ERE6.2

Geothermal provides nearly 20% of New Zealand’s electricity as well as increasing opportunities for direct use. In New Zealand’s ~20 high temperature geothermal systems, fluids flow dominantly through fractured rocks with low matrix permeability. It is important to understand the nature of these fracture systems, and how fluids flow through them, so that the geothermal systems may be more efficiently and sustainably used. Here we present fluid flow calculations in several distinct discrete fracture models, each of which is broadly consistent with the fracture density and high dip magnitude angle distributions directly observed in borehole image logs at the Rotokawa Geothermal Field (>300°C, 175 MWe installed capacity). This reservoir is hosted in fractured andesites. In general, fractures are steeply dipping, and the reservoir is known to be compartmentalized.

Our new code describes fluid flow through large numbers (e.g., thousands) of stochastic fracture networks to provide statistical distributions of permeability, permeability anisotropy and fluid dispersion at reservoir scale (e.g., 1 km²). Calculations can be based on both the cubic flow law for smooth-walled fractures and the Forchheimer flow model, which includes an additional term to describe the nonlinear drag (i.e. friction) in real fractures caused by surface roughness of the fracture walls.

Models with fracture density consistent with borehole observations show pervasive connectivity at reservoir scales, with fluid flow (hence permeability) and tracer transport predominantly along the mean fracture orientation. As the fracture density is varied, we find a linear relationship between permeability which holds above a well-defined percolation threshold. Permeability anisotropy is in general high (~10 to 15), because of the steeply dipping fractures. As fracture density decreases, mean anisotropy decreases while its variability increases. Significant dispersion of fluid occurs as it is transported through the reservoir. These fracture models will inform more traditional continuum models of fractured geothermal reservoirs hosted in volcanic rocks, to provide a better description of fluid flow within reservoirs and aid the responsible and sustainable use of that resource in the future.

How to cite: Kissling, W. and Massiot, C.: Anisotropic permeability and fluid dispersion in pervasively fractured lavas, Rotokawa Geothermal System, New Zealand., EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-3564, https://doi.org/10.5194/egusphere-egu21-3564, 2021.

While fractal models are often employed for describing the geometry of fracture networks, a constant aperture is mostly assigned to all the fractures when such models are flow simulated. While network geometry controls connectivity, it is fracture aperture that controls the conductivity of individual fractures as described by the well-known cubic-law. It would therefore be of practical interest to investigate flow patterns in a fractal-fracture network where the apertures also scale as a power-law in accordance to their position in the hierarchy of the fractal. A set of synthetic fractal-fracture networks and two well-connected natural fracture maps that belong to the same fractal system are used for this purpose. The former, with connectivity above the percolation threshold, are generated by spatially locating the fractured and un-fractured blocks in a deterministic and random manner. A set of sub-networks are generated from a given fractal-fracture map by systematically removing the smaller fracture segments. A streamline simulator based on Darcy's law is used for flow simulating the fracture networks, which are conceptualized as two-dimensional fracture continuum models. Porosity and permeability are assigned to a fracture within the continuum model based on its aperture value and there is nearly no matrix porosity or permeability. The recovery profiles and time-of-flight values for each network and its dominant sub-networks at different time steps are compared.

The results from both the synthetic networks and the natural maps show that there is no significant decrease in recovery in the dominant sub-networks of a given fractal-fracture network. It may therefore be concluded that in the case of such hierarchical fractal-fracture systems with scaled aperture, the smaller fractures do not significantly contribute to the fluid flow.

Key-words: Fractal-fracture; Connectivity; Aperture; Dominant Sub-networks; Streamline Simulator; Recovery

How to cite: Sahu, A. K. and Roy, A.: Influence of Aperture Distribution on Flow in Fractal-Fracture Networks, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-4050, https://doi.org/10.5194/egusphere-egu21-4050, 2021.

In fractured aquifers, the permeability of open fractures could change over time due to precipitation effects and hydrothermal mineral growth. These processes could lead to the clogging of individual fractures and to the complete rearrangement of flow and transport pathways. Existing fractured rock characterization techniques often neglect this dynamicity and treat the reconstruction as a static inversion problem. The dynamic changes then later added to the model as an independent forward modeling task. In this research we provide a new data assimilation-based methodology to monitor and predict the dynamic changes of fractured aquifers due to mineralization in a quasi-real-time manner.

We formulate the inverse problem as a dynamic ‘hidden Markov process’ where the underlying model dynamicity is just partly known. Data assimilation methods are specifically designed to model such systems with strong uncertainties. A typical example for such problems is weather forecasting, where the combination of nonlinear processes and the partial observations make the forecasting challenging. To handle the strong random behavior, data assimilation approaches use stochastic algorithms. In this study we combine DFN-based stochastic aquifer reconstruction techniques with data assimilation algorithms to provide a dynamic inverse modelling framework for fractured reservoirs. We use the transdimensional DFN inversion of (Somogyvári et al., 2017) to initialize the data assimilation. This method uses a transdimensional MCMC approach to identify the most probable DFN geometries given the observations. Because the method is transdimensional it can adjust the number of model parameters, the number of fractures within the DFN. We developed this idea further by enhancing a particle filter algorithm with transdimensional model updates, allowing us to infer DFN models with changing fracture numbers.

We demonstrate the applicability of this new approach on outcrop-based synthetic fractured aquifer models. To create a dynamic DFN example, we simulate solute transport in a 2-D fracture network model using an advection-dispersion algorithm. We simulate fracture sealing in a stochastic way: we define a limit concentration above which the fractures could seal with a predefined probability at any timestep. At the initial timestep, a hydraulic tomography experiment is performed to capture the initial aquifer structure, which is then reconstructed by the transdimensional DFN inversion. At predefined timesteps hydraulic tests are performed at different parts of the aquifer, to obtain information about new state of the synthetic model. These observations are then processed by the data assimilation algorithm, which updates the underlying DFN models to better fit to the observations.

How to cite: Somogyvári, M., Jalali, M., Engelhardt, I., and Reich, S.: Fracture network connectivity devolution monitoring using transdimensional data assimilation, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8400, https://doi.org/10.5194/egusphere-egu21-8400, 2021.

Hydraulic fracturing plays a central role in engineering fractured reservoirs. To simulate the propagation of “dry” fractures, the J-integral has been a standard technique. Its superior accuracy at coarser resolutions make it particularly attractive, especially for reservoir-scale simulations. However, the extension of the J-integral to hydro-mechanical simulations of fluid-driven fracturing has not received the same attention or success. In particular, while several studies have highlighted the capacity of the method in simulating viscosity-dominated propagation, detailed investigations into the performance of the method are still missing. In this work, we find that the extent of hydraulic fracturing is typically overestimated by the J-integral in the viscosity-dominated propagation regime.  A finite element analysis is conducted which sheds light on the source of the error. The case is put forward that the inaccurate numerical solution for fluid pressure is exclusively responsible for the loss in accuracy of the J-integral. With this new understanding, the J-integral is reformulated to minimise its dependence on inaccurate fluid pressures, bypassing the aforementioned sources of error. The reformulation, termed the J_V-integral, is both simple to implement, and general to the numerical method. Within the framework of finite elements, a propagation algorithm using the novel J_V-integral is subsequently constructed with two distinct abilities compared to the original J-integral. The first is an increased ability to capture the viscosity-dominated regime of propagation at significantly coarser resolutions. Finite element simulations conducted at various levels of refinement detail the promising results relevant to hydro-mechanical simulations at reservoir scale.  The ability of the method in simulating the toughness regime remains as performant as the original J-integral.  The second, is the ability of the J_V-integral in extracting the propagation velocity of the fracture; a feature particular to methods arising from hydraulic fracture mechanics. Consequently, the method demonstrates an inherent advantage when converging on the fracture length, requiring significantly fewer iterations compared to the original formulation. Fundamentally, the velocity obtained via the J_V-integral has the potential to be used in combination with front-tracking schemes like the implicit level set method. As a result, the J_V-integral appears to be a promising method when simulating hydraulic fracturing in geoenergy applications and beyond. 

How to cite: Pezzulli, E., Nejati, M., Salimzadeh, S., Matthai, S., and Driesner, T.: Modelling hydraulic fracturing with the J-integral, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13704, https://doi.org/10.5194/egusphere-egu21-13704, 2021.

Rocks in the subsurface are exposed to high amount of confinement which can potentially suppress the formation or the development of tensile-based cracks and thus, give rise to shear-based fracture growth. However, measuring the shear fracture toughness of rocks have been studied less in the literature, as providing the required confinement to force the shear fracturing precede tensile fracturing is not an easy task. In the current study, two new tests namely the double-edge notched Brazilian disk (DNBD) and the axially double-edge notched Brazilian disk (ANBD) are proposed to measure the in-plane (true mode II) and the out-of-plane (true mode III) shear fracture toughness of rocks, K_IIc and K_IIIc, respectively. We use the term true to emphasis that not only sustains the crack shear loading, but also the type of fracturing is shear-based. Finite element method is used to study the variations of stress field around the crack tip in these tests and to prove the applicability of the tests in providing mode II and mode III loading conditions. It is argued that both tests are straightforward and have several advantages compared to the existing ones. The effectiveness of the tests is empirically corroborated by conducting some experiments on Bedretto Granite. The pulverized surface of fracture in both the tests denotes the existence of friction which indicate the shear-based nature of fracture. Finally, the measured values of K_IIc and K_IIIc for Bedretto granite are compared to each other and to the reported values of K_Ic in the literature. It is shown that KIIc and KIIIc values are close to each other while both are more than two times greater than KIc.

How to cite: Bahrami, B., Nejati, M., Ayatollahi, M. R., and Dreisner, T.: In-plane and out-of-plane shear fracture toughness of rocks, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-6756, https://doi.org/10.5194/egusphere-egu21-6756, 2021.

Faults are crucial structures in the subsurface with respect to seismic hazards or the exploitation of the subsurface. However, even though it is clear that the released elastic energy changes the stress field, it is not well known at what distance these change leave a significant imprint on the stress tensor components. In particular, it is assumed that stress tensor rotations are a measure of these changes. Furthermore, from a technical point of view, the implementation of faults in geomechanical models is a challenging task. There are several implementation concepts are to mimic faults in geomechanical models. The two main classes are the continuous approach (soft of low plastic elements) and the discontinuous approach (contact surfaces). However, only partial aspects of the complex behaviour of faults or fault zones are represented by these techniques.

Knowing this limitation, we investigate the influence of the implementation concepts, fault properties and numerical resolution on the resulting stress field in the vicinity of a fault. The main focus of the generic models is to investigate, up to which distance from a fault, significant stress changes of the stress tensor components can be observed. In doing so, the respective models undergo a deformation that produces a similar stress state. The resulting stress magnitudes are investigated along a horizontal line at a depth of 660m, parallel to the shortening direction.

The result indicates, that stress magnitude pattern varies significantly close to the modelled fault, depending on the used implementation concept. However, beyond 500 m distance from the fault, the changes in stresses are < 0.5 MPa, regardless of the concept. Even a significant coarser resolution causes comparable stress patterns and magnitudes away from the implemented fault. Similarly, the dip angle, as well as the strike angle, have little effect on the observed distance effect. For stiff rocks having a higher Young's modulus, significant stress changes can also exceed the distance of 1000 m away from the fault.

The results indicate, that faults alone have limited effect on the far-field stress pattern. On the other hand, data of stress magnitudes or the stress tensor orientation close to a fault (< 500 m) are most likely affected by the particular fault geometry and fault characteristics. This is also the case for the vertical stress magnitude.

How to cite: Reiter, K. and Heidbach, O.: Stress field perturbations from faults, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10155, https://doi.org/10.5194/egusphere-egu21-10155, 2021.

Well-logging data show that geothermal formations typically feature layered heterogeneities. This imposes a challenge in numerical simulations, in particular in the upscaling of geothermal processes. The goal of our study is to develop an approach to (1) simplify the description of heterogeneous geothermal formations and (2) provide an accurate representation of convection/dispersion processes for simulating the up-scaled system.

In geothermal processes, transverse thermal conduction causes extra spreading of the cooling front: thermal Taylor dispersion. We derive a model from an energy balance for effective thermal diffusivity, α_eff, to represent this phenomenon in layered media. α_eff, accounting for transverse heat conduction, is much greater than the longitudinal thermal diffusivity, leading to a remarkably larger effective dispersion. A ratio of times is defined for longitudinal thermal convection and transverse thermal conduction, referred to as transverse thermal-conduction number N_TC. The value of N_TC is an indicator of thermal equilibrium in the vertical cross-section. Both N_TC and α_eff equations are verified by a match with numerical solutions for convection/conduction in a two-layer system. For N_TC > 5, the system behaves as a single layer with thermal diffusivity α_eff.

When N_TC > 5, a two-layer system can be combined and represented with α_eff and average properties of the two layers. We illustrate upscaling approach for simulation of geothermal processes in stratified formations, by grouping layers based on the condition of N_TC > 5 and the α_eff model. Specifically, N_TC is calculated for every adjacent two layers, and the paired layers with a maximum value of N_TC are grouped first. This procedure repeats on the grouped system until no adjacent layers meet the criterion N_TC > 5. The upscaled layer properties of the grouped system are used as new inputs in the numerical simulations. The effectiveness of the upscaling approach is validated by a good agreement in numerical solutions for thermal convection/dispersion using original and average layer properties, respectively (Figs. 1 and 2 in the Supplementary Data File). The upscaling approach is applied to well-log data of a geothermal reservoir in Copenhagen featuring many interspersed layers. After upscaling, the formation with 93 layers of thickness 1 – 3 meters is upscaled to 12 layers (Fig. 3 in the Supplementary Data File). The effective thermal diffusivity α_eff in the flow direction is about a factor of 10 times greater than original thermal diffusivity of the rock. Thus, α_eff should be used as simulation inputs for representing more accurately geothermal processes in the up-scaled system.

How to cite: Tang, J. and Rossen, W. R.: Application of Thermal Taylor Dispersion to Upscaling of Geothermal Processes in Heterogeneous Formations, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10564, https://doi.org/10.5194/egusphere-egu21-10564, 2021.

How to cite: Bourne, V. R., Cantu Bendeck, C. D., Hildyard, M. W., Clark, R. A., and Wills, W.: Fracture-generated frequency-dependent seismic Q measured from a VSP in granite, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12766, https://doi.org/10.5194/egusphere-egu21-12766, 2021.

In deep tight reservoirs like Enhanced Geothermal Systems (EGS), the fracture flow often plays a dominant role. The hydraulic and mechanical behaviors of the fracture are affected by a couple of factors such as the sealing deposits owing to mineral cementation. Here we aimed to investigate the impact of the sealing material on the hydro-mechanical properties of a rough fracture using a well-established self-affine rough fracture model. We developed finite element model based on the MOOSE/GOLEM framework dedicated to modeling coupled Hydraulic-Mechanical (HM) process of the rock-fracture system. We conducted numerical flow through a granite reservoir hosting one single large and partly sealed fracture of size 512x512 m². Navier-Stokes flow and Darcy flow are solved in the 3-dimensional rough aperture and in the embedding poro-elastic matrix, respectively. In order to mimic the impact of the fracture sealing material on the physical properties of the rock-fracture system, we sequentially increased the amount of the fracture-filling material in the rough fracture by changing the thickness of the sealing deposits.  The evolution of the contact area, fracture permeability, fracture diffusivity and normal fracture stiffness, is monitored up to the percolation threshold of the fluid flow. We show that sealing induces strong permeability anisotropy, significant decrease of hydraulic diffusivity and increase of fracture stiffness. The results have strong implications for optimizing the stimulation strategy like chemical stimulation of fractured reservoirs, as well as understanding the fluid-induced seismicity.

How to cite: Deng, Q., Schmittbuhl, J., Bloech, G., and Cacace, M.: Impact of fracture sealing on their hydraulic and mechanical properties, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13206, https://doi.org/10.5194/egusphere-egu21-13206, 2021.