Fractures such as joints and faults are prevalent discontinuity features in the Earth’s crust, forming hierarchical networks in the subsurface and controlling the bulk behaviour of geological media. They play an important role in various multiphysical processes such as stress transfer, pressure diffusion, heat transport, earthquake generation, wave scattering, and chemical dissolution, which are crucial for many geoenergy applications ranging from geothermal energy exploitation and critical mineral extraction to nuclear waste disposal and underground hydrogen storage. Thus, it is of central importance to advance our capability of realistically representing these ubiquitous discontinuity features and further accurately modelling the associated seismo-thermo-hydro-mechanical processes. Over the past years, I have established a powerful fractured media simulation platform based on the discrete fracture network concept to simulate coupled multiphysical processes in fractured rocks. The model can explicitly represent the distribution of a large number of fractures in both 2D and 3D space as well as accurately compute their multiphysical responses/interactions over both space and time domains. No a priori assumption about the representative elementary volume is needed, rendering this approach as an appropriate tool to study hierarchical fractured rocks that may have no characteristic length scale. Using this modelling paradigm, diverse macroscopic phenomena in fractured media can be captured as emergent properties physically arising from the collective behaviour of numerous existing/growing fractures and interacting rock blocks. This multiphysics modelling framework can serve as a useful tool to bridge experimentally-established constitutive relationships of fracture/rock samples at the laboratory scale to phenomenologically-observed macroscopic properties of fractured geological formations at the site scale. A series of case studies are presented, where high-fidelity multiphysics simulations are combined with high-quality laboratory measurements and/or high-resolution field observations to address different geoenergy-related problems. The research findings and insights obtained have important implications for understanding and predicting the behaviour of fractured rocks for safe and sustainable geoenergy development.

How to cite: Lei, Q.: Discrete fracture network modelling of multiphysics processes in fractured media for geoenergy applications, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13320, https://doi.org/10.5194/egusphere-egu24-13320, 2024.

Discontinuities of the bedrock, i.e. fractures, form the main pathways for fluid flow in crystalline rocks. For modelling purposes, fracture data can be gathered from e.g. bedrock outcrops and drillcores. Remote digitization of bedrock outcrops results in mostly two-dimensional fracture data while structural measurements in-situ and from drillcores results in three-dimensional data. The nowadays common digitized two-dimensional fracture trace data can be analysed for geometric (e.g. orientation and length) and topological properties (e.g. connectivity). For these purposes, specialized tools exist such as FracPaq (Healy et al., 2017), NetworkGT (Nyberg et al., 2018) and fractopo (Ovaskainen, 2023).

For three-dimensional fracture data analysis, the options become more sparse because as the data gains complexity through the addition of a dimension, so does the software required for analysis. This is especially the case for software that, rather than analysing fracture data, (also) generates it such as with discrete fracture network (DFN) modelling. DFN-modelling is required when fluid flow, reactive flow, geothermal flow, or contaminant transport properties of the fracture network need to be assessed at a scale larger than it is feasible to collect fracture data. Due to the added complexity, the available software for these purposes is varied and require specialized knowledge to use them effectively. In hydrocarbon exploration, geothermal exploitation and nuclear waste disposal, software such as FracMan (WSP trademark) is used for DFN-modelling and subsequent flow modelling. Although free and open-source options for DFN-modelling exist, they often lack user-friendly interfaces and lack the necessary manpower for further development outside of research purposes. 

In FLOP (FLOw Pathways within faults and associated fracture systems in crystalline bedrock) -project we gather knowledge of the available free and open-source software for three-dimensional fracture data analysis and modelling. We integrate the found solutions with macro- and microscale fracture data from outcrops and X-ray CT-imaging, respectively, to investigate flow channeling. We also apply the more mature tools available for two-dimensional fracture trace analysis, such as fractopo (Ovaskainen, 2023), to characterize varied sampling locations where flow properties of field analogues will be studied. 

The FLOP-project is funded by SAFER2028, a Finnish research programme on nuclear energy research, and the Geological Survey of Finland. The project is conducted in collaboration with the Deep-HEAT-Flows geothermal energy project. 

References

Healy, D., Rizzo, R.E., Cornwell, D.G., Farrell, N.J.C., Watkins, H., Timms, N.E., Gomez-Rivas, E., Smith, M., 2017. FracPaQ: A MATLAB™ toolbox for the quantification of fracture patterns. Journal of Structural Geology 95, 1–16. https://doi.org/10.1016/j.jsg.2016.12.003

Nyberg, B., Nixon, C.W., Sanderson, D.J., 2018. NetworkGT: A GIS tool for geometric and topological analysis of two-dimensional fracture networks. Geosphere 14, 1618–1634. https://doi.org/10.1130/GES01595.1

Ovaskainen, N., 2023. fractopo: A Python package for fracture network analysis. JOSS 8, 5300. https://doi.org/10.21105/joss.05300

How to cite: Ovaskainen, N., Nordbäck, N., Engström, J., and Nikkilä, K.: Structural and flow modelling of bedrock fractures - a software perspective, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-7550, https://doi.org/10.5194/egusphere-egu24-7550, 2024.

Fractures play a significant role in various geoscientific applications, such as nuclear waste disposal, geothermal energy, and hydrocarbon extraction. Understanding the governing hydraulic characteristics of fractures and their impact on flow processes is crucial for the success of these applications. Among the many parameters that affect fracture behavior, permeability stands out as one of the most critical. Several methods have been developed to investigate fracture permeability, including flow-through experiments and numerical hydraulic simulations. However, it is important to note that the geometry of a fracture greatly influences its permeability. This study focuses on examining different workflows to directly estimate the permeability of a single fracture based on its geometry. In the first step to achieve this, we apply and evaluate three fracture surface imaging methods: (1) handheld laser scanner (HLS), (2) mounted laser scanner (MLS), and (3) Structure from Motion (SfM). We conducted our study using a bedding joint in Flechtinger sandstone as the fracture sample. After capturing the fracture geometries using these imaging methods, we perform numerical flow simulations to estimate hydraulic apertures. Our findings reveal that due to limited resolution and accuracy, the HLS is not suitable for use in numerical flow simulations. However, MLS and SfM result in hydraulic apertures that exceed experimental air permeameter measurements (81 ± 1 µm). The hydraulic apertures obtained using MLS and SfM are 163 µm and 207 µm, respectively. To bridge the discrepancy between simulations and measurements, we stepwise increase the contact area, resulting in hydraulic apertures of 85 µm at 5 % contact area and 83 µm at 7 % contact area for MLS and SfM, respectively. In the second step, we utilize the topological persistent homology (PH) method to calculate permeability directly from the fracture geometry derived from MLS, eliminating the need for laboratory experiments or numerical simulations. We create three different datasets of the same fracture, varying in spatial resolution (200 µm, 100 µm, and 50 µm). The results from the PH analysis demonstrate hydraulic apertures ranging from 73 µm to 92 µm, which align closely with the air permeameter measurements. Notably, the accuracy of fracture permeability prediction improves with higher resolution. In summary, this study presents an effective workflow that enables the direct estimation of fracture permeability based on the geometry of a sandstone fracture. By utilizing different imaging methods and topological analysis, we provide valuable insights into understanding and predicting fracture permeability.

How to cite: Fuchs, M., Suzuki, A., Hasumi, T., Hale, S., Blesch, L., Menberg, K., Rau, G. C., and Blum, P.: A Matter of Geometry: Predicting Single Fracture Permeability by Evaluating Imaging Methods and Persistent Homology Analysis  , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2193, https://doi.org/10.5194/egusphere-egu24-2193, 2024.

Offshore crystalline basement volumes forming fractured reservoirs contain hydrocarbons within hydraulically conductive fracture networks. These networks, in places occurring at sub-seismic scales, may develop from geologically long and complex polyphase deformation histories. If, on the one hand, characterising fracture-related permeability and connectivity is vital in assessing hydrocarbon play prospectivity, on the other it is challenging due to the inaccessibility of the off-shore volumes and the small average size and intricacy of transmissive fractures. Indeed, approaches relying on deep wells and regional seismic data usually lack the spatial, temporal, and genetic resolution to properly resolve the sub-seismic fracture networks that guarantee the secondary permeability of those rock volumes. Correlative studies on onshore analogues, may therefore be of great assistance. Leveraging the improved resolution advantages of a series of geologically well-constrained onshore analogues, this study incorporates multi-scalar lineament trace maps, outcrop, and drill hole orientation data from Smøla Island in Central Norway to identify a number of systematic fracture sets, associated fracture size distributions, and fracture frequency and trace intensities. Crucially, this study also incorporates both deterministic cross-cutting/termination information, and absolute K-Ar age constraints from fault gouges on Smøla on the age of formation of the main faults and fracture sets. These fracture and temporal input variables were used to generate several ‘grown’ discrete fracture network (DFN) models. By generating fractures in a series of timesteps, these models produce a more realistic simulation of natural fracture patterns, including important fracture intersections and terminations. The models represent stochastic fracture network realisations which 'back-strip’ from the present to the Mid-Cretaceous, Late Triassic-Early Jurassic, and the Late Carboniferous/Early Permian. Based on each of these time-stage models, probabilistic outputs of 3D fracture network connectivity, and permeability tensor orientations using assumed reservoir values were produced. Our findings suggest a temporal shift in the principal permeability (K) tensor orientations during the extension of the Mid-Norwegian margin, opening of the North Atlantic, and Norwegian Sea basin development. A comparative analysis with known Norwegian Sea reservoir charging and fluid migration events suggests possible key basement-hosted tectonic structural geometries that have had permeability values through time that are of interest for hydrocarbon accumulation and potential geofluid storage.

How to cite: Hodge, M., Cottrell, M., Knies, J., and Viola, G.: Temporal evolution of fracture connectivity and permeability in crystalline basement volumes: an applied stochastic modelling approach for the Mid-Norwegian margin, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13003, https://doi.org/10.5194/egusphere-egu24-13003, 2024.

The heat transfer capability of any geothermal system is an essential characteristic deciding about its productivity, lifetime, and sustainability. Common attempts assuming thermal equilibrium between hot rock and injected fluid have shown to be a poor proxy for the thermal field in the subsurface. More detailed models at the laboratory scale based on explicit heat transfer between phases provide much better estimates but require a priori information concerning fracture geometry and network connectivity that is commonly not available at field scale applications.

Based on these single and discrete fracture models, this work presents an effective heat transfer model upscaled for fracture networks. Using a realistic parameter set including fracture orientation, fracture density, and the permeability distribution, the developed approach determines the heat transfer coefficient and heat transfer area to be subsequently used in a coupled thermo-hydraulic model to simulate the evolution of the temperature field. The heat transfer coefficient is derived from a semi-empirical approach using the dimensionless Nusselt, Prandtl, and Reynolds numbers, and based on over 240 experiments. The heat transfer area is analytically derived from geometrical constraints. This approach achieves good agreement with single fracture experiments as well as with an analytical solution for an equally spaced fracture network. Its full capabilities are demonstrated with a complex three-dimensional simulation of a doublet system in a heterogeneous fracture network including anisotropy.

How to cite: Heinze, T.: Estimating the heat transfer capability of fractured geothermal systems, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8373, https://doi.org/10.5194/egusphere-egu24-8373, 2024.

Hydraulic fracturing is a reservoir stimulation technique that has been applied since the 1950s and is one of the most effective ways to enhance well productivity. At the same time, hydraulic fracturing can induce seismicity or result in the loss of containment of subsurface fluids due to the high injection pressure applied during its operation, leading some projects to eventual shut-down. To mitigate such adverse impacts, an alternative approach known as hydro shearing has been promoted for some enhanced geothermal system projects, wherein the injection pressure is kept at a low level, aiming to stimulate pre-existing networks of fractures by shearing. However, the practical effectiveness of hydro shearing is yet to be proven. In this talk, we propose another alternative stimulation approach using a low-viscosity fluid. We demonstrate that with low-viscosity fluid injection, we can fracture discontinuous interfaces such as grain boundaries or natural fractures without initiating fractures at the injection point. Our results indicate the possibility of engineering reservoir stimulation operations without applying high injection pressure.

How to cite: Yoshioka, K. and You, T.: Remote hydraulic fracturing at weak interfaces, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2439, https://doi.org/10.5194/egusphere-egu24-2439, 2024.

The Hydro-Mechanical (HM) behavior of fluid-saturated porous materials is crucial in determining the response of the subsurface to natural processes, such as glaciation, and to engineering applications, such as construction/excavation, reservoir impoundments, geo-energy extraction, and deep geological disposal of used nuclear fuel. Two fundamental coefficients, i.e., the Biot coefficient and the Skempton coefficient, define the contribution of the fluid in subsurface media to maintain the mechanical equilibrium against perturbations in stress and pore fluid pressure. Despite the central importance of these two coefficients, which may broadly range between 0 and 1, their estimation is often oversimplified in most scientific and engineering studies that treat large-scale saturated problems by assuming a uniform geological material, with the coefficients estimated experimentally at the laboratory sample-scale or analytically through expressions valid for isotropic homogeneous materials.

In this work, we analyze the impact of fractures on the HM behavior of fractured rocks by looking at the equivalent Biot coefficient and Skempton coefficient. We adopt a recently defined framework in which the equivalent coefficients are estimated from the properties of both the porous intact rock and the discrete fracture network (DFN), including fracture size, orientation and mechanical properties. We extend this theory to incorporate more realistic assumptions on fractures, such as size-dependent and stress-dependent fracture properties. This setting allows us to explore the range of variability of the two equivalent coefficients with respect to the stochastic distribution of fracture size and orientation in the rock, and with respect to depth and stress faulting regime. We show that the coefficients are larger if 1) the network is placed in shallow rocks (i.e., low stress regime), 2) the network is populated by a few large fractures rather than by many small fractures, and 3) the fractures are oriented parallel to the in-situ maximum principal stress and normal to the applied stress.

How to cite: De Simone, S., Darcel, C., Kasani, H., Mas Ivars, D., and Davy, P.: The impact of fractures on the Biot and Skempton coefficients of fractured rocks  , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-11408, https://doi.org/10.5194/egusphere-egu24-11408, 2024.

Tectonic formation, fault activity, and earthquakes are influenced by the concentration of fluid within the Earth's crust. In this work, we aim to unravel the spatial and temporal evolution of fluid transport properties during fault growth to gain insights into the dynamics of fluid flow and its impact on fault development. This is done by taking advantage of a rich data set of measurements of stress, deformation, fluid flux, local pore pressure and acoustic emission locations, coupled with three-dimensional numerical simulations.

We induced quasi-static failure in an initially intact sample of Westerly granite under triaxial conditions. Fault growth was monitored using acoustic emission locations. Deformation was periodically halted to conduct flow-through tests, during which pore pressure heterogeneity and flow rate were measured. The exact geometry of the tested sample was then numerically reconstructed, and three-dimensional finite element simulations of Darcy flow were employed to estimate the heterogenous fluid flow properties for all the stages of the experiment by least-square minimisation within an adjoint framework. For each stage of the test the following two models of permeability heterogeneity were considered: i) different local permeability values are inverted for a regular grid in the fault zone and for the remaining volume of the sample; ii) empirical coefficients are inverted to link the change in permeability within the sample to the acoustic emission event density.

We were able to identify the stages during the faulting process where the permeability undergoes the most significant changes: in the initial stages following peak stress, the permeability of the fault zone increases, reaching up to approximately 150 times the permeability of the bulk. The subsequent significant increase (up to approximately 400 times the permeability of the bulk) occurs when the equivalent fault slip ranges between 0.6 and 0.7 millimetres. No substantial increase is observed for the remaining stages of the faulting process. We were also able to determine the extent of permeability heterogeneity along the shear fault zone, revealing variations of up to 8 times between different zones within the fault volumes. These variations are dependent on the specific stage of the faulting process.

How to cite: Farsi, A., Aben, F., and Brantut, N.: Fluid Transport Properties Heterogeneity Evolution During Fault Growth: Coupling Realistic Fluid Flow Simulations with Triaxial Experimental Data and Pore Pressure Heterogeneity Measurements, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-20932, https://doi.org/10.5194/egusphere-egu24-20932, 2024.

When the oilfield is in the middle and late stage of intensive waterflood development, waterflood development is likely to cause fault activation and bring about the development risk of injection-production contradiction in well groups and low injection-production correspondence rate. Therefore, it is necessary to identify and evaluate the fault sealing of low-grade faults. At present, the fault sealing is mostly high-grade faults in the exploration stage and mostly stays in the semi-quantitative evaluation method. Therefore, this paper provides a set of integrated thinking of fault interpretation and fault sealing quantitative evaluation in production and development stage. Firstly, the fault is delineated by well-seismic integrated method, and the possible fault breakpoint is identified from changes of strata thickness in the well. Secondly, high-frequency seismic data are obtained by frequency division, and faults are identified on the basis of fault breakpoint data by two-dimensional seismic section. Then, various three-dimensional seismic attributes such as ant tracking and variance (edge method) are extracted, and the combination of plane and section interpretation is used to strengthen fault characterization and recognition in three-dimensional space. The basic characteristics of faults are described well by the above methods. Then, the fault sealing property is qualitatively evaluated from the aspects of fault nature, fault inclination, fault distance and burial depth, and the conventional fault sealing property is quantitatively analyzed from shale gouge ratio method, lithologic juxtaposition method and the normal pressure on the fault plane from lateral and vertical aspects. Finally, the fuzzy comprehensive discrimination method is used to comprehensively evaluate the fault sealing property based on the above three parameters of the analysis results. The method is applied to ZB area with complex structure and developed fault, and the threshold of fault opening or sealing is determined by the comprehensive evaluation index of fault sealing in ZB area of Bohai Bay Basin. The results of low-grade fault sealing identified in the early stage are judged and applied to the development and production practice. The dynamic and static data such as tracer response relationship, injection-production response relationship and oil properties on both sides of the fault are used to verify the method. The results show that the method is in good agreement with the dynamic and static data .It is suitable for the fault sealing evaluation of  ZB area，and can better guide the later waterflood development, which is of great significance for the recovery of remaining oil .

How to cite: Cheng, C. and Zhang, X.: Application of a fault identification and fault sealing evaluation method in production and development stage in ZB area of Bohai Bay Basin, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1, https://doi.org/10.5194/egusphere-egu24-1, 2024.

This study is focused on the performance evaluation of composite laminated shells when the crack initiates and propagates longitudinally or circumferentially. For this purpose, two numerical composite shell models are considered. One is the equivalent single layer model, and the other is discrete-layer model. Both models are based on the p-convergent higher-order theory or called as the functionally refined model. The second model is mainly adopted and compared with the first model to predict the stress intensity factor in the vicinity of a crack tip not only before patch repair, but also after patch repair. The patch reinforcement effect has been analyzed with respect to various experimental parameters in terms of material type of patch, patch size, patch thickness, adhesive shear modulus, adhesive thickness, etc. The present model has a subprarmetric concept that considers linear mapping of geometry fields on a cylindrical coordinate, and hierarchical approximating functions are based on one- and two-dimensional integrals of Legendre polynomials, allowing accurate simulation of three-dimensional behavior. In assumed displacement field, stain-displacement relations and 3-D constitutive equations of one random layer are obtained by product of 1-D and 2-D higher-order shape functions. Thus it allows independent implementation of increasing p-level, order of shape function, for in-plane and out-of-plane displacement. In the proposed elements, the integrals of Legendre polynomials and Gauss-Lobatto technique are applied to interpolate displacement fields and to implement numerical integration. The sensitivity test has been carried out to show the robustness of present p-convergent higher-order element associated with severe element distortions, very high aspect ratios of elements, and very large radius-to-thickness ratios of shells. For verification of the proposed model, some benchmark laminated shell problems have been solved as compared to the numerical results obtained by the conventional h-convergent finite element method and other p-convergent analyses that used the Lagrange type polynomials as a shape function. Numerical results show that the proposed model is capable of prediction in-plane stresses around the crack tip as well as interlaminar stresses at the interface between shell layers.

How to cite: Yang, S.: Functionally refined model for cracked cylindrical shells repaired with laminated composite materials, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-15300, https://doi.org/10.5194/egusphere-egu24-15300, 2024.

This study presents a comprehensive numerical framework for simulating the evolution of fractures in mining sites characterized by fluid-saturated media during excavation. The proposed model integrates phase field fracture mechanics with a coupled solution approach, employing the finite volume method to solve fluid flow equations and the finite element method for geomechanical analysis. The complex interaction between fluid flow and geomechanics is crucial in understanding and predicting fracture propagation in mining environments. The phase field approach allows for a continuous representation of fractures, capturing their initiation, propagation, and coalescence throughout the excavation process. The model incorporates the influence of fluid saturation on fracture behaviour, providing a more realistic representation of the dynamic interplay between the geological medium and the excavated space. The fluid flow equations are discretized using the finite volume method, considering the poroelastic nature of the rock mass. This approach enables the accurate simulation of fluid movement within the saturated medium, considering the changes induced by excavation activities. Simultaneously, the geomechanics equation is solved using the finite element method, accounting for the stress distribution and strain evolution in response to excavation-induced changes. To validate the efficacy of our FEM code, the model is initially subjected to a single fracture scenario, treated as a notch, and benchmarked against published experimental and numerical results for an elastic medium subjected to compressive loads. The successful validation underscores the robustness of our approach in capturing mixed-mode fracturing phenomena in mining environments. The coupling of fluid flow and geomechanics allows for a thorough investigation of the impact of excavation on fracture initiation and propagation in mining environments. The proposed model provides valuable insights into the complex mechanics of fracture evolution in fluid-saturated mining sites, aiding in the development of strategies for optimizing excavation processes and ensuring the safety and stability of mining operations. The integration of finite volume and finite element methods enhances the accuracy and efficiency of the simulation, making the model a powerful tool for researchers and practitioners in the field of mining engineering.

How to cite: Kar, S. and Chaudhuri, A.: Multi-Physics Modeling of Phase Field Fracture in Fluid-Saturated Mining Environments during Excavation., EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-14515, https://doi.org/10.5194/egusphere-egu24-14515, 2024.

Fractured and karstified carbonates often serve as major aquifers and hydrocarbon reservoirs. Water-rock interactions within variable aperture fractures can lead to dissolution of fracture surfaces and local alteration of fracture apertures, potentially transforming the transport properties of fractures over time. Numerical modeling offers a valuable tool for comprehending the spatial and temporal evolution of karst reservoirs. This work aims to present a comprehensive model to reveal percolation characteristic and dissolution process of stochastic primary fracture systems in carbonate formation. Based on the embedded discrete fracture model, a multi-scale modeling approach is proposed to describe fracture networks with different topologies and various apertures. This model is verified against preexisting numerical models. Simulation results shows that the mechanisms of flow focusing and reactive infiltration instabilities determines fracture dissolutional propagation. Patterns of local dissolution-induced alterations related to fracture permeability, hydraulic conductivity and extensive dissolution appear in fracture tips and intersections.

How to cite: Liu, H., Dong, C., and Lin, C.: Flow Channeling, Dissolutional Growth, and Preferential Flow of Fractures in Karst formation: Insights from Reactive Transport Modeling, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13719, https://doi.org/10.5194/egusphere-egu24-13719, 2024.

The transition to sustainable energy systems introduces a complex landscape, wherein geothermal energy and carbon dioxide storage (CCS) play critical roles. These activities target geological formations that are always faulted and fractured. As the focus intensifies on alternative energy systems for decarbonisation, understanding these faulted rocks in the subsurface gains great importance. Fault and fracture systems can act not only as conduits for fluid flow but they can also be zones of mechanical weakness that may respond dynamically to fluid pressure changes due to natural geological processes or anthropogenic activities, such as CCS or geothermal extraction. This dual role of fault and fracture systems as pathways for fluid flow and as potential triggers for mechanical failure makes their study a cornerstone of sustainable subsurface resource management. The challenge lies in accurately characterising the permeability of these systems and estimating their mechanical behaviour under changing stress conditions. This is vital for ensuring the integrity and efficacy of operations like CCS and geothermal energy extraction, where even slight variations in fluid pressure can have significant implications. For instance, experiences from the fluid injection experiment for an enhanced geothermal system in Basel, Switzerland, and the In Salah CCS pilot site in Algeria highlight how minor changes in pore fluid pressures (as little as 10 MPa) can induce leakage and/or seismic activities. We highlight selected case studies from both active and prospective CCS and geothermal sites (in Svalbard and Mid-Ethiopian Ridge, respectively). These examples illustrate methodologies in fault stability analysis and geomechanical characterization, shedding light on the relationship between fluid flow, stress alterations, and rock mechanics in faulted and fractured formations. By coupling empirical data with modelling techniques, we present strategies to mitigate risks and enhance the efficiency of subsurface decarbonisation efforts.

How to cite: Rizzo, R. E., Keir, D. B., Busch, A., Forbes Inskip, N., Healy, D., Gudbrandsson, S., De Siena, L., and Vannucchi, P.: Fault Lines to Frontlines: Geomechanical Challenges of Sustainable Energy Transition, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-15525, https://doi.org/10.5194/egusphere-egu24-15525, 2024.