Z., Li, W., Liu, X., and Liang, L.: A Logging Evaluation Method for Cleat Development in Deep Coal Rocks Based on Acoustic Attenuation, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-15257, https://doi.org/10.5194/egusphere-egu25-15257, 2025.
