Petrophysics and rock-physics across the scales: integrating models, laboratory experiments and field geophysical studies



Geophysical methods have a great potential for characterizing subsurface properties and processes to inform geological, reservoir, hydrological, and biogeochemical studies. In these contexts, the classically used geophysical tools only provide indirect information about subsurface heterogeneities, reservoir rocks characteristics, and associated processes (e.g. flow, transport, biogeochemical reactions). Petrophysical relationships hence have to be developed to provide links between physical properties (e.g. electrical conductivity, seismic velocity or attenuation) and the intrinsic parameters of interest (e.g. fluid content, hydraulic properties, pressure conditions). In addition, geophysical methods are increasingly deployed as time-lapse, or even continuous, and distributed monitoring tools on more and more complex environments. Here again, there is a great need for accurate and efficient physical relationships such that geophysical data can be correctly interpreted (e.g. included in fully coupled inversions).
Establishing such models requires multidisciplinary approaches since involved theoretical frameworks differ. Each physical property has its intrinsic dependence to pore-scale interfacial, geometrical, and biogeochemical properties or to external condition (such as pressure or temperature). Each associated geophysical method has its specific investigation depth and spatial resolution which adds a significant level of complexity in combining and scaling theoretical developments with laboratory studies/validations and/or with field experiments. Ultimately, as inferred from geophysics, one needs to know the poroelastic properties and effective stress in place at depth.
This session consequently invites contributions from various communities to share their models, their experiments, or their field tests and data in order to discuss about multidisciplinary ways to improve our knowledge on reservoir and near surface environment.

Convener: Lucas Pimienta | Co-conveners: Ludovic Bodet, Damien Jougnot, Chi Zhang
vPICO presentations
| Wed, 28 Apr, 11:00–12:30 (CEST)

vPICO presentations: Wed, 28 Apr

Chairpersons: Damien Jougnot, Ludovic Bodet, Chi Zhang
The CO2 studies
Ismael Himar Falcon-Suarez

Experimental rock physics allows the study of specific geological phenomena in a controlled manner. The experimental data are used to develop and calibrate predictive numerical models, which ultimately improve our understanding of natural processes and interpretation of field scale datasets. However, upscaling laboratory geophysical datasets to explain large scale geological complexes is challenging and by definition imprecise, as core-scale experiments are not fully representative of the events occurring in the field. This challenge gains in complexity with the increasing number of involved parameters and with changing environmental conditions. Nowadays, one of the most challenging rock physics areas is Carbon Capture Utilization and Storage (CCUS).

CCUS is a realistic global scale mitigation solution to tackle the excess of CO2 expelled from industrial production and sequestering it into deep reservoir formations, while attempting at generate energetic benefits from this process (e.g., enhanced oil recovery and geothermal energy). When CO2 is injected in rocks, the parental pore fluid is displaced by CO2 and therefore the effective bulk modulus of the fluid (and the rock) changes; if the rock and/or the fluid are reactive to CO2, then the rock frame and fluid composition are also changing parameters, affecting both the elastic and hydrodynamic properties of the original rock.

In this contribution, I examine the complexity of the geophysical interpretation of a specific CCUS-related process: CO2-induced salt precipitation in saline aquifers. In essence, injected CO2 dry out the brine and salt precipitates in the pores, leading to some degree of clogging that depends on, but not exclusively, the pore size, salt volume and pore connectivity. This phenomenon affects the injectivity of the CO2 storage site, which could lead to pressure built-up events and ultimately compromise the geomechanical integrity of the reservoir. Therefore, an early warning of CO2-induced salt precipitation is essential to apply specific mitigation strategies in a timely manner.

Salt precipitation is a rapid, self-enhanced process, with a footprint in the geophysical record that has to be isolated from that of the CO2 fluid replacement and other potential CO2-induced rock reactions. When the geophysical data include seismic and electromagnetic surveys, S-waves provide information about the changes in the rock frame, while P-waves and electrical resistivity would help to distinguish between CO2, brine and salt fractions. Here, I use a dataset generated in the laboratory using ultrasonic P- and S-waves attributes, resistivity and axial deformation, during a CO2-brine flow-through experiment with salt precipitation, to discuss the potential of the rock physics to detect and quantify dynamic changes in the bulk properties of reservoir rocks.  

How to cite: Falcon-Suarez, I. H.: Joint elastic-electrical monitoring for detecting and quantifying CO2-induced salt precipitation during geological carbon and storage, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9920, https://doi.org/10.5194/egusphere-egu21-9920, 2021.

Chi Zhang, Siyan Liu, and Reza Barati

The continuously rising threat of global warming caused by human activities related to CO2 emission is facilitating the development of greenhouse gas control technologies. Subsurface CO2 injection and sequestration is one of the promising techniques to store CO2 in the subsurface.  However, during CO2 injection, the mechanisms of processes like injectant immobilizations and trapping and pore-scale geochemical reactions such as mineral dissolution/precipitation are not well understood. Consequently, the multi-physics modeling approach is essential to elucidate the impact of all potential factors during CO2 injection, thus to facilitate the optimization of this engineered application. 

Here, we propose a coupled framework to fully utilize the capabilities of the geochemical reaction solver PHREEQC while preserving the Lattice-Boltzmann Method (LBM) high-resolution pore-scale fluid flow integrated with diffusion processes. The model can simulate the dynamic fluid-solid interactions with equilibrium, kinetics, and surface reactions under the reactive-transport scheme.  In a simplified 2D spherical pack, we focused on examining the impact of pore sizes, grain size distributions, porosity, and permeability on the calcite dissolution/precipitation rate. Our simulation results show that the higher permeability, injection rate, and more local pore connectivity would significantly increase the reaction rate, then accelerate the pore-scale geometrical evolutions. Meanwhile, model accuracy is not sacrificed by reducing the number of reactants/species within the system.

Our modeling framework provides high-resolution details of the pore-scale fluid-solid interaction dynamics. To gain more insights into the mineral-fluid interfacial properties during CO2 sequestration, our next step is to combine the electrodynamic forces into the model. Potentially, the proposed framework can be used for model upscaling and adaptive subsurface management in the future.  

How to cite: Zhang, C., Liu, S., and Barati, R.: Pore-scale hydrodynamic evolution within carbonate rock during CO2 injection and sequestration, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9578, https://doi.org/10.5194/egusphere-egu21-9578, 2021.

Rumbidzai Nhunduru, Omid Shahrokhi, Krystian Wlodarczyk, Amir Jahanbakhsh, Susana Garcia, and Mercedes Maroto-Valer

Immiscible fluid displacement and the trapping of residual oil and gas phases in the pore spaces of reservoir rocks is critical to geological operations such as carbon geo-sequestration and enhanced oil recovery. In carbon geo-sequestration, residual trapping is advantageous because it ensures long-term storage security of carbon dioxide (CO2). In contrast, residual trapping can pose significant challenges during waterflooding in oil recovery operations where large volumes of oil may remain trapped in the interstitial spaces of the porous reservoir rock and cannot be extracted, thereby reducing the efficiency of the recovery process. In such operations, residual trapping is strongly influenced by the inherent surface roughness of the solid rock matrix amongst many factors. Surface roughness occurs in natural reservoir rocks as a result of geological processes that physically, chemically or biologically convert sediments into sedimentary rock (known as diagenesis) and weathering.

The effects of surface roughness on immiscible two-phase flow are currently not well understood. Previous investigations into residual trapping in porous media have mainly focused on the influence of factors such as pore geometry, wettability, fluids interfacial tension, mobility ratio and injection scenarios. Although some of these studies acknowledge the potential effect of surface roughness, there is still a lack of quantitative characterization and understanding of the influence of surface roughness on immiscible two-phase displacements in porous media.

In this study, the impacts of surface roughness on immiscible two-phase displacement are quantified. Immiscible two-phase displacement of air by water was conducted in a custom laser-manufactured glass microfluidic chip (micromodel). The glass chip comprised a 2.5D micro-structure analogous to the pore network pattern (micro-structure) of a natural reservoir rock, Oolitic limestone. The pore network pattern consisted of cylindrical pillars 400 µm in diameter arranged in a rhombohedra type of packing, generated on to a glass substrate using an ultrafast, pulsed picosecond laser. Surface roughness is an innate characteristic of laser machined surfaces and as a result, small variations in depth of the porous micro-structure were observed (50 ± 8 µm). The average surface roughness (Sa) of the laser-machined structure was measured to be 1.2 μm.

Experimental results for the rough micromodel exhibit high repeatability of fluid displacement patterns (preferential flow pathways) demonstrating that surface roughness has a strong influence on fluid invasion patterns and sweep efficiency and its effects must not be ignored. To ascertain the effects of surface roughness on the fluid displacement process, a direct numerical simulation (DNS) of the fluid displacement process was performed in OpenFoam using the Volume of Fluid (VOF) method assuming zero surface roughness. Comparing the experimental results with the numerical simulations, we show that surface roughness can significantly enhance residual trapping in porous media by up to 49.2%.


How to cite: Nhunduru, R., Shahrokhi, O., Wlodarczyk, K., Jahanbakhsh, A., Garcia, S., and Maroto-Valer, M.: The Effects of Surface Roughness on Fluid Displacement Mechanisms and Residual Residual Trapping - A Pore Scale Investigation, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13987, https://doi.org/10.5194/egusphere-egu21-13987, 2021.

Samuel Chapman, Jan V. M. Borgomano, Beatriz Quintal, Sally M. Benson, and Jerome Fortin

Monitoring of the subsurface with seismic methods can be improved by better understanding the attenuation of seismic waves due to fluid pressure diffusion (FPD). In porous rocks saturated with multiple fluid phases the attenuation of seismic waves by FPD is sensitive to the mesoscopic scale distribution of the respective fluids. The relationship between fluid distribution and seismic wave attenuation could be used, for example, to assess the effectiveness of residual trapping of carbon dioxide (CO2) in the subsurface. Determining such relationships requires validating models of FPD with accurate laboratory measurements of seismic wave attenuation and modulus dispersion over a broad frequency range, and, in addition, characterising the fluid distribution during experiments. To address this challenge, experiments were performed on a Berea sandstone sample in which the exsolution of CO2 from water in the pore space of the sample was induced by a reduction in pore pressure. The fluid distribution was determined with X-ray computed tomography (CT) in a first set of experiments. The CO2 exosolved predominantly near the outlet, resulting in a heterogeneous fluid distribution along the sample length. In a second set of experiments, at similar pressure and temperature conditions, the forced oscillation method was used to measure the attenuation and modulus dispersion in the partially saturated sample over a broad frequency range (0.1 - 1000 Hz). Significant P-wave attenuation and dispersion was observed, while S-wave attenuation and dispersion were negligible. These observations suggest that the dominant mechanism of attenuation and dispersion was FPD. The attenuation and dispersion by FPD was subsequently modelled by solving Biot’s quasi-static equations of poroelasticity with the finite element method. The fluid saturation distribution determined from the X-ray CT was used in combination with a Reuss average to define a single phase effective fluid bulk modulus. The numerical solutions agree well with the attenuation and modulus dispersion measured in the laboratory, supporting the interpretation that attenuation and dispersion was due to FPD occurring in the heterogenous distribution of the coexisting fluids. The numerical simulations have the advantage that the models can easily be improved by including sub-core scale porosity and permeability distributions, which can also be determined using X-ray CT. In the future this could allow for conducting experiments on heterogenous samples.

How to cite: Chapman, S., Borgomano, J. V. M., Quintal, B., Benson, S. M., and Fortin, J.: Seismic wave attenuation due to fluid pressure diffusion at the mesoscopic scale: an experimental and numerical study, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-16072, https://doi.org/10.5194/egusphere-egu21-16072, 2021.

Seismic properties across scales
Davide Geremia, Christian David, Christophe Barnes, Beatriz Menéndez, Jérémie Dautriat, Lionel Esteban, Joel Sarout, Sara Vandycke, and Fanny Descamps

Monitoring of fluid movements in the crust is one of the most discussed topics in oil & gas industry as well as in geothermal systems and CO2 storage, but still remains a challenge. The seismic method is one of the most common ways to detect the fluid migration. However, the use of ultrasonic monitoring at the sample scale in laboratory experiments persists as the most effective way to highlight large scale observations in which the boundary conditions are not well constrained.

To unravel the fluid effect on P-wave and S-wave velocity, we performed mechanical experiments coupled with ultrasonic monitoring on Obourg chalk from Mons basin (Belgium). Water injection tests under critical loading, imbibition tests and evaporation tests provided a full spectrum of observations of fluid-induced wave alteration in term of propagation time and attenuation.

The analysis of these experimental results showed that significant velocity dispersion and attenuation developed through variations in water saturation, and that these processes are linked to the presence of patches of water and air in the pore space.

We used the White’s formulation to model the relaxation effects due to spherical pockets of air homogeneously distributed in a water-saturated medium. In this framework, the pressure induced by the passing wave, produces a fluid flow across the water-air boundary with consequent energy loss.

This model reproduces both qualitatively and quantitatively the experimental results observed on the water injection tests. Indeed, it is shown that the progressive water saturation or desaturation of this chalk, generates a shift of the critical frequency (from the undrained relaxed towards unrelaxed regimes) which at some point matches the resonance frequency of the piezoelectric transducers used in the experimental setup (0.5 MHz). This phenomenon allowed us to get a continuous recording of the relaxation processes induced by saturation variations.

The outcomes of this work can significantly improve the actual knowledge on coupled effects of waves and fluids which is a crucial aspect of fluid monitoring in the context of reservoir evaluation and production.

How to cite: Geremia, D., David, C., Barnes, C., Menéndez, B., Dautriat, J., Esteban, L., Sarout, J., Vandycke, S., and Descamps, F.: Laboratory experiments of water injection coupled with ultrasonic monitoring reveal wave-induced fluid flow in microporous carbonate rock, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9230, https://doi.org/10.5194/egusphere-egu21-9230, 2021.

Santiago Solazzi, Ludovic Bodet, Klaus Holliger, and Damien Jougnot

Estimation of water content in the shallow subsurface using seismic data is a complex task of increasing importance in the overall field of hydrogeophysics. In this context, the velocities of compressional (Vp) and shear (Vs) waves can be used to infer strong water content variations in unconsolidated soils, such as, the presence of the water table, by means of Vp/Vs ratio estimations. This approach, which is based on first-arrival time data, generally does not permit a proper quantification of the water content distribution in the partially saturated zone. Conversely, field and laboratory measurements indicate that surface-waves are indeed remarkably sensitive to both the water table depth and the saturation characteristics in the overlaying capillary fringe. This apparent difference in sensitivity between body and surface waves cannot be explained using conventional models. Observations and experiments show that the effective stress of unconsolidated porous media is not only affected by the overburden stress and pore pressures, as classic models assume, but also by capillary forces, which tend to stiffen the soil at relatively low saturations. In this work, we extend seminal rock physics models to include capillary suction effects in the effective stress of the soil. This approach provides effective elastic moduli and, thus, Vp and Vs, which are depth- and saturation-dependent. Then, we solve the quasi-static fluid flow equations in a porous medium and obtain saturation profiles for a given water table depth. This information, combined with the proposed rock physics model, permits to simulate simple seismic data sets, that is, body-wave first-arrival times and surface-wave phase velocities, for different water table depths and soil textures. Our results clearly show that capillary effects allow to explain the apparent difference in sensitivity between body- and surface-wave signatures in response to small water content variations in the partially saturated zone. Capillary effects are primarily relevant in porous media composed by relatively small characteristic grain sizes. We conclude that the proposed framework has the potential to fundamentally improve our characterization of near-surface environments using both active and passive seismic methods.

How to cite: Solazzi, S., Bodet, L., Holliger, K., and Jougnot, D.: Capillary suction effects on surface-wave dispersion in partially saturated soils, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12197, https://doi.org/10.5194/egusphere-egu21-12197, 2021.

Felix Kästner, Simona Pierdominici, Alba Zappone, Luiz F. G. Morales, Anja M. Schleicher, Franziska D. H. Wilke, and Christian Berndt

Metamorphic and deformed rocks in thrust zones show particularly high seismic anisotropy causing challenges for seismic imaging and interpretation. A good example is the Seve Nappe Complex in Jämtland, Sweden, an exhumed orogenic thrust zone characterized by a strong but incoherent seismic reflectivity and considerable seismic anisotropy. However, only little is known about the origin of the anisotropy in relation to composition, structural influences, and implications for measurements at different seismic scales. We present an integrative study of the seismic anisotropy at different scales combining mineralogical composition, microstructural analyses and seismic laboratory experiments from samples of the 2.5 km-deep COSC-1 borehole. While there is a pronounced crystallographic preferred orientation in most of the core samples, variations in anisotropy correlate strongly with bulk mineral composition and dominant core lithology. Based on three major lithologic different facies (felsic gneiss, amphibole-rich rocks, and mica schists), we propose an anisotropy model for the full length of the borehole, which indicates two prevailing anisotropic units. Comparison of laboratory seismic measurements and electron-backscatter diffraction (EBSD) data reveals a strong scale-dependence, which is more pronounced in the highly deformed, heterogeneous samples. This highlights the need for comprehensive cross-validation of microscale anisotropy analyses with additional lithological data when integrating seismic anisotropy through seismic scales.

How to cite: Kästner, F., Pierdominici, S., Zappone, A., Morales, L. F. G., Schleicher, A. M., Wilke, F. D. H., and Berndt, C.: Seismic anisotropy in metamorphic rocks from the COSC-1 borehole, Sweden: A cross-scale investigation from thin section analysis to seismic scales, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12483, https://doi.org/10.5194/egusphere-egu21-12483, 2021.

Zhenya Zhou, Eva Caspari, Nicolás D. Barbosa, Andrew Greenwood, and Klaus Holliger

Fractures, which are ubiquitous in the Earth’s upper crust, have significant impacts on a wide range of human activities, and, hence, their adequate characterization is of wide interest and importance. Seismic methods have significant potential for effectively addressing this objective. When a seismic wave propagates across a fluid-filled fracture, its amplitude is diminished and its travel time is increased. Based on the linear slip theory, the associated amplitude decays and phase delays can be used to estimate the mechanical compliance of fractures. Full-waveform sonic (FWS) log data are particularly well-suited for this purpose. While the amplitudes of FWS data acquired during standard continuous logging runs (tool being moved uphole at a constant logging speed) can be somewhat unstable, the associated first-arrival travel times are generally quite robust. In this work, we exploit the relation between the time delay that seismic waves experience across fractures and relate them to the associated compliances. Specifically, we estimate fracture compliance from the differences in group time delay of the refracted P-wave between fractured and non-fractured sections along a borehole. Numerical simulations indicate that the proposed method provides reliable compliance estimates not only for individual fractures, but also for sets of multiple discrete fractures. This finding is corroborated by applying our approach to FWS log data acquired in the course of standard logging runs in the Bedretto Underground Laboratory (www.bedrettolab.ethz.ch). Our estimates are comparable to previously inferred compliance values in a closely comparable geological environment (Grimsel test site, www.grimsel.com). The latter were inferred under rather ideal conditions, involving the quasi-static acquisition of the FWS data as well as the combination of amplitude and travel time information for their interpretation. An interesting and important open question, which we plan to address in the following, concerns the influence of the heterogeneity of the host rock embedding the fractures on compliance estimation in general and on the proposed method in particular.

How to cite: Zhou, Z., Caspari, E., D. Barbosa, N., Greenwood, A., and Holliger, K.: Estimation of fracture compliance based on group delays inferred from full-waveform sonic log data, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10820, https://doi.org/10.5194/egusphere-egu21-10820, 2021.

Peter Lelièvre, Zeudia Pastore, Nathan Church, Madeline Lee, Hirokuni Oda, and Suzanne McEnroe

We are using 3D magnetic vector inversion (MVI) of scanning magnetic microscopy (SMM) data to investigate the fine‐scale magnetization of rock samples, and particularly of their remanence carriers, which can record geologically meaningful information. Previous investigations of magnetite grains suggest variable remanence intensities and directions coherent with multidomain behaviour. This research seeks to improve our understanding of the contribution of different microstructures on remanence acquisition.

SMM offers a spatial resolution down to tens of micrometers, allowing detailed investigation of discrete magnetic mineral grains, or magnetic textures and structures. However, all magnetic measurements are, at some scale, bulk measurements. Further analysis of the data is required to extract information about the magnetization within the samples: for this, we employ state-of-the-art MVI methods. The MVI problem suffers from a high degree of nonuniqueness. Additional constraints are required to obtain accurate, reliable and interpretable results. Such constraints are readily available for this application.

SMM instruments use magnetic shields or Helmholtz coils to allow collection of data in controlled magnetic fields, enabling the removal of induced magnetization effects. Measurements can be taken both above and below the sample. Individual magnetized mineral grains are easily outlined through optical and electron microscopy. The internal geometry of the oxide mineral phases and compositions can also be constrained. Physical property information constrains the range of magnetization intensity. As such, there is a tremendous amount of constraining information invaluable for reducing the nonuniqueness of the inverse problem. We use a highly flexible and functional inversion software package, MAGNUM, developed jointly at Mount Allison University and Memorial University of Newfoundland, that allows incorporation of all available constraints.

We take a multitiered approach for investigating specific magnetized grains. First, coarse regional inversions are performed to assess and remove any effects of other magnetized grains in the vicinity. The entire grain is then modelled with a homogeneous magnetization to obtain an approximate but representative bulk magnetization. The grain is then modelled as a collection of independent subdomains, each with a different homogeneous magnetization direction. Subsequently, more heterogeneous scenarios are considered by relaxing inversion constraints until the data can be fit to the desired degree.

Obtaining reliable information about the magnetic mineralogy of rock samples is vital for an understanding of the origin of rock bulk behaviour in both the laboratory and larger scale magnetic surveys. This work is among the first to simultaneously invert SMM data collected above and below a thin sample, which is critical for improving depth resolution on thicker samples. It is also the first time we have been able to incorporate all available constraints into inverse modelling to improve results.

How to cite: Lelièvre, P., Pastore, Z., Church, N., Lee, M., Oda, H., and McEnroe, S.: Constrained Magnetic Vector Inversion of Scanning Magnetic Microscopy Data for Modelling Magnetization of Multidomain Mineral Grains, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-3466, https://doi.org/10.5194/egusphere-egu21-3466, 2021.

Simón Lissa, Matthias Ruf, Holger Steeb, and Beatriz Quintal

Seismic waves are affected by rock properties such as porosity, permeability, grain material and by their heterogeneities as well as by the fluid properties saturating the rocks. Consequently, seismic methods are a valuable tool for the indirect characterization of rocks. For example, at the microscale, the presence of compliant pores (cracks or grain contacts) in fluid-saturated rocks can cause strong seismic attenuation and velocity dispersion. In this case, the deformation caused by a passing wave induces a fluid pressure gradient between compressed compliant pores and much less compressed pores (stiff isometric pores or cracks having a different orientation than the most compressed ones) if they are hydraulically connected. The consequent fluid pressure diffusion (FPD) dissipates seismic energy due to viscous friction in the fluid.

Digital rock physics (DRP) aims to reproduce experimental measurements using numerical simulation in models derived from high resolution rock images. We developed a DRP workflow to calculate the frequency dependent seismic moduli dispersion and attenuation in fluid-saturated models derived from micro X-Ray Computed Tomography (µXRCT) images. Filtering, segmentation and meshing procedures are applied on sub-volumes of different rock images to create 3D numerical models. We apply our workflow to calculate seismic moduli attenuation due to FPD at the microscale (squirt flow). We consider a µXRCT image of a cracked (through thermal treatment) Carrara marble sample. A detailed visualization of the fluid pressure as well as of the energy dissipation rate in the 3D model helps to understand the squirt flow attenuation process at different frequencies.

How to cite: Lissa, S., Ruf, M., Steeb, H., and Quintal, B.: Seismic moduli dispersion and attenuation obtained using Digital Rock Physics, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-5887, https://doi.org/10.5194/egusphere-egu21-5887, 2021.

Across Physical properties
Anthony Clark, Tiziana Vanorio, Andrey Radostin, and Vladimir Zaitsev

An understanding of micro- and macrofracture behavior in low porosity rocks is pertinent to several areas of energy and environmental science such as petroleum production, carbon sequestration, and enhancement of technologies based on geothermal energy, etc. For example, the carbonate reservoirs in dolomitic or micritic formations with matrix porosities below 6% suggest the importance of fracture-augmented permeability in production. Similarly, hydrocarbons have been found on nearly every continent in tight basement rocks, all of which have little matrix porosity and their permeability therefore rely solely on hydraulic connectivity from fractures. For geothermal energy, various igneous and sedimentary rocks (granites, basalts, and limestones) are being exploited across the globe, with some of the lowest porosity and permeability. In all these cases, fractures are necessary to improve rock permeability and thermal exchange between the rock and working fluid, which can be enabled by hydraulic stimulation, as well as by secondary cracking due to extreme temperature gradients from the injection of cold water. The fracture geometry, density, and distribution all together control not only fluid and thermal transport in the rocks, but also their seismic attributes that can be used to extract information about the fractures. 
In order to accurately interpret the seismo-acoustic data (usually, the velocities of compression and shear waves) reliable rock physics models are required. Here, we report the results of interpretation of such experimental data for both as-cored rock samples and those subjected to thermo-hydro-chemo-mechanical damage (THCMD) in the laboratory. For interpretation, we use a convenient model of fractured rock in which fractures are represented as planar defects with decoupled shear and normal compliances. The application of such an approach makes it possible to assess and compare the elastic properties of fractures in the rocks before and after application of THCMD procedures. For the analyzed samples of granites, basalts, and limestones it has been found that for a significant portion of rocks, the ratio of normal-to-shear compliances of cracks significantly differ from the value typical of conventionally assumed penny-shape cracks. Furthermore, for some samples, this ratio appears to be noticeably different for fractures existing in the as-cored rock and arising in the same rock after THCMD procedures. These results indicate that damage to a rock typically changes its compliance ratio since the old and new cracks are likely to have different elastic properties. Our results are also consistent with the notion that a specific damage process occurring for a given microstructure will consistently create cracks with a particular set of elastic properties. The proposed methodology for assessment of elastic properties of cracks in rock samples subjected to thermo-hydro-chemo-mechanical damage has given previously inaccessible useful information about the elastic properties of fractures and can be extended to interpretation of seismic attributes of rocks for a broad range of other applications.

How to cite: Clark, A., Vanorio, T., Radostin, A., and Zaitsev, V.: Assessing elastic properties of cracks in rock samples subjected to thermo-hydro-chemo-mechanical damage, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-6492, https://doi.org/10.5194/egusphere-egu21-6492, 2021.

Martin Balcewicz, Mirko Siegert, Marcel Gurris, David Krach, Matthias Ruf, Holger Steeb, and Erik H. Saenger

Over the last two decades, Digital Rock Physics (DRP) has become a complementary part of the characterization of reservoir rocks due to, among other things, the non-destructive testing character of this technique. The use of high-resolution X-ray Computed Tomography (XRCT) has become widely accepted to create a digital twin of the material under investigation. Compared to other imaging techniques, XRCT technology allows a location-dependent resolution of the individual material particles in volume. However, there are still challenges in assigning physical properties to a particular voxel within the digital twin, due to standard histogram analysis or sub-resolution features in the rock. For this reason, high-resolution image-based data from XRCT, transmitted-light microscope, Scanning Electron Microscope (SEM) as well as inherent material properties like porosity are combined to obtain an optimal spatial image of the studied Ruhr sandstone by a geologically driven segmentation workflow. On the basis of a homogeneity test, which corresponds to the evaluation of the grayscale image histogram, the preferred scan sample sizes in terms of transport, thermal, and effective elastic rock properties are determined. In addition, the advanced numerical simulation results are compared with laboratory tests to provide possible upper limits for sample size, segmentation accuracy, and a calibrated digital twin of the Ruhr sandstone. The comparison of representative grayscale image histograms as a function of sample sizes with the corresponding advanced numerical simulations, provides a unique workflow for reservoir characterization of the Ruhr sandstone.

How to cite: Balcewicz, M., Siegert, M., Gurris, M., Krach, D., Ruf, M., Steeb, H., and Saenger, E. H.: Digital rock physics: A geological driven segmentation workflow for Ruhr sandstone, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-4147, https://doi.org/10.5194/egusphere-egu21-4147, 2021.

Mirko Siegert, Marcel Gurris, and Erik Hans Saenger

Within the scope of the present work, the pressure-dependent effective thermal conductivity of rock samples is simulated. Our workflow can be assigned to the field of digital rock physics. In a first step, a 3D micro-CT scan of a rock sample is taken. Subsequently, the resulting greyscale images are analysed and segmented depending on the occurring phases. Based on this data set, a computational mesh is created and the corresponding thermal conductivities are assigned to each phase. Finally the numerical simulations can be carried out.
For the representation of the pressure dependency we use the approach proposed by Saenger [1]. By making use of the watershed algorithm, boundaries between the individual grains of the rock sample are detected and assigned to an artificial contact phase. In the course of several simulations, the thermal conductivity of the contact phase is continuously increased. Starting with the thermal conductivity of the pore phase and ending with the thermal conductivity of the grain phase. A linear correlation is used to match the thermal conductivity of the contact phase with the pressure of a given experimental data set. This enables a direct comparison between simulation and measurement.
In a further step, the numerical model is calibrated to optimise the agreement between experimental data and simulation results. In particular, starting from two calibration points of the experimental data set, an adjustment of the thermal conductivities in the numerical model is carried out. While the thermal conductivity of the pore phase is held constant during the whole calibration process, thermal conductivities of the grain and contact phase are adjusted.

[1] Saenger et al. 2016. Analysis of high-resolution X-ray computed tomography images of Bentheim sandstone under elevated confining pressures. Geophysical Prospecting, 64(4), 848–859.


How to cite: Siegert, M., Gurris, M., and Saenger, E. H.: Numerical determination of pressure-dependent effective thermal conductivity in Berea sandstone, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-4691, https://doi.org/10.5194/egusphere-egu21-4691, 2021.

Jonas K. Limbrock, Maximilian Weigand, and Andreas Kemna

Geoelectrical methods are increasingly being used for non-invasive characterization and monitoring of permafrost sites, since the electrical properties are sensitive to the phase change of liquid to frozen water. Here, electrical resistivity tomography (ERT) is most commonly applied, using resistivity as a proxy for various quantities, such as temperature or ice content. However, it is still challenging to distinguish between air and ice in the pore space of the rock based on resistivity alone due to their similarly low electrical conductivity. Meanwhile, geoelectrical methods that utilize electrical polarization effects to characterize permafrost are also being explored. For example, the usage of the spectral induced polarization (SIP) method, in which the complex, frequency-dependent impedance is measured, can reduce ambiguities in the subsurface conduction properties, considering the SIP signature of ice. These measurements seem to be suitable for the quantification of ice content (and thus the differentiation of ice and air), and for the improved thermal characterization of alpine permafrost sites. However, to improve the interpretation of SIP measurements, it is necessary to understand in more detail the electrical conduction and polarization properties as a function of temperature, ice content, texture, and mineralogy under frozen and partially frozen conditions.

In the study presented here, electrical impedance was measured continuously using SIP in the frequency range of 10 mHz to 45 kHz on various water-saturated solid rock and loose sediment samples during controlled freeze-thaw cycles (+20°C to -40°C). These measurements were performed on rock samples from different alpine permafrost sites with different mineralogical compositions and textures. For all samples, the resistance (impedance magnitude) shows a similar temperature dependence, with increasing resistance for decreasing temperature. Also, hysteresis between freezing and thawing behavior is observed for all measurements. During freezing, a jump within the temperature-dependent resistance is observed, suggesting a lowering of the freezing point to a critical temperature where an abrupt transition from liquid water to ice occurs. During thawing, on the other hand, there is a continuous decrease in the measured resistance, suggesting a continuous thawing of the sample. The spectra of impedance phase, which is a measure for the polarization, exhibit the same qualitative, well-known temperature-dependent relaxation behaviour of ice at higher frequencies (1 kHz - 45 kHz), with variations in shape and strength for different rock texture and mineralogy. At lower frequencies (1 Hz - 1 kHz), a polarization with a weak frequency dependence is observed in the unfrozen state of the samples. We interpret this response as membrane polarization, which likewise depends on the texture as well as on the mineralogy of the respective sample. This polarization response partially vanishes during freezing. Overall, the investigated SIP spectra do not only show a dependence on texture and mineralogy, but mainly a dependence on the presence of ice in the sample as well as temperature. This indicates the possibility of a thermal characterization, as well as a determination of the ice content, of permafrost rocks using SIP.

How to cite: Limbrock, J. K., Weigand, M., and Kemna, A.: Textural and mineralogical controls on temperature dependent SIP behavior during freezing and thawing, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-14273, https://doi.org/10.5194/egusphere-egu21-14273, 2021.

Yi Zhou, Michele Pugnetti, Anneleen Foubert, Pierre Lanari, Christoph Neururer, and Andrea Biedermann

Magnetic pore fabrics (MPF) are an indirect measure of the 3D pore structure. They are defined by measuring anisotropy of magnetic susceptibility after samples have been impregnated with ferrofluid. Previous studies proposed that MPFs target pores down to 10 nm. Therefore, the method complements X-ray computed tomography (XRCT) datasets, with resolution on the order of 1-10 µm. Empirical relationships exist between MPF and pore fabric, and between MPF and permeability anisotropy. This study investigates quantitative correlations between these three properties, and between measured quantities and digital-rock-model-simulations of permeability anisotropy and MPF. Samples used for this study include natural sedimentary rocks and synthetic samples. Sediments are Plio-Pleistocene calcarenite (Apulia, Italy) with ~50% porosity and complex pore structure, and Upper Marine Molasse sandstone (Belpberg, Switzerland) with 10-20% porosity and relatively homogeneous pore space properties. Synthetic samples were made from quartz sand and calcite powder in different proportions, to simulate sandstone and carbonate rocks. Samples were characterized by pycnometry, XRCT scans, MPF determination and directional permeability measurements to obtain porosity, digital rock models, MPFs and permeability anisotropy. Porosity, permeability anisotropy, and MPFs were also computed based on digital rock models derived from XRCT data, and compared to direct measurements. Permeability anisotropy and MPF are both second-order tensors, representing the average property of the entire sample. To directly relate the XRCT-derived individual pore properties to these second-order tensor quantities, a total shape ellipsoid was computed by adding the second-order tensors reflecting the best-fit ellipsoids of single pores. Once all properties were described by second-order tensors, they were correlated in terms of fabric orientation, degree and shape of anisotropy. The MPF and total shape ellipsoids are coaxial when the samples have sufficiently large pores to be resolved, and good impregnation efficiency, and as expected, total shape ellipsoids have larger anisotropy degree. Preliminary results further indicate that the permeability anisotropy is partly consistent with total shape ellipsoids and MPFs. The defined quantitative relationships facilitate the interpretation of MPF data, thus making the method more applicable to geological and fluid migration studies.

How to cite: Zhou, Y., Pugnetti, M., Foubert, A., Lanari, P., Neururer, C., and Biedermann, A.: Correlations of magnetic pore fabrics with pore fabrics derived from high-resolution X-ray computed tomography and with permeability anisotropy in sedimentary rocks and synthetic samples, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13527, https://doi.org/10.5194/egusphere-egu21-13527, 2021.

Michele Pugnetti, Yi Zhou, and Andrea Biedermann

The magnetic pore fabrics method is a useful technique to investigate the pore fabric of rocks. The method is based on impregnating porous samples with ferrofluid, a colloidal suspension of magnetic nanoparticles (particle size of 10 nm) in water or oil carrier fluid, and measuring the anisotropy of magnetic susceptibility. It succesfully provides the average pore shape and orientation. This information is important to determine the preferred direction of fluid flow. A crucial step in magnetic pore fabric studies is ferrofluid impregnation; several studies pointed out the importance of forced impregnation methods to enhance impregnation efficiency. This study compares directional impregnation techniques (applying external forces along the ferrofluid flow along the axis of the core sample) with standard vacuum- and immersion-based methods. The newly developed or adapted techniques include: (1) pressure experiment: a cylindrical sample is placed in a metal tube under confining pressure of 12 bar, and an external pump-syringe system injects ferrofluid at a constant rate of 100 ml/min that generates a differential pressure of 5 bar; (2) resin flowthrough: vacuum is applied at the bottom of the sample and a mixture of resin and oil-based ferrofluid supplied at the top, so that the resin drags the fluid into the pores, where it hardens; (3) magnetically assisted flowthrough: fluid flow is enforced by the combined action of a hydraulic pressure gradient in the ferrofluid reservoir (~10 kPa) and the magnetic force exerted by the field gradient of about 2 A/m2 in the vicinity of an electric coil. These impregnation methods were tested on natural and synthetic samples, for which previous experiments employing standard impregnation methods exist. The natural samples include calcarenite from Apulia, Italy (50% porosity) and sandstone from Schupfheim, Swiss molasse (20% porosity). Synthetic samples consist of calcite and quartz sand in different proportions, consolidated with liquid glass (sodium silicate) in a cubic consolidation cell (specifically designed for the experiment), applying uniaxial pressure along the z axis, to create uniaxial anisotropy. The cube was dried in the oven for three days and three cylindrical cores were drilled along the x, y and z axes. For each impregnation method, the magnetic anisotropy of the samples was measured before and after impregnation. Impregnation efficiency was tested  using bulk susceptibility measurements, visual microscopic investigations and susceptibility profiles along the flow direction. Initial results show that (1) directional forced impregnation is more efficient than traditional methods in impregnating smaller pores,  avoids particle aggregation, and allows viscous fluid such as resin to acess the sample’s pores; (2) directional impregnation methods require less  fluid;  (3) the distribution of the ferrofluid after impregnation is more uniform, overcoming the difficulty of impregnating the  centre of the sample;  and (4) the fluid flow rate must be faster than the particle aggregation rate. For future studies, directional forced impregnation systems are recommended over standard vacuum- and immersion-based impregnation methods.


How to cite: Pugnetti, M., Zhou, Y., and Biedermann, A.: Experimental improvements for ferrofluid impregnation of rocks using directional forced impregnation methods: results on natural and synthetic samples, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-14695, https://doi.org/10.5194/egusphere-egu21-14695, 2021.