Faults and fracture zones are fundamental features of geological reservoirs that control the physical properties of the rock. As such, understanding their role in in-situ fluid behaviour and fluid-rock interactions can generate considerable advantages during exploration and management of reservoirs and repositories.
Physical properties such as frictional strength, cohesion and permeability of the rock impact deformation processes, rock failure and fault/fracture (re-)activation. Faults and fractures create fluid pathways for fluid flow and allow for increased fluid-rock interaction.
The presence of fluids circulating within a fault or fracture network can expose the host rocks to significant alterations of the mechanical and transport properties. This in turn can either increase or decrease the transmissibility of a fracture network, which has implications on the viability and suitability of subsurface energy and storage projects. Thus, it is important to understand how fluid-rock interactions within faults and fractures may alter the physical properties of the system during the operation of such projects. This is of particular interest in the case of faults as the injection/ remobilisation of fluids may affect fault/fracture stability, and therefore increase the risk of induced seismicity and leakage.
Fieldwork observations, monitoring and laboratory measurements foster fundamental understanding of relevant properties, parameters and processes, which provide important inputs to numerical models (see session “Faults and fractures in geoenergy applications 1: Numerical modelling and simulation”) in order to simulate processes or upscale to the reservoir scale. A predictive knowledge of fault zone structures and transmissibility can have an enormous impact on the viability of geothermal, carbon capture, energy and waste storage projects.
We encourage researchers on applied or interdisciplinary energy studies associated with low carbon technologies to come forward for this session. We look forward to interdisciplinary studies which use a combination of methods to analyse rock deformation processes and the role of faults and fractures in subsurface energy systems, including but not restricted to outcrop studies, monitoring studies, subsurface data analysis and laboratory measurements. We are also interested in research across several different scales and addressing the knowledge gap between laboratory scale measurements and reservoir scale processes.
vPICO presentations: Mon, 26 Apr
Fractures and fracture networks play fundamental roles in the operation of subsurface systems such as geothermal production and geological carbon storage: Fractures are the circulatory systems of such reservoirs, driving them via transport of fluids, gases, heat, and dissolved elements, channelling the flow as both carriers and barriers, and providing connection to the rock matrix. Furthermore, due to their role, they provide important insights into the reservoirs, such as the dominant flow paths, the thermal evolution and the dominant chemical processes taking place and affecting e.g. the permeability via dissolution, precipitation and mechanics within the subsurface.
At Hengill central volcano, SW-Iceland, the subsurface reservoir is utilised for geothermal production, re-injection of geothermal fluids and injection of carbon dioxide (CO2) for the means of mineral CO2 storage, at the two field sites in Nesjavellir and Hellisheidi. The operation involves thousands to millions of tonnes of fluid, steam, and gases that are circulated annually through the subsurface bedrock via extraction and injection. Over 100 production and injection wells have been drilled in the two fields, ranging in depths from 800 m to 3300 m. The increased emphasis on the mapping of surface and subsurface faults and structures, and the opportunity of tracing the fluid flow via injection of tracers into the reinjection wells of the fields has provided deeper understanding of the role of fractures in this fracture dominated reservoir. This knowledge has benefitted the field operation by the drilling of very powerful production wells, and successful injection wells – both in terms of injectivity and their locations, providing pressure support to the geothermal production while preventing thermal breakthrough of colder fluids. Furthermore, the use of tracers has been an invaluable tool for managing injection of dissolved CO2 into fractured basaltic reservoirs for mineral carbon storage, both in terms of quantitative monitoring and detection of dissolved and mineralised CO2.
The utilisation of the Hengill field sites at Nesjavellir and Hellisheidi offers unique opportunities to increase our understanding of subsurface processes, providing large-scale field laboratories with enormous datasets, and building bridges between industry and academia.
How to cite: Snæbjörnsdóttir, S., Ratouis, T., and Gunnarsdóttir, S.: Hengill, SW-Iceland: Operating a fractured reservoir for geothermal production and carbon storage, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13636, https://doi.org/10.5194/egusphere-egu21-13636, 2021.
This study aims to characterize fracture permeability in altered Oligocene-Early Miocene basalts of the Jizan Group, which accumulated in half grabens during the continental rift stage of Red Sea evolution. Unlike fresh basalts, the Jizan Group was affected by low temperature hydrothermal metamorphism, which plugged the original matrix porosity in vesicles, breccias, and interflow layers with alteration minerals. On the other hand, the basalts are pervasively shattered by open closely spaced fractures in several directions. Characterization of these fractures is essential to reducing the fracture permeability uncertainty for mineral carbonation by the dissolved CO2 process such as Carbfix.
Conventional measurements of fracture orientations and densities were initially taken at outcrops of the Jizan Group to characterize the fracture network. Photogrammetry of drone images covering larger areas were then used to create 3D models of the outcrops using Agisoft Metashape, which were analyzed for fracture geometries using Cloud Compare. The automated analysis of fracture orientations and densities compared well with conventional manual measurements. This gives confidence in semi-automated dronebased fracture characterization techniques in 3D, which are faster and less labor intensive, especially for characterization of large and difficult to reach outcrops.
Our fracture characterization will be used to construct 3D fracture permeability models of the Jizan Group for combined physical and chemical simulation of injection of dissolved CO2 from industrial sources into basalts. This will provide essential parameters to mitigate geological risks and to determine depth, spacing, and injection rates in CO2 disposal wells.
How to cite: Al Malallah, M., Fedorik, J., Losi, G., Panara, Y., Menegoni, N., Alafifi, A., and Hoteit, H.: Fracture network analysis for carbon mineralization in basalts of the Oligocene Jizan volcanics, Saudi Arabia, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-16442, https://doi.org/10.5194/egusphere-egu21-16442, 2021.
The success of geological carbon capture and storage projects depends on the integrity of the top seal, confining injected CO2 in the subsurface for long periods of time. Here, faults and related fracture networks can compromise sealing by providing an interconnected pathway for injected fluids to reach overlying aquifers or even the surface or sea bottom. In this work, we apply an integrated workflow  that, combining single fracture stress-permeability laboratory measurements and detailed fault and fracture network outcrop data, builds permeability models of naturally faulted caprock formations for in situ stress conditions.
We focus our study on two-dimensional (2D) fault-related fracturing within caprock sequences cut by extensional faults. 2D data of fault and fracture networks were collected from an Upper Jurassic to Lower Cretaceous shale-dominated succession in the Konusdalen area (Nordenskioldland, Svalbard, Norway). The studied rock succession represents the regional caprock and seal for the reservoir of the nearby Longyearbyen CO2 Lab. By digitising all the visible features over the images and then inputting them into the open-source toolbox FracPaQ , we obtain information about the fault and fracture networks. In particular, we study the variations in fracture size (i.e., length, height) and density distribution near and away from the fault zone(s), together with the connectivity of fractures within the network. These three parameters are fundamental to establish if the network provides permeable pathways. They also enable us to statistically reproduce and upscale a fracture network in a realistic way.
Combining laboratory single fracture stress-permeability measurements with outcrop fracture network data allow us to create an accurate coupled mechanical-hydromechanical model of the natural fracture network and to evaluate the effective permeability of a fault related fracture network. These results are also compared against analytical estimates of effective permeability . With this workflow, we overcome the geometrical simplifications of synthetic fracture models, thus allowing us to establish representative stress-permeability relationships for fractured seals of geological CO2 storage.
Reference:  March et al., 2020, Preprint;  Healy et al., 2017, JSG;  Seavik & Nixon, 2017, WRR
How to cite: Rizzo, R. E., Fazeli, H., Doster, F., Kampman, N., Bisdom, K., Snippe, J., Senger, K., Betlem, P., and Busch, A.: Role of fault and fracture networks to de-risk geological leakage from subsurface energy sites, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8517, https://doi.org/10.5194/egusphere-egu21-8517, 2021.
Fractured crystalline basement units are attracting increasing attention as potential unconventional reservoirs for natural (oil, heat and water) resources and as potential waste (nuclear, CO2) disposal sites. The focus of the current efforts is the characterisation of the structural permeability of fractured crystalline basement units, which is primarily related to the geology, geometry, and spatial characteristics of fracture networks. Fracture network properties may be scale–dependent or independent. Thus, a multi–scale characterisation of fracture networks is usually recommended to quantify the scale–variability of properties and, eventually, the related predictive scaling laws. Fracture lineament maps are schematic representations of fracture distributions obtained from either manual or automated interpretation of 2D digital models of the earth surface at different scales. From the quantitative analysis on fracture lineament maps, we can retrieve invaluable information on the scale–dependence of fracture network properties.
Here we present the results of the quantification of fracture network and fracture set properties (orientation, length, spacing, spatial organisation) from multi– (outcrop to regional) scale 2D lineament maps of two crystalline basement study areas of Western Norway (Bømlo island and Kråkenes). Lineament maps were obtained from the manual interpretation of orthophotos and 2D digital terrain models retrieved from UAV–drone and LiDAR surveys.
Analyses aimed at the quantification of: (i) scaling laws for fracture length cumulative distributions, defined through a statistically–robust fitting method (Maximum Likelihood Estimations coupled with Kolmogorov–Smirnov tests); (ii) variability of orientation sets as a function of scale; (iii) spatial organisation of fracture sets among scales; (iv) fractal characteristics of fracture networks (fractal exponent). Results suggest that: (i) a statistical analysis considering variable censoring and truncation effects allows to confidently define the best–fitting scaling laws; (ii) the analysis of orientation variability of fracture sets among different scales may provide important constraints about the geometrical complexity of fracture and fault zones; (iii) the statistical analysis of 2D spacing variability and fracture intensity can be adopted to quantify fracture spatial organisation at different scales.
A statistically robust analysis of the scaling laws, length distributions, spacing, and spatial organisation of lineaments on 2D maps provides reliable results also where only partial or incomplete dataset/lineament maps are available. Such properties are the fundamental input parameters for conceptual (geologic) and numerical (discrete fracture network, DFN) models of fractured crystalline basement reservoirs. Therefore, a statistically robust analysis of fracture lineament maps may help to improve the accuracy of conceptual and numerical models.
How to cite: Ceccato, A., Tartaglia, G., Viola, G., and Antonellini, M.: On the multiscale quantification of fracture network geometry from lineament maps of crystalline basement units, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-2103, https://doi.org/10.5194/egusphere-egu21-2103, 2021.
The geothermal potential of the granites of SW England has long been known. The first significant exploration of the resource was in the Carnmenellis Granite under the ‘Hot Dry Rock (HDR) Project’ during the 80’s and early 90’s. Following completion of the HDR project there was little further exploration in the area for geothermal power generation. Recently however, development of the United Downs Deep Geothermal Power (UDDGP) project marks a significant leap forward, and this aims to be the first commercial project to explore deep geothermal power generation in SW England.
The UDDGP project targets the Porthtowan Fault zone, a regional scale NW to NNW striking strike-slip fault that is inferred to transect the NE margin of the Carnmenellis Granite. Two directional wells were drilled to intersect this fault zone, maximising the surface area of the fault exposed. A production well with a measured depth of 5275 m true vertical depth of 5054 m and an injection well vertically above the production well at a measured depth of 2393 m and a true vertical depth of 2214 m. A full suite of geophysical wireline logs were collected for the production well, including borehole image logs from 900 mMD to 5160 mMD (900 - 4097mTVD).
Interpretation of the borehole imaging across the 4260 m identified a total of 12031 discontinuities. The features were classified using a simple schema and provide new insights into the complex nature of faulting and fracturing within the Granite. Stress field indicators including Borehole Breakouts and Drilling Induced Tensile Fractures (DIFs) were also interpreted.
The orientations of the borehole breakouts and DIFs are consistent and are comparable to previous measurements in the region and the regional stress field, indicating the direction of maximum compression is, approximately horizontal trending towards 320°.
The data show variable fracture density along the imaged section of the well with the maximum density tentatively associated with discreet fault zones. At least 3 fracture sets are identified with the largest concentration of fractures approximately parallel to inferred Porthtowan Fault Zone, suggesting UD-1 intersected the target fault zone. Key fracture attributes are explored and discussed including orientation, spacing, intensity, and spatial correlation.
How to cite: Fellgett, M. W. and Haslam, R.: Fractures in Granite: Results from United Downs Deep Geothermal well UD-1, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-5593, https://doi.org/10.5194/egusphere-egu21-5593, 2021.
Understanding the complex seismic, thermal, hydraulic and mechanical processes active during the hydraulic stimulation or continuous operation of Enhanced Geothermal Systems (EGS) requires an accurate description of the pre-existing fractures and faults. However, the three-dimensional characterization of the fracture network is challenging, as direct observation of the discontinuity network at great depth is limited. Fracture image logs and continuous core, which provide line samples through the fracture network, are most valuable in this regard as they provide the most precise option to place constraints on network attributes in stochastic realizations of the fractured rock mass. Among various geometrical attributes, the spatial clustering of fractures plays a critical role on the rock mass properties.
Here, we analyzed the spatial distribution of fractures derived from image log runs in six deep boreholes in crystalline basement rock. In one well, the fracture distribution from continuous core was also available. The wells were drilled to depths between 2-5 km, and were all located in the same tectonic setting of the Upper Rhine Graben, which is recognized for its high geothermal potential. The normalized correlation integral method was employed to define the scaling relationships of fracture patterns. This methodology is demonstrated to be less affected by the finite size effects, delivering reliable estimates of scaling laws.
Detailed analyses of image log datasets revealed fractal scaling with similar fractal dimensions (between 0.85 and 0.96), prevailed over almost two orders of magnitude of scale. The same was true for the fracture distribution derived from the continuous core, although this distribution was found to be more clustered than that derived from image logs in the same well (i.e. the fractal dimension was lower, which may be due to the partial fracture sampling of image logs which have a coarser resolution than continuous core analyses). Analysis of fractures in sub-sections of the core dataset from progressively increasing depths revealed no systematic depth-dependency for the fractal dimension, although a local variation at a scale of hundreds of meters was identified.
How to cite: Afshari Moein, M. J., Evans, K., Valley, B., Bär, K., and Genter, A.: Depth-dependent Clustering Analysis of Fractures in Crystalline Basement Rocks, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8921, https://doi.org/10.5194/egusphere-egu21-8921, 2021.
La Garriga-Samalús geothermal system is located in the Catalan Coastal Ranges (CCR) (NE Spain). The CCR is a NE-SW horst and graben system with two lifted mountain chains, the Precoastal (PR) and Coastal ranges (CR), separated by the Vallès basin. An Hercynian highly fractured granodiorite thrusts the Paleozoic metamorphic units in the northern part of the PR. Towards the south, the intrusive unit is in contact with the Miocene rocks of the Vallès basin by a major Neogene normal fault, the Vallès fault.
Previous works in this area showed that the fractured zone associated to the Vallès normal fault, located in the Hercynian granodiorite, could act as the geothermal reservoir as well as the fast-ascending path for the hot fluids. Although some geophysical prospections and exploration boreholes have been made in La Garriga-Samalús area, it is still necessary to understand and model the fracture network.
This study presents a multiscale fracture analysis of the granodiorite from outcrops and boreholes samples. This multiscale analysis combines satellite pictures, field studies and laboratory measurements of both field and borehole samples.
The fracture data collection has allowed the identification of 3 major fracture sets related to the main tectonic events of the CCR, in addition to 7 other minor fracture groups. Through the variation of fracture density in the footwall, a 10 meters fault core, and an asymmetric damage zone of approximately 300 m, have been identified. The damage zone shows an increasing fracture density towards the northern and southern limits of the granodiorite, which are an alpine thrust and the Vallès fault, respectively. In the fault core, the presence of cemented rocks like cataclasites with hydrothermal sealed fractures result in low porosity and permeability. Contrary, the damage zone consists of minor faults and related fractures which may enhance fault permeability with respect the core and its protolith.
In order to characterize fractures in depth, the borehole samples have been digitized via photogrammetry method. The study of the point cloud related to this samples have allowed the identification and characterization of some of the fractures sets at greater depths. The permeability differences between the fault core and the damage zone can be also identified in the borehole samples. The presence of centimetric open fractures, cavities, and hydrothermal minerals, confirm the circulation of thermal fluids. Meanwhile, other samples within the fault trace are compact rocks, with slickensides and high-pressure alteration minerals.
These fracture results have been also correlated with a previous 2D magnetotelluric (MT) model which shows the Vallès fault zone as a low resistivity unit. The fault zone may give a low resistivity value only if it is permeable and water saturated. Therefore, our results identify the damage zone of the Vallès fault as the potential reservoir of La Garriga-Samalús geothermal system.
How to cite: Mitjanas, G., Alías, G., García-Martínez, D., Queralt, P., and Ledo, J.: Multiscale fracture analysis of the Vallès fault zone in La Garriga-Samalús geothermal system, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9940, https://doi.org/10.5194/egusphere-egu21-9940, 2021.
Forced-gradient flow sustained by a geothermal well doublet in a porous-fissured reservoir (more or less karstified, Jurassic formation, cf. Behrens et al. 2020 for a conceptual-hydrogeologic model outline and competing hypotheses as to what role large fractures might play) is subject to a tracer test anew, following a significant augmentation of fluid turnover rates. The distinct aromatic sulfonates (N2S and P4S) used as tracers in the first (lower-rate) and the second (higher-rate) test are supposed to be transported conservatively and similarly under this reservoir’s in-situ conditions; in terms of solute diffusivity, the larger molecule size of P4S ought to be roughly matched by N2S’s stronger hydratization in-situ, and for assuming else physicochemically conservative behavior one may invoke vast evidence from past applications in mineralogically variate, saline, hot reservoirs (Behrens 1992ff; Rose 1997ff). Cumulative mass recovery for each tracer can be calculated based on its theoretical ‘single-passage’ signal, deconvolved from its measured signal (eliminating ‘redundant’ contributions from fluid recirculation; to account for flow-rate variability, we set up an ad-hoc deconvolution algorithm). From tracer sampling to date, CMR amounts to ~28% for P4S, and ~70%* for N2S – whose first 20-30%* mass amounts were swept through the reservoir under the lower-rate flow regime, and its subsequent amounts under the higher-rate regime, reaching 60-65%* by the time P4S was added (for the latter, a certain time lag after flow rate augmenting was allowed, not having in pectore whether the higher flow rate would prove sustainable, and how long it would take for the flow field to reach a new ‘quasi-steady’ state at reservoir scale; pressure buildup/drawdown changes at injection/production wells stayed uninterpretably low). Those N2S %* cannot be told accurately due to short-term flow-meter (instrumental) failures during precisely this transition. CMR for P4S exhibits a significantly lower growth rate than for N2S (even when plotted against cumulative fluid turnover, which should compensate for flow-rate disparities), and, more strikingly, a marked first-order discontinuity (tangent drop) after reaching ~20% (which would correspond to ~30% N2S after the same cumulative fluid turnover, counted since tracer injection). Three hypotheses which might explain these findings are evaluated: P4S decay? reservoir ‘stimulation’ → stronger P4S dilution? reservoir ‘compartmenting’ → P4S ‘loss’ into some ‘non-pay’ zone? Accordingly, special monitoring options that would allow to disambiguate (or refute) some ‘induced fracture’ / ‘activated fault’ / ‘karst window’ scenarios are discussed. [*Note: not only these particular values for N2S, but its entire subsequent CMR calculation is impeded by the flow-meter data gap; as a substitute, one may attempt to reconstruct the missing flow-rate data from ‘geothermal’ power generation data, but here operator-provided information is insufficient. For P4S however, being injected way later after this metering gap, its tangent discontinuity in CMR stays independent upon the missing data] – – Reference: SGP-TR-216, pp.195-201, pangea.stanford.edu/ERE/db/GeoConf/papers/SGW/2020/Behrens.pdf (for a reservoir model outline, and early tracer signal illustrations)
How to cite: Ghergut, H. B. J. and Sauter, M.: First-order discontinuity in tracer mass recovery: indicative of (large) induced fracture(s)?, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13435, https://doi.org/10.5194/egusphere-egu21-13435, 2021.
The Bedretto Underground Laboratory for Geosciences and GeoEnergies, located in the Swiss Alps and situated under more than 1 km of granitic overburden, offers a unique field site to study processes in fractured rock. Currently, a total of six boreholes are available, four of them being permanently instrumented with monitoring equipment, and two dedicated as stimulation boreholes. One of the monitoring boreholes contains permanent packed-off intervals which record pressure changes and flow rate. The remaining three are instrumented with a variety of sensors, including fiber-optic micro-strain sensors, temperature monitoring, permanent geophones and accelerometers. All monitoring boreholes are either sealed with packers or cemented, and only the stimulation boreholes allow for outflow. During a period of several weeks, we were able to seal the two stimulation boreholes and allow the reservoir to approach ambient pressure conditions (more than 3 MPa at the wellhead) while we monitored the response of the reservoir. The pressure buildup shows not only in the pressure data, but also as stress changes in the reservoir. During a depressurization phase, we quickly opened one borehole and subsequently performed time-lapse single-hole Ground Penetrating Radar (GPR) measurements. At a second depressurization phase, we continued the GPR measurements while opening the second borehole in a controlled manner. The changes in strain, pressure and GPR reflectivity illuminate the response of the reservoir when moving from ambient to atmospheric pressure at the wellhead, and reveal processes such as wellbore storage, pore-pressure variations and ultimately permeability changes in the reservoir.
How to cite: Shakas, A., Gholizadeh, N., Hertrich, M., Wenning, Q., Maurer, H., Brixel, B., Zappone, A., Rinaldi, A., Obermann, A., Ma, X., Kaestli, P., Linwood, P., Hochreutener, R., Wiemer, S., and Giardini, D.: The response of a fractured crystalline reservoir to natural pressure buildup: Experiment results from the Bedretto Lab, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10324, https://doi.org/10.5194/egusphere-egu21-10324, 2021.
Fracture morphology influences various physical processes within a fracture, such as fluid flow, contaminant, and heat transport as well as mechanical shearing. Through the increasing availability of affordable high-precision scanning technology of open surfaces, drill cores, and broken rock samples, digital rock surfaces are easy to obtain and become a common tool to study hydraulic and mechanical processes inside fractures. Through statistical fracture generation and 3D printing technology, even custom-made fracture surfaces have been applied in numerous studies.
However, the complexity to describe and quantify fracture surface morphology is a major obstacle in evaluating and comparing results from laboratory and numerical experiments across studies and rock samples. While many so-called roughness parameters exist, there is no single parameter representing all features of a fracture surface. Only through a combination of parameters, which often is problem depending, a fracture surface can be suitably characterized to enable reproducibility of experiments and analysis across samples and studies. The effort of calculating various parameters is impeding scientists to sufficiently and quantitatively describe fracture surfaces.
We introduce an open-source MATLAB toolbox that allows the determination of over 25 different roughness parameters for height profiles as well as full 3D fracture surfaces. The selection of parameters includes statistical parameters, amplitude and spatial metrics, joint roughness coefficients, and fractal parameters. Variation of those parameters across as fracture surface as well as anisotropy is also calculated. For three-dimensional profiles, also surface measures are determined. If the top and bottom surfaces of a fracture are provided, even an estimated aperture distribution can be obtained, which is analyzed as well as provided for subsequent calculations, e.g., regarding the flow field. Further, the toolbox includes pre-processing routines for digital fracture surfaces of different sizes, shapes, and orientations. The toolbox is validated with standard profiles and synthetically generated fractures with known characteristics.
The toolbox massively simplifies the quantitative description of fracture surfaces, unifies the methodology of determining roughness parameters, and allows an easy generation of digital fractures with known characteristics. On the other hand, the toolbox enables easy customization for advanced users with specific demands. The toolbox consists of well-documented MATLAB scripts and functions that require a minimum of user-defined metadata. Extensive examples are also provided. The source code is freely available for download at https://gitlab.com/thomhGeoCode/fsat
How to cite: Heinze, T., Frank, S., and Wohnlich, S.: FSAT - An Open-Source Fracture Surface Analysis Toolbox, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-361, https://doi.org/10.5194/egusphere-egu21-361, 2021.
Fractures can provide principal fluid flow pathways in the Earth’s crust, making them a critical feature influencing subsurface geoenergy applications, such as the storage of anthropogenic waste, emissions or energy. In such scenarios, fluid-conductive fault and fracture networks are synonymous with two-phase flow, due to the injection of an additional fluid (e.g. CO2) into an already saturated (e.g. brine) system. Predicting and modelling the resulting (partly-)immiscible fluid-fluid interactions, and the nature of fluid flow, on the field-scale, requires an understanding of the constitutive relationships (e.g. relative permeability and capillary pressure) governing fluid flow on the single-fracture scale. In addition to capillary and viscous forces, fracture relative permeability is influenced by aperture heterogeneity, arising from surface roughness. The degree to which surface roughness controls relative permeability behaviour in fractures remains unclear. As all fractures display roughness to various degrees, furthering our understanding of two-phase flow in fractures benefits from a systematic investigation into the impact of roughness on flow properties. To this end, we performed co-injection experiments on two 3D-printed (polymeric resin) fractures with different controlled and quantified surface roughness distributions (Joint Roughness Coefficients of 5 & 7). Brine and decane were simultaneously injected at a series of incrementally decreasing brine fractional flow rates (1, 0.75, 0.5, 0.25, and 0), at low total volumetric flow rates (0.015 mL/min). Steady-state fluid occupancy patterns, preferential flow pathways and overall fluid saturations in each fracture were imaged and compared using an environmental laboratory-based μ-CT scanner with a 5.8 μm voxel size (EMCT; Ghent University Centre for X-ray Computed Tomography). Experimental results highlight the importance of roughness on the relative permeability behaviour of fractures, which is, for example, a principal control on leakage rates from geological stores.
How to cite: Phillips, T., Van Stappen, J., Bultreys, T., Van Offenwert, S., Mascini, A., Wang, S., Cnudde, V., and Busch, A.: Two-Phase Flow in Rough Fractures – Insights from 3D-Printed Fractures, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-7687, https://doi.org/10.5194/egusphere-egu21-7687, 2021.
The rupture of geomaterials is integral to multiple areas of geoscience and engineering, and is of particular importance to subsurface engineering projects that address decarbonisation, such as geothermal energy extraction and carbon capture and storage. Laboratory experimentation has led to the development of numerous, elegant micro-mechanical solutions that detail the accumulation of damage during deformation. Yet few studies have constrained the impact of deformation rate (which spans 10’s of orders of magnitude in nature and during subsurface stimulation) on material strength, rupture architecture and associated geophysical signals.
Here, we perform a suite of uniaxial compressive strength (UCS) and Brazilian disc tests with acoustic emission monitoring at 4 deformation rates (0.0004, 0.004, 0.04 and 0.4 mms-1) using a dense (1% porosity), low permeability (7x10-19 m2 at 10 MPa effective pressure) medium-fine grained monzogranite. Rates chosen equate to strain rates (for UCS) and diametric equivalent strain rates (Brazil tests) span 10-5 to 10-1, encompassing and expanding upon standard conditions for reporting of material strength. We find that materials undergo apparent strengthening under increasing deformation rate in both compression and tension. UCS is increased by ~45 % and Brazilian tensile strength by ~35 % across the rates tested. Young’s Modulus also shows an apparent increase of ~17 % across the rates tested. In UCS, increasing rate results in increasingly localised rupture and increasingly efficient grain size reduction along the fracture plane, suggesting that the rate of rupture impacts development of permeable pathways and hence fracture conductivity in deformed media.
Acoustic emission monitoring shows that ruptures developed in compression and tension follow different characteristic rates of acceleration, driven by the initiation, propagation and coalescence of fractures which differs under the two regimes. Moreover, b-value, calculated for the frequency-amplitude distribution of AEs is shown to be higher in tension than in compression. As a function of rate in both compression and tension, we find a higher prevalence of higher energy AE events with increasing deformation rates, which also serves to reduce b-value. This demonstrates that the predictability of failure events is dependent on stress regime (tensile/ compressive) and deformation rate, which impacts our ability to accurately forecast behaviour; however monitoring and predictive strategies largely fail to account for these controls. One of the most robust strategies for monitoring changes in material response to deformation may thus be tracking b-value with fixed sampling windows. A better understanding of the signals that accompany rate-dependent deformation will aid in the interpretation of seismicity both in natural phenomena and during geoenergy applications.
How to cite: Kendrick, J. E., Lamur, A., Mouli-Castillo, J., Fraser-Harris, A., Lightbody, A., Bell, A., Edlmann, K., McDermott, C., and Shipton, Z.: An exploration of the rate-dependent rupture of granites in compression and tension, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-16156, https://doi.org/10.5194/egusphere-egu21-16156, 2021.
Carbon Capture and Storage (CCS) aims to gather and store atmospheric CO2, often in geologic reservoirs, to mitigate the increasing atmospheric CO2 concentrations that lead to climate change. While the majority of CCS projects to date focus on structurally trapping CO2 in gaseous form in porous sedimentary rocks, carbon mineralization approaches storage from a much more secure perspective by storing CO2 as a solid carbonate mineral phase.
During the carbon mineralization process, interactions between the host rock and the fluids flowing through the rock’s permeable pathways exert a primary control on the evolution of permeability of the system. Precipitation of mineral phases within the fracture network can significantly reduce the permeability of the overall system (clogging), whereas mineral dissolution and volume positive mineral reactions (leading to cracking) can enhance permeability. The coupling between these competing processes dictates reservoir permeability and thus the long-term storage capacity and lifetime of CO2 storage reservoirs. Experimental studies are therefore vital to understand the chemo-mechanical controls on dissolution, precipitation, and carbonation-induced cracking, as well as to quantify their effect on the permeability of the system.
In this study, we perform experiments using a new AutoLab triaxial deformation apparatus equipped with independently servo-controlled axial load, confining, and fluid pressures. Samples are prepared via cold press from Twin Sisters peridotite powdered to a mean particle size of 94 µm. Experimental conditions are set to reproduce shallow crust conditions at viable injection depths and are controlled at a confining pressure of 20 MPa and fluid pressures of 10 MPa. Experimental temperatures range from 20 to 150 °C. Pore fluids are mixed in a joint mixing vessel using deionized water and sodium bicarbonate forming a solution of 0.6 M concentration. The solution is then pressurized using CO2 (99.9% purity) to a pressure of 3.5 MPa serving both as a vehicle for CO2 transport and as pH buffer. Permeability, ultrasonic wave velocities, axial strain, pH and fluid composition are monitored during these flow-through experiments.
Preliminary results relate progress of the mineral carbonation reaction through the sample with a systematic decrease in permeability and an associated increase in P wave velocity. The results of this experimental study will be used to constrain the most favourable conditions for CO2 storage in a solid form, which is fundamental to the upscaling of carbon mineralization as an innovative, efficient and safe method for CO2 storage.
How to cite: Sanchez Roa, C., Tielke, J., McCarthy, C., Kelemen, P., Choi, S., Leong, J. A., Spiegelman, M., Evans, O., and Park, A.: Permeability evolution during carbon mineralization in peridotite: an experimental determination of chemo-mechanical feedbacks, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13759, https://doi.org/10.5194/egusphere-egu21-13759, 2021.
Injecting fluids into the subsurface is necessary for a number of industries to facilitate the energy transition (e.g., geothermal, geologic CO2 sequestration or hydrogen storage). One of the biggest challenges is that fluid injection induces seismicity, which can lead to damaging events. It is currently not possible to predict the exact nature of seismicity that will occur due to fluid injection prior to operations.
Using laboratory friction experiments and in-situ microseismic analyses, we investigate the role frictional behaviour may have on the rate and magnitude of induced seismicity. This study focuses on the Horn River Basin shale gas play (British Columbia, Canada), where hydraulic fracturing activity has resulted in felt induced seismicity. Microseismic data from this field highlights fault planes that cut across the stratigraphy, including overburden and reservoir shales of varying mineralogy and underburden dolomites.
Our experimental friction results on samples recovered from core at reservoir depths show that both the frictional strength and stability vary considerably across the different lithologies; transitioning from very velocity-strengthening with friction coefficients of 0.3 – 0.4 in the overburden shales to more velocity-weakening and friction coefficients of 0.55 – 0.7 in the reservoir shales and an analogue of the underburden dolomite.
Spatial clustering analysis of the microseismicity allowed us to discriminate the operationally induced fracturing from fault reactivation events. We then examined the variations in the seismic b-value of the event magnitude-frequency distribution. These events were further differentiated by depth, separating them into their lithological horizons. The results show, for both fracturing and faulting events, higher seismic b-values of 1.4 – 1.5 occur in the overburden shales, which then decrease into the upper reservoir shales to 0.8 – 1.1, and then increase into the lower reservoir shales and underburden dolomite to 1.1 – 1.4. These trends correlate well with the laboratory measurements of frictional a-b values that define the degree of velocity-strengthening to velocity-weakening in the different gouges across the same lithological units.
These results suggest that knowledge of the frictional behaviour of the subsurface prior to operations, derived from mineralogical compositions and laboratory testing on cored material, may help improve our understanding of the potential rate and magnitude of induced seismicity that may occur due to subsurface fluid injection.
How to cite: Allen, M. J., Kettlety, T., Faulkner, D. R., Kendall, J. M., and De Paola, N.: Frictional properties of a faulted shale gas play: implications for induced seismicity , EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12764, https://doi.org/10.5194/egusphere-egu21-12764, 2021.
The long-term sustainability of fractures in Variscan metamorphic rocks will determine whether it is reasonable to utilize such formations as potential unconventional EGS reservoirs. During long lasting fluid flow within fractures, dissolution, precipitation, and chemical reactions between the fluid and the rock matrix may alter the flow pathway structure and flow properties. Within the framework of the European Union's Horizon 2020 initiative "MEET (Multi-Sites EGS Demonstration)", we performed long-term fracture permeability experiments on saw-cut slate samples from the Hahnenklee drill site, Harz Mountains, Germany, under constant pressure and temperature conditions. Two experiments were performed using deionized water as pore fluid with intermittent flow for more than one month at 10 MPa confining pressure and 1 MPa pore pressure. Three sequential investigations were performed, including (1) an initial continuous flow tests at room temperature, (2) temperature cycles between room temperature and up to 70 °C or 90 °C, and (3) measurement of the time-dependent permeability evolution at 70 °C or 90 °C. During stage (3), the effluents were sampled in time intervals of 6 days and analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES). The results show that (1) sample permeability first continuously decreases, but progressively converges within about three days, (2) increasing temperature leads to an additional permeability decline that is irreversible, and (3) the time-dependent permeability reduction is much more pronounced at 90 °C in comparison to that at 70 °C. The effluents are enriched with Na, Fe, K, Ca, Si, where the Na concentration is always an order of magnitude higher than the others. Except for Si, concentrations are progressively decreasing with time. During the entire experimental period, sample permeability was reduced by approximately 90% at 90 °C and 60% at 70 °C compared to their initial values. In contrast, both samples showed a negligible permeability decline with time at room temperature after cooling. Our results demonstrate that thermally-enhanced fluid-rock interactions lead to a permanent and at least partial closure of fracture aperture, which is unfavorable for geothermal exploitation. However, the degree of permeability reduction may strongly depend on initial fracture roughness, which remains to be investigated.
How to cite: Cheng, C., Herrmann, J., Rybacki, E., and Milsch, H.: Long-term evolution of fracture permeability in slate as potential target reservoirs for Enhanced Geothermal Systems (EGS), EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12187, https://doi.org/10.5194/egusphere-egu21-12187, 2021.
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