ERE5.3

Hydraulic fractures often turn or branch, interacting with pre-existing discontinuities (e.g. natural fracture, grain boundary). Such fracture complexities, especially in the proximity of borehole, impact the subsequent well conductivity. When a fracture finds a discontinuity, it either penetrates or deflects depending supposedly on the in-situ stress and the discontinuity geometry. However, our hydraulic fracture experiments on carbonates show that the fractures deflected more frequently at a grain boundary as they propagated farther away from the borehole. In other words, the fracture complexity consistently increases with the propagation distance. In this study, using energy release rate analyses, we show that the energy dissipation of a penetrating fracture increases with the distance away from the borehole. This means, the farther away the hydraulic fracture propagates, the more easily it deflects at a grain boundary from the energetic point of view. This tendency was also confirmed by numerical hydraulic fracture simulations based on a successive energy minimization approach. Our findings challenge the conventional hydraulic fracture penetration/deflection criteria based only on the in-situ stress and the discontinuity geometry. 

How to cite: Yoshioka, K., Katou, M., Tamura, K., Arima, Y., Ito, Y., Chen, Y., and Ishida, T.: Hydraulic fracture interactions with mineral grains, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-1624, https://doi.org/10.5194/egusphere-egu22-1624, 2022.

Characterizing and modelling geometrical and topological characteristics of fracture networks, both in fault zones and in the less-fractured background, is essential for the analysis and modelling of mechanical and hydraulic properties of rock masses (i.e. rock plus fractures). Here we present evidence of a counterintuitive behavior in mechanically layered sequences of different kinds of rocks, from porous carbonates to metamorphic rocks. In our case studies the more intense fracturing, both in terms of fracture density/intensity and number of fracture sets, is observed in the more competent layers, that can be therefore considered the more permeable ones.

In large outcrops of the Island of Gozo (Malta) we have characterized several damage zones in the Lower Globigerina Member (LGM) and Lower Coralline Limestone (LCL). A complete petrophysical and geomechanical characterization of these rocks shows the following properties (LGM vs. LCL): porosity 33% vs. 23%; Young’s modulus 2.4GPa vs. 5.5GPa; Poisson’s coefficient 0.18 vs. 0.15; UCS 14MPa vs. 36MPa; tensile strength 2.3MPa vs. 4.4MPa. Despite the LGM being by far the “softer” mechanical layer, we see that the thickness of the damage zone is about 1/30 in this unit with respect to the LCL, and that, comparing sections at the same distance to the fault core, fracture intensity is about 1/10.

In large outcrops in the Breuil-Cervinia area, at the foots of the Italian side of the Cervino-Matterhorn, we have observed a strikingly similar situation in uniformly fractured rocks (no major fault here) of the Dent Blanche and Combin Nappes. These are, in order of decreasing competence, greenschist facies (possibly formerly blueschist) meta-gabbros and meta-granitoids (Dent Blanche), and prasinites and calcschists (Combin). As in the Gozo case study, our quantitative characterization of fracturing reveals an inverse correlation between competence and fracturing parameters.

To understand the physics behind these observations, we have performed simulations with a geomechanical finite element code. During horizontal extension of a multilayer with variable elastic properties, deviatoric stresses build up much more quickly in less compliant, stiffer rocks. This is because all the different layers are subject to the same strain (horizontal stretching), and stress is controlled by the elastic moduli, resulting in higher deviatoric stresses in more rigid layers. At some point, brittle failure (simulated as plastic yield in continuous FEM codes) takes place in the stiff layers, well in advance with respect to failure in the soft ones. At this point, the simulation reveals a situation where fracturing is confined in the stiff layers. As horizontal stretching continues, failure can occur also in the soft layers, but always in a more limited way.

Even if in the Cervino-Matterhorn case study also pressure solution should have played a role in inhibiting fracturing in calcschists, we feel that this mechanical behavior, observed in very different tectonic environments and lithological units, can be of general relevance and might result in a reevaluation of paradigms used to predict fracturing and hydraulic properties of mechanically layered reservoirs in general.

How to cite: Bistacchi, A., Martinelli, M., Castellanza, R., Arienti, G., Dal Piaz, G., Monopoli, B., and Bertolo, D.: Counterintuitive fracturing in a multilayer of more or less competent rocks: Examples in porous carbonates and metamorphic rocks, and explanation with numerical modelling, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-11415, https://doi.org/10.5194/egusphere-egu22-11415, 2022.

Hydraulic fracturing is widely applied in unconventional reservoirs to generate fracture networks for productivity enhancement. Interactions between hydraulic fractures and natural fractures have a great impact on fracture propagation. In this study, we use a two-dimensional phase field model to investigate interactions between hydraulic fractures and different frictional or cemented fractures under different in-situ stress, injection rate, natural fracture orientation and strength. We find that with the increasing stress anisotropy, hydraulic fracture is more likely to cross natural fracture and leads to a lower fracture complexity. A moderate injection rate is conducive for complex fractures. The approaching angle between the hydraulic fracture and natural fracture impact fracture topology. Complex fractures are formed when the angles are not so steep. With the increasing strength contrast between natural fractures and the rock matrix, the material heterogeneity increases for hydraulic fractures to generate complex fractures. Compared with frictional NFs, opening stronger cemented NFs requires more pressure than hydraulic fracture propagating outside the interface. The numerical investigations in this study can provide theoretical support and design guidance for fracturing operations in complex geological conditions.

How to cite: Li, X., Hofmann, H., Yoshioka, K., Luo, Y., and Liang, Y.: Phase Field Modelling of Interactions Between Hydraulic Fractures and Natural Fractures, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5614, https://doi.org/10.5194/egusphere-egu22-5614, 2022.

Acid fracturing has been widely used in the oil and gas industry to increase permeability in carbonate reservoirs. In recent years this chemical stimulation technique has been borrowed from the oil and gas industry, employed in the enhanced geothermal systems at Groß Schönebeck, Germany (Zimmermann et al., 2010), and at Soultz-sous-Forêts, France (Portier et. al., 2009). In concept, acid fracturing utilizes strong acids that react with acid-soluble rock matrix in order to non-uniformly etch fracture surfaces. The permeability-enhancing effect depends upon the degree of surface irregularity after pore-scale acidizing which is affected by the compositional heterogeneity of the reacting rock matrix, fracture aperture heterogeneity, and flow and transport heterogeneity. In order to have an insight into these impacts on the acid etching process with the final goal of determining optimum operating conditions (e.g., acid type and acid injection rate), a pore-scale acid-fracturing model is needed. The core components of the pore-scale acid-fracturing model consist in tracking the motion of the fluid-matrix boundary surface induced by acid etching. To date, a number of front tracking approaches (e.g., local remeshing technique, embedded boundary method, immersed boundary method, and level-set method) have been proposed by many researchers in order for moving boundary problems. Each approach has its pros and cons. In this work, we propose employing the phase-field approach as an alternative to the existing front tracking approaches to capture the physically sharp concentration discontinuities across the liquid-solid interface. The developed pore-scale acid-fracturing model includes the Stokes-Brinkmann equations for fluid flow in the fracture-matrix system, the multi-component reactive transport equation for transport of solute species in the rough-walled fracture, and the phase-field equation for the reaction-driven motion of the fluid-matrix boundary surface. Through this numerical study, we demonstrate that the phase-field approach is viable to track recession of carbonate fracture surface by acid etching and to capture the solute concentration jump (w.r.t., Ca²⁺, H⁺, and HCO3⁻) across the solid-liquid interface.

Reference

Zimmermann, G., Moeck, I. and Blöcher, G., 2010. Cyclic waterfrac stimulation to develop an enhanced geothermal system (EGS) — conceptual design and experimental results. Geothermics, 39(1), pp.59-69.

Portier, S., Vuataz, F.D., Nami, P., Sanjuan, B. and Gérard, A., 2009. Chemical stimulation techniques for geothermal wells: experiments on the three-well EGS system at Soultz-sous-Forêts, France. Geothermics, 38(4), pp.349-359.

How to cite: Lu, R., Miao, X.-Y., Kolditz, O., and Shao, H.: Pore-scale modeling of acid etching in a carbonate fracture, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-3960, https://doi.org/10.5194/egusphere-egu22-3960, 2022.

Faults and fractures in carbonate reservoirs strongly influence subsurface fluid movement and can determine the success or failure of geothermal energy and heat production projects. Characterizing their physical and hydraulic properties is therefore crucial. Firstly, because they strongly control the secondary porosity and permeability of the reservoir, which are key parameters for the estimation of the reservoir quality, and for the planning of injection/extraction strategies. Secondly, because upon anthropogenic reactivation, they can lead to felt seismic activity, which could interrupt operations and potentially lead to damage to infrastructure and endanger the population.

Devonian carbonate rocks underlie a vast portion of North Rhine-Westphalia in Western Germany. Their stratigraphic thickness (up to 1,300 m), location, and depth, make them a potential reservoir for deep geothermal heat and energy exploitation. While estimated at depths between 1.3 km and 6 km, outcrop analogues of these Devonian carbonates are exposed in a number of quarries in the region.

This work quantitatively characterizes the fracture and fault distribution and permeability of the Devonian limestones and dolostones exposed at the the Steltenberg quarry, located at the northern margin of the Remscheid-Altena Anticline. The units outcropping in the quarry are tectonically affected by splays of the WSW-ENE-trending Ennepe thrust (Variscan), and by post-Variscan NNW-SSE-trending normal faults. We combine field structural analyses and fracture characterization using scan lines with a 3D digital outcrop model and fracture analyses using UAV imagery, to produce 3D Discrete Fracture Network (DFN) models. Preliminary results show three main fracture sets: WSW-ENE-trending and S-dipping fractures parallel to the Ennepe Thrust, WSW-ENE-trending and N-dipping bedding-parallel fractures, and NNW-SSE-trending sub-vertical fractures parallel to the regional post-Variscan normal faults. Our DFN modeling suggests that the latter represent the main pathways for fluid flow with permeability values up to 10^-14 m².

As next steps we will use the DFN modeling results (e.g., fractures sets, permeability tensor) as input for a 3D thermo-hydro-mechanical finite element model aimed at predicting fluid flow, pressure, and stress changes in a potential geothermal reservoir. Modeling, together with fault-related parameters such as slip tendency and fracture susceptibility, will help estimate the potential for fault reactivation and induced seismicity in the region.

How to cite: Verdecchia, A., Pederson, C., Smeraglia, L., Lippert, K., Immenhauser, A., and Harrington, R.: Discrete fracture network analysis of Devonian carbonate rocks in Western Germany: Implications for deep geothermal energy, heat exploitation and anthropogenic fault reactivation, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4620, https://doi.org/10.5194/egusphere-egu22-4620, 2022.

Temperature estimation in hydrothermal reservoirs is a critical point for the feasibility of geothermal projects and subsequent processes, such as chemical and biological activity as well as thermal stresses. As flowing fluid and surrounding host rock locally diverge in temperature until equilibrium occurs, heat transfer between phases needs to be described. However, this is a challenging task, especially in fractures, because the heat transfer coefficient depends on various parameters, such as flow velocity and aperture. Heat transfer characteristics in fracture networks, and their dependence on fracture network characteristics, have been rarely studied so far.

Starting from a newly developed analytical solution of heat transfer in single fractures, a consistent formulation for heat transfer in fractured reservoirs is presented. Using an intermediate step of bench-scale experiments, the sensitivity of the temperature field in the fracture network with respect to the heat transfer coefficient is investigated. Due to multiple flow paths within a reservoir, the heat transfer capabilities of individual fractures can become less relevant in well-connected reservoirs. On the other hand, single fractures with uncommon velocity or aperture values can cause local heterogeneities in the temperature field due to the velocity-dependent heat transfer.

Bridging the gap between well-defined networks with a limited number of fractures and large-scale fracture networks of arbitrary shape requires a change in the parameters used. On large scale, effective values such as fracture density and anisotropic permeability are more suitable and accessible than single fracture apertures. To incorporate such a change in parameterization, a new theoretical framework based on the assumption of fracture networks with a regular geometry is presented.

The presented work sheds new light on the heat transfer mechanisms in fractures and fracture networks and is the first attempt to derive a consistent mathematical framework for heat transfer in fractures across scales.

How to cite: Heinze, T.: Heat transfer across scales: from single fractures to fracture networks, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2163, https://doi.org/10.5194/egusphere-egu22-2163, 2022.

Geothermal energy applications involve heat circulation in naturally fractured reservoirs, which are in general difficult to characterize due to the multiscale complexity of the fracture network and therefore the flow. In this context, numerical modeling is key to forecast the performance of geothermal energy applications under a number of scenarios. Numerical modeling is challenging because fractures represent the main pathway for flow and advective transport, but diffusive thermal exchange with the host rock controls the geothermal performance - the two processes occurring on very different length and time scales. Moreover, the host rock cooling provokes thermal contraction which tends to increase the fracture aperture, with direct effects on the flow and the advective transport. Quantify these processes is crucial but in general computational demanding when dealing with large reservoirs with hundreds of thousands of fractures.

In this study we present a novel methodology to simulate thermo-mechanical (TM) heat transport. The method is based on the particle tracking approach in Discrete Fracture Networks (DFN) and it has been implemented in the DFN.Lab software platform. The contribution of the host rock matrix in terms of diffusive heat exchange and thermal contraction/expansion is analytically evaluated, which directly impacts the fracture aperture and therefore the advective heat transfer. The methodology enables investigating the reservoir behavior and optimizing the geothermal performance while keeping the computational effort within reasonable values. Results from simulations of cold fluid injection show that rock contraction accelerates the advective transport resulting in a faster recovery of cold fluid at the outlet. We analyze systems of fractures with different characteristics (density, aperture, geometrical patterns, ...) and we identify the parameters that mostly impact the TM response.

How to cite: De Simone, S., Pinier, B., Bour, O., and Davy, P.: A numerical study on the thermo-mechanical response of deformable fractured systems to advective-diffusive heat transport, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5748, https://doi.org/10.5194/egusphere-egu22-5748, 2022.

Naturally fractured systems are an important component to fluid flow for a variety of applications, in particular geothermal energy extraction. Geothermal reservoirs often have low rock permeability (e.g. limestone reservoirs) where permeability anisotropy is governed at first order by fractured networks controlled by fracture density, orientation and connectivity. These are often difficult to assess and as such permeability estimates can lead to high uncertainties. Understanding how fracture networks influence permeability of reservoirs is an important aspect to geothermal exploration.

Where subsurface data (e.g. seismic and well) are limited, other data sources for characterising the reservoirs are required. Outcrop analogues are excellent areas for the analysis and characterisation of fractures within the host rocks found at depth. 2D fractured cliff faces and pavements provide information on variation in fracture arrangement, distribution and connectivity which can be utilised in thermohydraulic modelling of the geothermal system.

Through imaging of 2D fractured faces within target reservoir rocks and using efficient discretisation and homogenisation techniques, reliable predictions on permeability distributions in the geothermal reservoirs can be made. Using an example from an open pit quarry within the Franconian Basin, Germany, fracture network anisotropy in a geothermal reservoir (Malm) is assessed using detailed structural analysis and numerical homogenisation modelling of outcrop analogues.

Structural analysis shows several events affected the limestone reservoir unit in the area. The first major phase of deformation recorded are steep-angled reverse thrust and strike-slip faulting (stress orientated NNE-SSW) attributed to the Late Cretaceous Inversion. A second deformation phase causing normal faulting and fracturing within a NW-SE stress field is related to the European Cenozoic Rift System (e.g. Eger Rift). The final deformation phase recorded corresponds to the Alpine Orogeny where strike-slip faults and conjugate fractures are formed under a NW-SE compression and NE-SW extension. The faults and fractures are heavily influenced by the Kulmbach Fault, part of the Franconian Lineament Fault System that is observed 10m north of the quarry and active during the multiphase deformation culminating with a reverse throw of 800m.

2D imagery is used to capture the fracture networks interpreted through the structural analysis from which different sets of similar fractures are extracted. These are then digitised and meshed for numerical modelling and homogenisation using MOOSE Framework. Three fractured faces are imaged at increasing distance from the Kulmbach Fault to determine the fault impact on the potential flow within the system. The calculated permeability tensors from the homogenisation show differences in fluid transport direction where fracture permeability is controlled by orientation compared to a constant value which would be more pronounced for larger scale simulations. Therefore, for reliable predictions of geothermal flow within the networks, assigning permeabilities for sets is vital. As a result, it is observed that the orientation of the tensor is influenced by the Kulmbach Fault, and thus faults within the reservoirs at depth should be considered as important controls on the fracture flow of the geothermal system.

How to cite: Smith, R., Lesueur, M., Kelka, U., Koehn, D., and Poulet, T.: Using fractured outcrops to calculate permeability tensors. Implications for geothermal fluid flow within naturally fractured reservoirs. , EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-11868, https://doi.org/10.5194/egusphere-egu22-11868, 2022.

Accurate assessment of fault-related CO₂ migration hazard is required to deploy geologic carbon storage at the gigaton scale. First, we present a novel methodology, PREDICT, to model the intrinsic permeability of faults in siliciclastic sequences. PREDICT models realizations of the fault core consistent with the stratigraphy, and computes the probability distributions for the directional components (dip-normal, strike-parallel and dip-parallel) of the fault-scale permeability tensor. PREDICT accounts for uncertainty in the geologic variables influencing fault permeability and was developed for scenario building and risk management.

Second, we show how to leverage PREDICT to build geologically-realistic fault leakage scenarios using a model of the Miocene offshore Texas, Gulf of Mexico. The process includes selection of anisotropic, upscaled fault permeability values from PREDICT’s output, upscaling of multiphase-flow fault properties (relative permeability and capillary pressure), and CO₂-brine numerical simulation for hundreds of years. CO₂ migration through the fault and into overlying units is tracked in each scenario, and results are compared with SGR-based fault property modeling.

How to cite: Saló-Salgado, L., Davis, S., and Juanes, R.: Anisotropic fault permeability upscaling and modeling of fault CO2 migration scenarios during geologic carbon sequestration, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2089, https://doi.org/10.5194/egusphere-egu22-2089, 2022.

The CCS (Carbon Capture & Storage) process involves the capture of CO₂ produced by energy production plants, cement factories and refineries, transport to storage sites and injection into deep geological structures with physical and chemical characteristics suitable for long-term confinement. This technology can significantly assess the containment of CO₂ emissions into the atmosphere, with an estimated reduction between 12% and 14%. One of the most important phases in which the role of the geoscientist is necessary is the screening of the structures with the suitable geological characteristics for CO₂ trapping and the estimation of the injectable mass.

Storage capacity estimates are usually approximate and are based on the average geometric and physical values of the geological formations. Furthermore, not knowing in detail the heterogeneity and complexity of geological structures, many storage efficiency scenarios are presented, which consequently propose very different values. Fractured rocks are one of the largest resources on the earth's surface, and host many of the most important reserves of water, oil and natural gas, and can also be exploited for the storage of gas or carbon dioxide. Determining the dynamic behaviour of fluids within a fractured rock mass is a necessary step in the characterization and definition of a potential site for CO₂ injection.

In this work a Discrete Fracture Network (DFN) approach is used to quantify the efficiency of fracture systems to the fluid transport, quantifying the mass of supercritical CO₂ injectable in a volume of rock with different fracture intensity in a purely discrete approach, with the utilization of dfnWorks and FEHM software. Using multi-phase reservoir simulations of CO₂ injection, we determine the efficiency and storage capacity of fractured rocks. The main result this approach is the introduction of the Efr index which quantifies the efficiency of fracture systems for supercritical CO₂ injection. This index allows, starting only from the fracture intensity data and using the equations proposed in the literature for the calculation of the storage capacity, to obtain an immediate and reliable estimate of the volume of the aquifers, which consider the efficiency of fractured aquifers to the fluid flow.

How to cite: Proietti, G., Romano, V., Pawar, R., and Bigi, S.: The real potential of fractured aquifers for CO2 storage, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-9292, https://doi.org/10.5194/egusphere-egu22-9292, 2022.

In a geological CO₂ storage site, the main migration pathways in case of leakage would be compromised boreholes or gas permeable faults or fractures. In this work we propose a modeling workflow based on detailed field data acquired on a fault exposed in the Roman Valley Quarry (Majella Mountain, Italy), to simulate the three-dimensional migration of gas CO₂ in the fault zone. The numerical modeling is performed using the open-source multiphase flow simulator PFLOTRAN. This study provides a new methodology to characterize the hydraulic behavior of a fault including all its components, the core and the damage zone, capturing in detail the impact of the fault zone architecture to the migration of CO₂. Simulation test results point out the robustness of the modeling approach, highlighting its strong predictive power, and show how most of the gas migrates through the high permeable footwall damage zone, where the injection occurs, whereas some of the gas also migrates through the hanging wall damage zone and the fault core. The buildup of gas pressure in the vicinity of the injection wells demonstrates the need of increasingly accurate modeling of the injection conditions to avoid possible faults reactivation and CO₂ leakage. While the technique presented here is applied to a case scenario on carbonate rocks, the proposed methodology can be extended to other geological scenarios, by the appropriate calibration of the geometric and petrophysical parameters of fractures and host rock, to understand the conditions under which faults can promote fluid flow from a reservoir and mitigate the risk of CO₂ migration via faults.

How to cite: Romano, V., Bigi, S., Park, H., Valocchi, A. J., Hyman, J. D., Karra, S., Nole, M., Hammond, G., Proietti, G., and Battaglia, M.: A numerical model for CO2 gas migration in a fault zone., EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-11289, https://doi.org/10.5194/egusphere-egu22-11289, 2022.

Quantifying the effective permeability structure of fault and fracture zones is crucial for numerous geo-energy applications, especially at sub-seismic scales. However, the multi-scale presence of fractures and the structural heterogeneity of faults and host rocks often cause highly non-stationary and anisotropic hydraulic properties. This usually impedes the definition of representative elementary volumes and complicates the upscaling process. Thus, progressively integrating these multi-scale complexities into 3D numerical models of exploration targets has gained increasing scientific interest in recent years and is crucial to make predictions of flow and transport through reservoirs.

Here, we aim to reproduce multiple drawdown curves obtained in analog field pumping tests with numerical models of fluid flow in order to develop a proof of concept for generating correct hydraulic representations of fault and fracture zones in numerical models with the final goal to upscale their effective permeabilities for numerical simulations above the sub-seismic scale.

The test subject is a 30- by 30-meter-wide area in a quarry in the Franconian Alb, Germany, featuring an intensively deformed Upper Jurassic limestone formation, frequently explored for geothermal energy production in the southern German Molasse Basin. First, an initial 3D structural model of the main faults, fractures, and layer surfaces, based on multiple borehole logs and pavement traces is constructed with the GemPy software. In the next step, we employ a newly developed discretization method to convert the initial 3D GemPy model into various equivalent continuum models of the test field by parameterizing fracture, fault, and rock matrix permeabilities/porosities, resulting in high-resolution 3D voxel models with individual, anisotropic permeability tensors. Those serve as input for numerical simulations of a pumping test, where we solve for transient, unsaturated/saturated Darcy-flow using a newly developed parallel, 3D finite element code that utilizes a van Genuchten approximation for the arising non-linearities, i.e., relative permeability and water content. As a final step, we compare the drawdown curves logged in three observation wells in an analog constant-head hydraulic test in the field to the ones obtained from the numerical simulations by computing a cumulative misfit. While changing the parameters of the employed permeability-porosity parametrizations for faults, fractures, and rock matrix in a classical forward-approach manner, we can determine a range of best-fitting models. Preliminary results show that with some educated initial guesses on the hydraulic properties of the reservoir, we could reproduce the drawdown curves in two observation wells with a relative error below one percent after a couple of tens of simulations. The uniqueness of those results will be assessed during the discussion.

How to cite: Kottwitz, M. O., Popov, A. A., Freitag, S., Bauer, W., and Kaus, B. J. P.: Towards validating numerical simulations of drawdown in unconfined fractured rocks with field experiments: A comparative study at sub-seismic scale, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4116, https://doi.org/10.5194/egusphere-egu22-4116, 2022.

Control volume finite element (CVFE) methods provide flexible framework for modelling flow and transport in complex geological features such as faults and fractures. They combine the finite element method that captures complex flow characteristics with the control volume approach known for its stability and mass conservative properties. The general approach of CVFE methods maps the physical properties of the system onto the element mesh (element-wise properties) while the node centred control volumes span element boundaries. In the presence of abrupt material interfaces between elements which are often encountered in fractured models, the method suffers from non-physical leakage in the saturation solution as the result of control volume discretization used for advancing the transport solution. In this work, we present a discontinuous pressure formulation based on control volume finite element (CVFE) method for modelling coupled flow and transport in highly heterogeneous porous media. We propose the element pair P_(1,DG)-P_(0,DG), a discontinuous first order velocity approximation combined with a discontinuous low order pressure approximation. The approach circumvents the non-physical leakage issue by incorporating a discontinuous, element-based approximation of pressure. Hence, the resultant control volume representation directly maps to the element mesh as well as to the projected physical properties of the system. Due to the low order nature of the formulation, low computational requirement per element and the improved control volume discretization, the presented formulation is proven more robust and accurate than classical CVFE methods in the presence of highly heterogeneous domains.

How to cite: Al Kubaisy, J., Salinas, P., and Jackson, M.: Discontinuous low order pressure formulation in control volume finite element method for simulating flow and transport in highly heterogeneous porous media, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-12372, https://doi.org/10.5194/egusphere-egu22-12372, 2022.

The Wenchang 9/8 area is one of the most promising hydrocarbon accumulation zones in the Pear River Mouth Basin, China. In this area, oil and gas are mainly accumulated in the Zhuhai and Zhujiang formations and their hydrocarbon reservoirs are generally related to faults, which are mainly located at the intersection area between NW-striking faults and NE-striking faults. Furthermore, previous petroleum exploration indicates that oil and gas are mainly sealed by faults. Therefore, high-resolution fault sealing calculation like shale-gauge-ratio (SGR) has a significant influence on further petroleum production. Present methods can only calculate single or discontinuous points of SGR for one fault and does not provide the SGR for the entire fault plane, which could impact future petroleum exploration. Testing several methods, we established the 3D fault plane SGR calculation method, which is based on the Petrel software platform. We then used this method on proven oil-bearing structures and target structures in the Wenchang 9/8 area. The results show that: (1) the 3D fault plane SGR of the fault, which controls the Wenchang 9-3 oil-bearing structure, reaches 35%-45%; the 3D fault plane SGR of the fault, which controls the Wenchang 9-7 oil-bearing structure, reaches 40%-55%. Therefore, the 3D fault plane SGR in Wenchang 9-3 and 9-7 oil-bearing structures are consistent with petroleum production; (2) For the target structures the 3D fault plane SGR in target 1 reaches 35%-55%. This is very high and supposed to be the next promising area in the study area, while the 3D fault plane SGR in target 2 is just 20-25%, which indicates high exploration risk at this target. Accordingly, we will promote this method for exploration targets in other petroliferous basins.

How to cite: Xu, L., Wu, Z., Cheng, Y., and Xu, B.: 3D fault plane SGR calculation for fault sealing in Petrel software: An example from Wenchang 9/8 area of the Pear River Mouth Basin, China, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13140, https://doi.org/10.5194/egusphere-egu22-13140, 2022.