Abstract:Summary
In fractured reservoirs, data directly related to fractures are scarce and 1D (e.g., core and image-log data). Other types of data are more widespread (e.g., seismic data) but generally are related only indirectly to fracture distribution. In such reservoirs, it is necessary to understand and then to model the fracture network on a field-wide scale by integrating all available data.
We propose a methodology to achieve this objective. The methodology establishes relationshi… Show more
“…Capturing Fracture-network Heterogeneity Using One-Dimensional Well Data Three-dimensional fracture networks generally display strong spatial heterogeneity, often linked to geological drivers, such as faults, folds, stress fields, lithological trends or bed thickness distributions (Gauthier et al, 2002b;Bourbiaux et al, 2002). These geological drivers impact the large-scale trends of fracture networks.…”
Section: Pitfalls In Two-dimensional Fracture-network Analysismentioning
confidence: 99%
“…Three-dimensional modeling of highly heterogeneous subsurface km-scale fractured reservoirs is a major challenge as usually only 1D well data are available, sometimes steered by geological drivers (Gauthier et al, 2002b). As our 3D DFN models are considered accurate representations of the fracture network within the quarry, we can use them to calibrate a similar subsurface NFR analog.…”
Section: Using Local Three-dimensional Discrete Fracture Network To mentioning
A B S T R A C TModeling 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 Kevin Bisdom holds a M.Sc. degree in petroleum engineering and geosciences from the Delft University of Technology, Netherlands. He is currently a Ph.D. candidate in the section of applied geology at the Delft University of Technology working on geomechanical and fluid flow modeling of fracture networks in folded subsurface structures using outcrop analogs in central Tunisia. is a senior geologist and geophysicist at Total. He is currently head of the naturally fractured reservoir (NFR) study team and scientific adviser for NFR operational and research and development projects. Bertrand holds a Ph.D. in structural geology from the Pierre and Marie Curie University of Paris and has 25 years of experience in the oil and gas industry with Shell and Total. received his master's degree at the University of Pisa (Italy) and the Ph.D. at the ETH-Zurich with a thesis on the tectonosedimentary evolution of the South-Alpine rifted margin. He was then at the VU Amsterdam studying passive margins and foredeep basins. Since 2010, he has been a professor for applied geology at the Delft University of Technology working mainly on fractured reservoirs.
“…Capturing Fracture-network Heterogeneity Using One-Dimensional Well Data Three-dimensional fracture networks generally display strong spatial heterogeneity, often linked to geological drivers, such as faults, folds, stress fields, lithological trends or bed thickness distributions (Gauthier et al, 2002b;Bourbiaux et al, 2002). These geological drivers impact the large-scale trends of fracture networks.…”
Section: Pitfalls In Two-dimensional Fracture-network Analysismentioning
confidence: 99%
“…Three-dimensional modeling of highly heterogeneous subsurface km-scale fractured reservoirs is a major challenge as usually only 1D well data are available, sometimes steered by geological drivers (Gauthier et al, 2002b). As our 3D DFN models are considered accurate representations of the fracture network within the quarry, we can use them to calibrate a similar subsurface NFR analog.…”
Section: Using Local Three-dimensional Discrete Fracture Network To mentioning
A B S T R A C TModeling 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 Kevin Bisdom holds a M.Sc. degree in petroleum engineering and geosciences from the Delft University of Technology, Netherlands. He is currently a Ph.D. candidate in the section of applied geology at the Delft University of Technology working on geomechanical and fluid flow modeling of fracture networks in folded subsurface structures using outcrop analogs in central Tunisia. is a senior geologist and geophysicist at Total. He is currently head of the naturally fractured reservoir (NFR) study team and scientific adviser for NFR operational and research and development projects. Bertrand holds a Ph.D. in structural geology from the Pierre and Marie Curie University of Paris and has 25 years of experience in the oil and gas industry with Shell and Total. received his master's degree at the University of Pisa (Italy) and the Ph.D. at the ETH-Zurich with a thesis on the tectonosedimentary evolution of the South-Alpine rifted margin. He was then at the VU Amsterdam studying passive margins and foredeep basins. Since 2010, he has been a professor for applied geology at the Delft University of Technology working mainly on fractured reservoirs.
“…Though fracturing should be related to geomechanical (strain and stress) conditions, fracture orientations, types and densities generally result from successive poorly known tectonic episodes, which are difficult to identify hence to model. Relating fracture densities to seismic attributes has also been the purpose of research work (Zheng 2006, Zeidouni & van Kruijsdijk 2006, Pearce 2003, Gauthier et al 2002c). If valuable information may be expected from seismic data, the availability of good quality seismic data must come along with specific processing algorithms to extract relevant attributes.…”
Section: Spe 107525mentioning
confidence: 99%
“…The spatial distribution of fracture densities being necessarily uncertain, a probabilistic approach should also be preferred, that relies on multivariate statistical analysis, for relating fracture density to explicative variables, and on geostatistics for addressing the spatial variability issue. Such an approach has been proposed by Gauthier et al (2002aGauthier et al ( , 2002bGauthier et al ( and 2002c where it proved efficient on different case-studies. It is the one presented later in this article.…”
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AbstractA large proportion of petroleum reservoirs is known to be naturally fractured with consequences on their flow behavior hence on reservoir performance. Though the modeling of such reservoirs has been the purpose of many research works, it remains a challenging task. Too simplistic reservoir models do not allow capturing essential features like large-scale fracturing trends, or non-linear multivariate relationships between the equivalent (generally anisotropic) permeability of the fracture system, and fracture densities and properties to be characterized on a directional fracture-set basis. Conversely, too complex reservoir models, intended to be more realistic, require computationally intensive and memory consuming algorithms. They also involve numerous parameters, a large part of which cannot be estimated from available data.In-between, there is a need for reasonably complex models and methods to generate them in a consistent way with various fracturing and dynamic data in order to produce conditional models. This paper presents such an approach, which has been developed as a workflow.The approach is based on an original conceptual model of fracture systems and a notion of scale-dependent effective properties. It is also a two-step modeling approach in which the fracture system is first characterized, then converted into equivalent flow properties for reservoir simulation purposes. Key aspects of the approach include the geostatistical modeling of fracture densities, scale-dependent calculation of equivalent within-layer horizontal permeability tensors based on spatially periodic discrete fracture networks, analytical calculations of vertical inter-layer permeabilities, and conditioning to well-test permeabilities by using steady-state flow-based evaluation of reservoir model responses. All these aspects rely on innovative and CPU-time efficient methods. They are introduced and illustrated by case-study results.
“…Several studies have focused on surface and subsurface fractures characterization in Algeria encompassing different methodologies and approaches (Gauthier et al, 2002;Guehria et al, 2005;Zazoun, 2008;Panien et al, 2010). The increasing interest in fractured reservoir modeling in Algeria is mainly due to the observations that well performances are strongly influenced by the presence of faults and fractures in the subsurface.…”
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