ERE6.2

Faults and fractures in geoenergy applications 1: Numerical modelling and simulation

Nonlinear behavior and anisotropic flow fields and transport are vital challenges for naturally fractured reservoir modelling and simulation. Naturally fractured reservoirs are of great importance in various disciplines such as hydrogeology, hydrocarbon reservoir management, nuclear waste repositories 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 they often introduce a strongly nonlinear behavior. Numerical modelling of such systems is especially challenging and often requires creative new ideas to solve, for example the use of stochastic models. This refers in particular to the mechanical properties via reduction of strength and stiffness.
Fractures also provide the main flow and transport pathways in the rock mass, dominating over the permeability of the rock matrix, as well as creating anisotropic flow fields and transport. 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 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 behavior 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.

With field and laboratory studies from the same subjects please refer to the session: “Faults and fractures in geoenergy applications – monitoring, laboratory and field work results".

Co-organized by EMRP1
Convener: Reza Jalali | Co-conveners: Márk SomogyváriECSECS, Peter Bayer, Florian Amann
vPICO presentations
| Mon, 26 Apr, 13:30–15:00 (CEST)

vPICO presentations: Mon, 26 Apr

Chairpersons: Reza Jalali, Márk Somogyvári, Peter Bayer
13:30–13:35
13:35–13:45
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EGU21-658
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ECS
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solicited
Ivar Stefansson, Eirik Keilegavlen, and Inga Berre

In addition to significantly impacting flow properties, fractures may deform and propagate due to changes in the stress state. Such stress changes may e.g. be caused by changes in fluid pressure or rock temperature. Accounting for all interacting processes and structures leads to a tightly coupled and highly complex system.

We apply a mixed-dimensional model explicitly accounting for both rock matrix and fractures, the latter as two-dimensional objects. This framework enables tailored modeling in the different parts of the domain. We impose conservation of mass and energy in both fractures and matrix and conservation of momentum in the matrix. At the fractures, we impose contact mechanics relations and propagation criteria based on the local stress state. Coupling between fractures and matrix is formulated as interdimensional fluid and heat fluxes and displacement at the two fracture surfaces.

We demonstrate the model through three-dimensional transient simulations focusing on process-structure interaction. That is, we investigate the interplay between thermo-hydraulic processes and fracture deformation, including propagation of pre-existing fractures.

How to cite: Stefansson, I., Keilegavlen, E., and Berre, I.: Numerical modelling of deformation and fracturing of thermo-poroelastic media, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-658, https://doi.org/10.5194/egusphere-egu21-658, 2021.

13:45–13:47
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EGU21-7087
Lei Qinghua and Chin-Fu Tsang

We present a fully-coupled hydro-mechanical simulation of fluid injection-induced activation of pre-existing discontinuities, propagation of new damages, development of seismic activities, and alteration of network connectivity in naturally faulted and fractured rocks, which are represented using the discrete fracture network approach. We use the finite element method to compute the multiphysical fields including stress, strain, damage, displacement, and pressure by solving governing and constitutive equations of coupled solid and fluid domains. Essential hydro-mechanical coupling mechanisms are honoured such as pore pressure-induced shear slip of natural discontinuities, poro-elastic response of rock matrix, and stress-dependent permeability/storativity of both fractures and rocks. We use the numerical model developed to investigate the hydro-mechanical behaviour of deeply buried fractured rocks and fault zones in response to high-pressure fluid injection, with a specific focus on the system either below or above the percolation threshold. We observe a strong control of fracture network connectivity on the damage emergence, seismicity occurrence and connectivity change in the rock mass subject to hydraulic stimulation. We highlight the strong poro-elastic effect that tends to drive heterogeneous connectivity evolution of fracture systems during fluid injection. The results of our research and insights obtained have important implications for injection-related geoengineering activities such as the development of enhanced geothermal systems and extraction of hydrocarbon resources.

How to cite: Qinghua, L. and Tsang, C.-F.: Numerical simulation of fluid injection in faulted and fractured rocks based on a fully-coupled hydro-mechanical model, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-7087, https://doi.org/10.5194/egusphere-egu21-7087, 2021.

13:47–13:49
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EGU21-5064
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ECS
Iman Vaezi, Víctor Vilarrasa, Francesco Parisio, and Keita Yoshioka

Fractures control fluid flow and the coupled geomechanical response of geological media in many geo-engineering applications. For instance, fractures dominate fluid flow and deformation in enhanced geothermal systems, underground radioactive waste repositories, and CO2 storage. Coupled thermo-hydro-mechanical processes in rock masses are a result of perturbations in the pore pressure, as in fluid injection and/or production, and/or temperature, as in cold fluid injection and disposal of radioactive waste. For example, fractures open as a result of pore pressure increase, which simultaneously increases permeability and reduces overpressure.

Geo-engineering and geo-energy applications involve a large portion of rock masses that include several fractures. Numerical computations of coupled processes occurring in rock masses while considering a large number of fractures pose several challenges. In this study, we firstly focus on a simple problem to fully understand the hydro-mechanical behavior of a single fracture subjected to a constant injection flow rate. We use the FEM software CODE_BRIGHT, which solves the thermo-hydro-mechanical governing equations in a fully coupled way. Since standard FEM can solve equations in continuum media, we investigate the behavior of a single fracture by analyzing the hydro-mechanical parameters that control the fracture response in a continuum fashion. However, simulating fractures with the real aperture is not simply feasible, hence, we search the equivalent properties of thicker fractures that are more feasible to be discretized in large-scale models with several fractures.

As the pore pressure increases inside a fracture, the fracture aperture increases and enhances its transmissivity. The embedded model uses variable permeability as a function of the cubic law. The simulation results show that a continuum approach can represent a fracture with a relatively large thickness (in the cm order) instead of the real aperture dimension (in the order of the micron).

How to cite: Vaezi, I., Vilarrasa, V., Parisio, F., and Yoshioka, K.: Numerical simulation of coupled processes in a single fracture employing a continuum approach, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-5064, https://doi.org/10.5194/egusphere-egu21-5064, 2021.

13:49–13:51
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EGU21-3564
Warwick Kissling and Cecile Massiot

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.

13:51–13:53
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EGU21-4050
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ECS
Ajay Kumar Sahu and Ankur Roy

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.

13:53–13:55
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EGU21-8400
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ECS
Márk Somogyvári, Mohammadreza Jalali, Irina Engelhardt, and Sebastian Reich

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.

13:55–13:57
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EGU21-10581
|
ECS
Bora Yalcin, Olaf Zielke, and Martin Mai

Fractured reservoirs comprise finite or discrete fracture networks; if these are conductive, they
form heterogeneously distributed high-permeability streaks. These are generally referred as
fracture corridors. Unless they occur as joint swarms, fracture corridors are simply seismic or sub-
seismic fault zones with connected fractures in the near-fault damage zone. Several studies
document the decrease in rock-matrix permeability adjacent to the fault surface, within the
damage zone. Although the damage zone creates fracture connectivity and high permeability
anisotropy for reservoirs, the matrix fracture feeding mechanism is related to matrix permeability
generally described by a transfer function. This transfer function accounts for fracture properties
(i.e. fracture density, length and connectivity), relative fluid mobilities, imbibition and reservoir
properties (i.e. matrix permeability). Commonly, the matrix permeability for all transfer functions
is considered in terms of a representative rock type permeability. However, observational
evidence and our numerical model show that slip induced deformation causes significant strain on
matrix in vicinity to the fault surface causing a permeability decrease in the matrix.

In this study, we present a new approach to model strain in a porous medium and related
permeability changes due to stress perturbation from slip around pure strike slip faults. The fault
length is used to scale the amount fault slip. For given/computed dislocation (slip) the off-fault
strain is then calculated to derive porosity and permeability changes. In our study we propose an
off-fault plastic-poroelastic deformation model for any known fault length and known rock
mechanical and petrophysical properties of the surrounding material. Our modeling technique will
help to better quantify fault transmissivity in geo-reservoirs.

How to cite: Yalcin, B., Zielke, O., and Mai, M.: A model for off-fault plastic poroelastic deformation and its effects on permeability, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10581, https://doi.org/10.5194/egusphere-egu21-10581, 2021.

13:57–13:59
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EGU21-7810
|
ECS
Morteza Nejati, Mahsa Sakha, Bahador Bahrami, Saeid Ghouli, Majid R. Ayatollahi, and Thomas Driesner

Accurate predictions of fracture growth path resulted from fluid injection in subsurface is an important topic in geoscience projects such as wastewater injection, CO2 sequestration and geothermal energy extraction. Pressurised fluid not only creates new fractures in form of hydraulic fractures, but also potentially propagates pre-existing ones. A precise assessment of fracture growth path is pivotal in characterising the connectivity of the fracture network, and as a result, the hydraulic response of the rock volume. Numerical modelling provides a strong platform to help better understand fracture growth path during hydraulic stimulations. Despite significant progress in the computational power and advanced numerical algorithms in recent years, the numerical simulation of fracture growth still faces many challenges. Some of these challenges are related to the robustness of the numerical schemes used to model evolving fractures. The development of methods such as extended finite element and phase-field have greatly helped in recent years to tackle the evolution of fractures in complex trajectories. A second group of challenges is related to the development of accurate fracturing laws and their implementation into numerical codes in order to obtain realistic fracture growth trajectories. In this paper, we address some of the challenges in the second group and share our findings on how we can more accurately predict fracture path in subsurface. At first, we present our evaluation of the measured values of the fracture toughness in laboratory, and discuss why those values are mostly underestimating fracture toughness in rock masses. We then introduce a method to correct these values, that are obtained from small laboratory-sized specimens, to be able to use them in numerical codes that predict fracture growth in large rock volumes in subsurface. The second contribution is related to the rock anisotropy and its influence on the fracture growth path. We present experimental results on the anisotropy of fracture toughness, and show how important it is to take into account the directional-dependence of fracture toughness when modelling fracture growth in anisotropic formations. Lastly, the third contribution is to distinguish between tension-based and shear-based fracture growth mechanisms. Most numerical models in literature use the maximum tangential stress criterion to predict fracture growth path. We show that this criterion is not able to predict shear-based fracturing that often occurs in the subsurface. We conclude that a reliable numerical code needs to implement a fracturing law that is able to predict both tensile- and shear-based fracturing types.

How to cite: Nejati, M., Sakha, M., Bahrami, B., Ghouli, S., Ayatollahi, M. R., and Driesner, T.: Challenges in correctly assessing fracture growth in subsurface applications, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-7810, https://doi.org/10.5194/egusphere-egu21-7810, 2021.

13:59–14:01
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EGU21-13704
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ECS
Edoardo Pezzulli, Morteza Nejati, Saeed Salimzadeh, Stephan Matthai, and Thomas Driesner

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 JV-integral, is both simple to implement, and general to the numerical method. Within the framework of finite elements, a propagation algorithm using the novel JV-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 JV-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 JV-integral has the potential to be used in combination with front-tracking schemes like the implicit level set method. As a result, the JV-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.

14:01–14:03
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EGU21-6756
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ECS
Bahador Bahrami, Morteza Nejati, Majid Reza Ayatollahi, and Thomas Dreisner

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, KIIc and KIIIc, 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 KIIc and KIIIc for Bedretto granite are compared to each other and to the reported values of KIc 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.

14:03–14:05
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EGU21-10155
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ECS
Karsten Reiter and Oliver Heidbach

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.

14:05–14:07
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EGU21-10564
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ECS
Jinyu Tang and William R. Rossen

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, αeff, to represent this phenomenon in layered media. αeff, 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 NTC. The value of NTC is an indicator of thermal equilibrium in the vertical cross-section. Both NTC and αeff equations are verified by a match with numerical solutions for convection/conduction in a two-layer system. For NTC > 5, the system behaves as a single layer with thermal diffusivity αeff.

When NTC > 5, a two-layer system can be combined and represented with αeff 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 NTC > 5 and the αeff model. Specifically, NTC is calculated for every adjacent two layers, and the paired layers with a maximum value of NTC are grouped first. This procedure repeats on the grouped system until no adjacent layers meet the criterion NTC > 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 αeff in the flow direction is about a factor of 10 times greater than original thermal diffusivity of the rock. Thus, αeff 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.

14:07–14:09
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EGU21-12766
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ECS
Victoria R. Bourne, C. Dario Cantu Bendeck, Mark W. Hildyard, Roger A. Clark, and William Wills

We integrate two topics – seismic characterisation of fractures, and seismic attenuation quantified as the frequency-dependent Seismic Quality Factor Q, Q(f). The former is vital for predicting and monitoring fluid movement and containment in energy-related settings (hydrocarbons; geothermal; CO2, hydrogen or compressed air storage; radwaste). Fractures control the fluid flow and structural behaviour of a rock mass, yet their expression in Q is poorly studied and not well understood despite it typically being more sensitive than wavespeeds as a rock physics parameter. The latter is long-recognised, little-studied, and a paradigm shift from frequency-independent Q (‘constant-Q’, a routine signal-processing and image enhancement tool in hydrocarbon exploration), despite theory, laboratory, and field data showing that Q must be frequency dependent due to varying scale-lengths of the physical-mechanical phenomena causing attenuation.

We therefore measure Q(f) from the downgoing direct P-wave arrival in a near-offset vertical seismic profile in granite at a former geothermal test site in Cornwall, SW England, where vertical and horizontal fracturing is seen at surface: horizontal fractures are confirmed at depth by well-log data. Sensors were 3-component 15Hz geophones at 15m depth spacing: the source was a single vibrator, linear 8-100Hz up-sweep, 30m offset from the wellhead in the azimuth of well deviation: record length was 1000ms at 1ms sample interval. We analyse only the deeper cased interval, from 700m to 1735m. Pre-processing was geometric spreading correction, hodogram-based component rotation toward the source, and wavefield separation using a 7-point median filter to suppress interference from upgoing energy. Measured attenuation Qeff is the harmonic sum of intrinsic Q, Qint, and apparent attenuation, Qapp. Qint in massive granite is typically 500-1000, yet we find Qeff(f) is 50-70 at >60Hz and only ≈30 at <30-35Hz, features masked in the constant-Q result of 55±11 over our working bandwidth of 25-90Hz.

One contribution to Qapp is ‘stratigraphic attenuation’, forward-scattering interference of short-path internal multiple reflections superimposed on direct arrivals, and quantifiable from sonic and density well-logs using O’Doherty-Anstey-Shapiro methodology. We find it is indeed frequency-dependent (peaking at ≈50-60Hz, 10-40% lower at our bandwidth limits) but its absolute magnitude is insignificant (Q≈20,000-30,000) and unable to explain the measured Qeff(f). We therefore investigate the effect of fracturing directly using finite difference models in which fractures are defined explicitly as displacement discontinuities with opposing surfaces connected by a normal and shear stiffness. An individual fracture acts somewhat like a low pass filter: more complex frequency behaviour emerges from multiple fractures, particularly when fracture stiffness, spacing and size can vary. We concentrate first on large horizontal fractures perpendicular to the borehole receiver array, and find that these can indeed influence effective attenuation within the 25-90Hz bandwidth. We then discuss the range of fracture spacings and stiffnesses capable of explaining the data and whether they are sufficiently physically credible as an explanation of the observed Q(f).

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.

14:09–14:11
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EGU21-13206
Qinglin Deng, Jean Schmittbuhl, Guido Bloech, and Mauro Cacace

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.

14:11–14:13
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EGU21-15250
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ECS
Lamia Boussa, Amar Boudella, and José Almeida

Reservoir characterization and flow studies require accurate inputs of petrophysical properties such as porosity, permeability, water and residual oil saturation and capillary pressure functions. All these parameters are necessary to evaluate, predict and optimize the production of a reservoir.

This study is the continuity of a previous work that summarize the construction of a net rock aerial map by combining stochastic simulation of rock types and processed seismic data. In this case study; petrophysical data are integrated to construct a 3D model of porosity corresponding to the 3D model of rock type. This is in order to further understand the intricacies of the geostatistical methods used and the impact of the technique on the resulting uncertainty profile

For the construction of 3D model of porosity corresponding to the 3D model of rock types, a geostatistical workflow encompassing the modelling of experimental variograms and sequential Gaussian simulation (SGS) were used. The geostatsitical methodologies of stochastic simulation such as SGS enabled the generation of several realistic scenarios of constinuous data, such as porosity, within a volume, thus facilitating the association of local probabilities of occurrence of each rock type.

The resulting porosity image properly combines the available seismic and well data and balance the local and regional uncertainty of the studied reservoir volume.

Keywords: Geostatistics, Sequential Gaussian Simulation (SGS), Rock types, Porosity, Uncertainty, Spatial resolution.

How to cite: Boussa, L., Boudella, A., and Almeida, J.: Assessing of tight reservoir by combining the porosity of geological units, and simulated images of rock types: A case study, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-15250, https://doi.org/10.5194/egusphere-egu21-15250, 2021.

14:13–15:00