ERE5.3 | Faults and fractures in geoenergy applications 2: Numerical modelling and simulation
Faults and fractures in geoenergy applications 2: Numerical modelling and simulation
Including ERE Division Outstanding Early Career Scientist Award Lecture
Convener: Sarah WeihmannECSECS | Co-conveners: Reza Jalali, Nathaniel Forbes InskipECSECS
| Wed, 17 Apr, 10:45–12:30 (CEST), 14:00–15:45 (CEST)
Room K2
Posters on site
| Attendance Wed, 17 Apr, 16:15–18:00 (CEST) | Display Wed, 17 Apr, 14:00–18:00
Hall X4
Orals |
Wed, 10:45
Wed, 16:15
Naturally fractured reservoirs are of great importance in various disciplines such as hydrogeology, hydrocarbon reservoir management, nuclear waste repositories, CO2 storage and geothermal reservoir engineering. This session addresses novel ideas as well as established concepts for the representation and numerical simulation of discontinuities and processes in fractured media.
The presence of fractures modifies the bulk physical properties of the original media by many orders of magnitudes and often introduces strongly nonlinear behaviour. Fractures also provide the main flow and transport pathways in the rock mass, dominating over the permeability of the rock matrix and creating anisotropic flow fields and transport.
Numerical modelling of such systems is especially challenging and often requires creative new ideas and solutions, for example the use of stochastic models. Understanding the hydraulic and mechanical properties of fractures and fracture networks thus is crucial for predicting the movement of any fluid such as water, air, hydrocarbons, or CO2.
The geologist toolboxes for modelling fractured rocks and simulating processes in fractured media experiences constant extension and improvement. Contributions are especially welcome from the following topics:

• Deterministic or stochastic approaches for structural construction of fractured media
• Continuous or discontinuous (DFN) modelling methods representing static hydraulic and/or mechanical characteristics of fractured media
• Simulation of dynamic processes, hydraulic and/or mechanical behaviour and THMC coupling in fractured media
• Deterministic and stochastic inversion methods for calibrating numerical models of fractured media
• Numerical modelling concepts of accounting for fractured properties specifically in groundwater, petroleum or geothermal management applications

We encourage researchers to elaborate on applied projects on the role of faults and fractures in subsurface energy systems in our session. We are interested in research across different scales and disciplines and welcome ECS warmly.

Orals: Wed, 17 Apr | Room K2

Chairpersons: Sarah Weihmann, Reza Jalali, Nathaniel Forbes Inskip
On-site presentation
Qinghua Lei

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,, 2024.

On-site presentation
Nikolas Ovaskainen, Nicklas Nordbäck, Jon Engström, and Kaisa Nikkilä

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. 


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.

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.

Ovaskainen, N., 2023. fractopo: A Python package for fracture network analysis. JOSS 8, 5300.

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,, 2024.

On-site presentation
Marco Fuchs, Anna Suzuki, Togo Hasumi, Sina Hale, Larissa Blesch, Kathrin Menberg, Gabriel C. Rau, and Philipp Blum

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,, 2024.

On-site presentation
Matthew Hodge, Mark Cottrell, Jochen Knies, and Giulio Viola

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,, 2024.

On-site presentation
Thomas Heinze

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,, 2024.

On-site presentation
Keita Yoshioka and Tao You

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,, 2024.

On-site presentation
Silvia De Simone, Caroline Darcel, Hossein Kasani, Diego Mas Ivars, and Philippe Davy

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,, 2024.

On-site presentation
Ado Farsi, Frans Aben, and Nicolas Brantut

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.