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G Bertotti - One of the best experts on this subject based on the ideXlab platform.
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the mps based Fracture Network simulation method application to subsurface domain
81st EAGE Conference and Exhibition 2019, 2019Co-Authors: Pierreolivier Bruna, G Bertotti, Rahul Prabhakaran, Julien Straubhaar, R Plateaux, L Maerten, Gregoire Mariethoz, Marco MedaAbstract:Natural Fractures conduct fluids in subsurface reservoirs. Quick and realistic predictions of the Fracture Network organization and its fluid flow efficiency from limited amount of data is critical to optimize resources productivity. We recently developed a method based on multiple point statistics (MPS) technique to produce geologically-constrained Fracture Network simulations. The method allows to account for the intrinsic non-stationarity of these Networks by considering a multivariate input data instead of averaged distribution of Fracture parameters. In addition, the method considers probability maps reflecting the influence of Fracture drivers in the Network variability. Consequently, the simulated Fracture Networks derived from the innovative MPS approach are geologically better constrained than in classical discrete Fracture Network modelling approaches. This paper proposes to apply this method in subsurface conditions where available data are sparsely distributed. We developed a workflow where data are gathered from wellbore and from additional sources (outcrops). These data are used to extrapolate a Network around the borehole as training images and themselves are extrapolated at the reservoir scale following a geological probability map.This work also presents innovations on the way how training images and probability maps that may integrate more geology constrain than relying almost entirely on available data.
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A new methodology to train Fracture Network simulation using multiple-point statistics
Copernicus Publications, 2019Co-Authors: P.-o. Bruna, K Bisdom, G Bertotti, J. Straubhaar, R. Prabhakaran, G. Mariethoz, M. MedaAbstract:Natural Fracture Network characteristics can be establishes from high-resolution outcrop images acquired from drone and photogrammetry. Such images might also be good analogues of subsurface naturally Fractured reservoirs and can be used to make predictions of the Fracture geometry and efficiency at depth. However, even when supplementing Fractured reservoir models with outcrop data, gaps will remain in the model and Fracture Network extrapolation methods are required. In this paper we used Fracture Networks interpreted from two outcrops from the Apodi area, Brazil, to present a revised and innovative method of Fracture Network geometry prediction using the multiple-point statistics (MPS) method.The MPS method presented in this article uses a series of small synthetic training images (TIs) representing the geological variability of Fracture parameters observed locally in the field. The TIs contain the statistical characteristics of the Network (i.e. orientation, spacing, length/height and topology) and allow for the representation of a complex arrangement of Fracture Networks. These images are flexible, as they can be simply sketched by the user.We proposed to simultaneously use a set of training images in specific elementary zones of the Apodi outcrops in order to best replicate the non-stationarity of the reference Network. A sensitivity analysis was conducted to emphasise the influence of the conditioning data, the simulation parameters and the training images used. Fracture density computations were performed on selected realisations and compared to the reference outcrop Fracture interpretation to qualitatively evaluate the accuracy of our simulations. The method proposed here is adaptable in terms of training images and probability maps to ensure that the geological complexity in the simulation process is accounted for. It can be used on any type of rock containing natural Fractures in any kind of tectonic context. This workflow can also be applied to the subsurface to predict the Fracture arrangement and fluid flow efficiency in water, geothermal or hydrocarbon Fractured reservoirs.
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multiscale Fracture Network characterization and impact on flow a case study on the latemar carbonate platform
Journal of Geophysical Research, 2015Co-Authors: N J Hardebol, G Bertotti, Christine Maier, Hamid Nick, Sebastian Geiger, Herman BoroAbstract:A Fracture Network arrangement is quantified across an isolated carbonate platform from outcrop and aerial imagery to address its impact on fluid flow. The Network is described in terms of Fracture density, orientation, and length distribution parameters. Of particular interest is the role of Fracture cross connections and abutments on the effective permeability. Hence, the flow simulations explicitly account for Network topology by adopting Discrete-Fracture-and-Matrix description. The interior of the Latemar carbonate platform (Dolomites, Italy) is taken as outcrop analogue for subsurface reservoirs of isolated carbonate build-ups that exhibit a Fracture-dominated permeability. New is our dual strategy to describe the Fracture Network both as deterministic- and stochastic-based inputs for flow simulations. The Fracture geometries are captured explicitly and form a multiscale data set by integration of interpretations from outcrops, airborne imagery, and lidar. The deterministic Network descriptions form the basis for descriptive rules that are diagnostic of the complex natural Fracture arrangement. The Fracture Networks exhibit a variable degree of multitier hierarchies with smaller-sized Fractures abutting against larger Fractures under both right and oblique angles. The influence of Network topology on connectivity is quantified using Discrete-Fracture-Single phase fluid flow simulations. The simulation results show that the effective permeability for the Fracture and matrix ensemble can be 50 to 400 times higher than the matrix permeability of 1.0 · 10−14 m2. The permeability enhancement is strongly controlled by the connectivity of the Fracture Network. Therefore, the degree of intersecting and abutting Fractures should be captured from outcrops with accuracy to be of value as analogue.
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calibrating discrete Fracture Network models with a carbonate three dimensional outcrop Fracture Network implications for naturally Fractured reservoir modeling
AAPG Bulletin, 2014Co-Authors: K Bisdom, B D M Gauthier, G Bertotti, N J HardebolAbstract:Modeling naturally Fractured reservoirs requires a detailed understanding of the three-dimensional (3D) Fracture-Network characteristics, whereas generally only one-dimensional (1D) data, often suffering from sampling artifacts, are available as inputs for modeling. Additional Fracture properties can be derived from outcrop analogs with the scanline method, but it does not capture their full two-dimensional (2D) characteristics. We propose an improved workflow based on a 2D field-digitizing tool for mapping and analyzing Fracture parameters as well as relations to bedding. From Fracture data collected along 11 vertical surface outcrops in a quarry in southeast France, we quantify uncertainties in modeling Fracture Networks. The Fracture-frequency distribution fits a Gaussian distribution that we use to evaluate the intrinsic Fracture density variability within the quarry at different observation scales along well-analog scanlines. Excluding well length as a parameter, we find that 30 wells should be needed to fully (i.e., steady variance) capture the natural variability in Fracture spacing. This illustrates the challenge in trying to predict Fracture spacing in the subsurface from limited well data. Furthermore, for models with varying scanline orientations we find that Terzaghi-based spacing corrections fail when the required correction angle is more than 60°. We apply the 1D well analog data to calculate 3D Fracture frequency using stereological relations and find that these relations only work for cases in which the orientation distribution is accurately described, as results greatly vary with small changes in the orientation distribution.
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multi scale Fracture Network analysis from an outcrop analogue a case study from the cambro ordovician clastic succession in petra jordan
Marine and Petroleum Geology, 2012Co-Authors: Geertje Strijker, G Bertotti, Stefan M LuthiAbstract:Abstract A regional multi-scale Fracture Network is prominently exposed in the Cambro-Ordovician sedimentary succession in south-western Jordan. This succession consists of marine deposits, overlain by heterogeneous deltaic sediments, culminating in 500 m of massive to cross-bedded fluvial sandstones. A data set acquired from high-resolution satellite imagery and field measurements enables the quantification of the geometry and spatial characteristics of the Fracture Network in three dimensions. Five directional Fracture sets are identified from the satellite data with mean strikes of 000°, 040°, 065°, 120°, and 145°. Large Fracture zones (longer than 600 m), composed of tightly spaced joints confined in Fracture swarms, exhibit a log-normal trace-length distribution and the Fracture swarms are regularly spaced. The trace-length distribution of intermediate Fractures (40–600 m long) exhibits power-law characteristics and the Fractures are clustered, reflecting different Fracture system styles and stratigraphic controls as a function of scale. The small-scale Fracture Network is strongly dependent on the distribution of bedding plane discontinuities throughout different parts of the succession. The multi-scale Fracture Network is categorized in a three-tier hierarchical Fracture model that reflects underlying stratigraphic controls in the study area. This type of model can be used to improve the representation of Fracture Networks in fluid flow simulations of Fractured reservoirs with hybrid models that combine elements of discrete Fracture Networks and continuum models.
N J Hardebol - One of the best experts on this subject based on the ideXlab platform.
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multiscale Fracture Network characterization and impact on flow a case study on the latemar carbonate platform
Journal of Geophysical Research, 2015Co-Authors: N J Hardebol, G Bertotti, Christine Maier, Hamid Nick, Sebastian Geiger, Herman BoroAbstract:A Fracture Network arrangement is quantified across an isolated carbonate platform from outcrop and aerial imagery to address its impact on fluid flow. The Network is described in terms of Fracture density, orientation, and length distribution parameters. Of particular interest is the role of Fracture cross connections and abutments on the effective permeability. Hence, the flow simulations explicitly account for Network topology by adopting Discrete-Fracture-and-Matrix description. The interior of the Latemar carbonate platform (Dolomites, Italy) is taken as outcrop analogue for subsurface reservoirs of isolated carbonate build-ups that exhibit a Fracture-dominated permeability. New is our dual strategy to describe the Fracture Network both as deterministic- and stochastic-based inputs for flow simulations. The Fracture geometries are captured explicitly and form a multiscale data set by integration of interpretations from outcrops, airborne imagery, and lidar. The deterministic Network descriptions form the basis for descriptive rules that are diagnostic of the complex natural Fracture arrangement. The Fracture Networks exhibit a variable degree of multitier hierarchies with smaller-sized Fractures abutting against larger Fractures under both right and oblique angles. The influence of Network topology on connectivity is quantified using Discrete-Fracture-Single phase fluid flow simulations. The simulation results show that the effective permeability for the Fracture and matrix ensemble can be 50 to 400 times higher than the matrix permeability of 1.0 · 10−14 m2. The permeability enhancement is strongly controlled by the connectivity of the Fracture Network. Therefore, the degree of intersecting and abutting Fractures should be captured from outcrops with accuracy to be of value as analogue.
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calibrating discrete Fracture Network models with a carbonate three dimensional outcrop Fracture Network implications for naturally Fractured reservoir modeling
AAPG Bulletin, 2014Co-Authors: K Bisdom, B D M Gauthier, G Bertotti, N J HardebolAbstract:Modeling naturally Fractured reservoirs requires a detailed understanding of the three-dimensional (3D) Fracture-Network characteristics, whereas generally only one-dimensional (1D) data, often suffering from sampling artifacts, are available as inputs for modeling. Additional Fracture properties can be derived from outcrop analogs with the scanline method, but it does not capture their full two-dimensional (2D) characteristics. We propose an improved workflow based on a 2D field-digitizing tool for mapping and analyzing Fracture parameters as well as relations to bedding. From Fracture data collected along 11 vertical surface outcrops in a quarry in southeast France, we quantify uncertainties in modeling Fracture Networks. The Fracture-frequency distribution fits a Gaussian distribution that we use to evaluate the intrinsic Fracture density variability within the quarry at different observation scales along well-analog scanlines. Excluding well length as a parameter, we find that 30 wells should be needed to fully (i.e., steady variance) capture the natural variability in Fracture spacing. This illustrates the challenge in trying to predict Fracture spacing in the subsurface from limited well data. Furthermore, for models with varying scanline orientations we find that Terzaghi-based spacing corrections fail when the required correction angle is more than 60°. We apply the 1D well analog data to calculate 3D Fracture frequency using stereological relations and find that these relations only work for cases in which the orientation distribution is accurately described, as results greatly vary with small changes in the orientation distribution.
Gloria Arancibia - One of the best experts on this subject based on the ideXlab platform.
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Fracture Network fluid pathways and paleostress at the tolhuaca geothermal field
Journal of Structural Geology, 2017Co-Authors: Pamela Perezflores, Eugenio E Veloso, Jose Cembrano, Pablo Sanchezalfaro, Martin Lizama, Gloria ArancibiaAbstract:Abstract In this study, we examine the Fracture Network of the Tolhuaca geothermal system located in the Southern Andean volcanic zone that may have acted as a pathway for migration and ascent of deep-seated fluids under the far/local stress field conditions of the area. We collected the orientation, slip-data and mineralogical content of faults and veins recovered on a ca. 1000 m deep borehole (Tol-1) located in the NW-flank of the Tolhuaca volcano. Tol-1 is a non-oriented, vertical borehole that recovered relatively young ( 1 axis (083/74) and a subhorizontal, NS-trending σ 3 axis (184/03). Within the topmost 400 m of the borehole, faults and veins are randomly oriented, whereas below 400 m depth, faults and veins show preferential NE-to EW-strikes and steep (>50°) dips. The EW-striking veins are compatible with the calculated local stress field whereas NE-striking veins are compatible with the regional stress field, the morphological elongation of volcanic centers, alignments of flank vents and dikes orientation. Our results demonstrate that the paleomagnetic methodology proved to be reliable and it is useful to re-orient vertical boreholes such as Tol-1. Furthermore, our data show that the bulk transpressional regional stress field has local variations to a tensional stress field within the NE-striking fault zone belonging to the Liquine-Ofqui Fault System, favoring the activation of both NW- and NE-striking pre-existent discontinuities, especially the latter which are favorably oriented to open under the prevailing stress field. The vertical σ 1 and NS-trending subhorizontal σ 3 calculated in the TGS promote the activation of EW-striking extensional veins and both NE and NW-striking hybrid faults, constituting a complex fluid pathway geometry of at least one kilometer depth.
Herman Boro - One of the best experts on this subject based on the ideXlab platform.
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multiscale Fracture Network characterization and impact on flow a case study on the latemar carbonate platform
Journal of Geophysical Research, 2015Co-Authors: N J Hardebol, G Bertotti, Christine Maier, Hamid Nick, Sebastian Geiger, Herman BoroAbstract:A Fracture Network arrangement is quantified across an isolated carbonate platform from outcrop and aerial imagery to address its impact on fluid flow. The Network is described in terms of Fracture density, orientation, and length distribution parameters. Of particular interest is the role of Fracture cross connections and abutments on the effective permeability. Hence, the flow simulations explicitly account for Network topology by adopting Discrete-Fracture-and-Matrix description. The interior of the Latemar carbonate platform (Dolomites, Italy) is taken as outcrop analogue for subsurface reservoirs of isolated carbonate build-ups that exhibit a Fracture-dominated permeability. New is our dual strategy to describe the Fracture Network both as deterministic- and stochastic-based inputs for flow simulations. The Fracture geometries are captured explicitly and form a multiscale data set by integration of interpretations from outcrops, airborne imagery, and lidar. The deterministic Network descriptions form the basis for descriptive rules that are diagnostic of the complex natural Fracture arrangement. The Fracture Networks exhibit a variable degree of multitier hierarchies with smaller-sized Fractures abutting against larger Fractures under both right and oblique angles. The influence of Network topology on connectivity is quantified using Discrete-Fracture-Single phase fluid flow simulations. The simulation results show that the effective permeability for the Fracture and matrix ensemble can be 50 to 400 times higher than the matrix permeability of 1.0 · 10−14 m2. The permeability enhancement is strongly controlled by the connectivity of the Fracture Network. Therefore, the degree of intersecting and abutting Fractures should be captured from outcrops with accuracy to be of value as analogue.
Chuangbing Zhou - One of the best experts on this subject based on the ideXlab platform.
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effects of Fracture density roughness and percolation of Fracture Network on heat flow coupling in hot rock masses with embedded three dimensional Fracture Network
Geothermics, 2020Co-Authors: Chi Yao, Qinghui Jiang, Jianhua Yang, Yulong Shao, Fan Huang, Chuangbing ZhouAbstract:Abstract This paper presents a model to reveal the heat transfer mechanism and simulate the heat-flow coupling process in Fractured rock masses. Specifically, effects of Fracture density, roughness, and percolation on heat-flow coupling are investigated systematically. The Fractured rock masses are composed of a discrete Fracture Network and a rock matrix. Regarding the mesh discretisation for finite element analysis, the rock matrix is discretised into three-dimensional (3D) solid elements, whereas the discrete Fractures are modelled by zero-thickness elements. Fracture and matrix elements share the same nodes. Considering the effect of temperature on fluid density and dynamic viscosity, a heat-flow coupled model of Fractured rock masses is established with an embedded 3D Fracture Network. The reliability of the model is verified by comparing it with the analytical solution of a two-dimensional single-Fracture heat-flow coupling problem. The effects of Fracture density and diameter on percolation probability are studied based on Monte-Carlo tests with each group for 10,000 times. Finally, numerical samples of the 3D discrete Fracture Network with different geometric parameters are generated to characterise Fractured rock masses, and heat-flow coupling numerical simulation is conducted simultaneously. Results show that the percolation of the Fracture Network is the decisive factor affecting heat-flow coupling. The average outlet flow rate of the percolation Network under the same Fracture density is much larger than that of the nonpercolation Fracture Network, which results in a more rapid decrease in the outlet temperature. Other factors such as Fracture roughness are also investigated. It is discovered that the effect of Fracture roughness on heat-flow coupling is almost negligible for the nonpercolation Fracture Network model.
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A Novel Numerical Model for Fluid Flow in 3D Fractured Porous Media Based on an Equivalent Matrix-Fracture Network
Hindawi Limited, 2019Co-Authors: Chi Yao, Qinghui Jiang, Jianhua Yang, Jinsong Huang, Chuangbing ZhouAbstract:An original 3D numerical approach for fluid flow in Fractured porous media is proposed. The whole research domain is discretized by the Delaunay tetrahedron based on the concept of node saturation. Tetrahedral blocks are impermeable, and fluid only flows through the interconnected interfaces between blocks. Fractures and the porous matrix are replaced by the triangular interface Network, which is the so-called equivalent matrix-Fracture Network (EMFN). In this way, the three-dimensional seepage problem becomes a two-dimensional problem. The finite element method is used to solve the steady-state flow problem. The big finding is that the ratio of the macroconductivity of the whole interface Network to the local conductivity of an interface is linearly related to the cubic root of the number of nodes used for mesh generation. A formula is presented to describe this relationship. With this formula, we can make sure that the EMFN produces the same macroscopic hydraulic conductivity as the intact rock. The approach is applied in a series of numerical tests to demonstrate its efficiency. Effects of the hydraulic aperture of Fracture and connectivity of the Fracture Network on the effective hydraulic conductivity of Fractured rock masses are systematically investigated
