Kevin Bisdom

The impact of different aperture distribution models and critical stress criteria on equivalent permeability in fractured rocks

Predicting equivalent permeability in fractured reservoirs requires an understanding of the fracture network geometry and apertures. There are different methods for defining aperture, based on outcrop observations (power law scaling), fundamental mechanics (sublinear length-aperture scaling), and experiments (Barton-Bandis conductive shearing). Each method predicts heterogeneous apertures, even along single fractures (i.e., intrafracture variations), but most fractured reservoir models imply constant apertures for single fractures. We compare the relative differences in aperture and permeability predicted by three aperture methods, where permeability is modeled in explicit fracture networks with coupled fracture-matrix flow. Aperture varies along single fractures, and geomechanical relations are used to identify which fractures are critically stressed. The aperture models are applied to real-world large-scale fracture networks. (Sub)linear length scaling predicts the largest average aperture and equivalent permeability. Barton-Bandis aperture is smaller, predicting on average a sixfold increase compared to matrix permeability. Application of critical stress criteria results in a decrease in the fraction of open fractures. For the applied stress conditions, Coulomb predicts that 50% of the network is critically stressed, compared to 80% for Barton-Bandis peak shear. The impact of the fracture network on equivalent permeability depends on the matrix hydraulic properties, as in a low-permeable matrix, intrafracture connectivity, i.e., the opening along a single fracture, controls equivalent permeability, whereas for a more permeable matrix, absolute apertures have a larger impact. Quantification of fracture flow regimes using only the ratio of fracture versus matrix permeability is insufficient, as these regimes also depend on aperture variations within fractures.

Calibrating discrete fracture-network models with a carbonate three-dimensional outcrop fracture network: Implications for naturally fractured reservoir modeling

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.

A geometrically based method for predicting stress-induced fracture aperture and flow in discrete fracture networks

Modeling of fluid flow in naturally fractured reservoirs is often done through modeling and upscaling of discrete fracture networks (DFNs). The two-dimensional fracture geometry required for DFNs is obtained from subsurface and outcropping analog data. However, these data provide little information on subsurface fracture aperture, which is essential for quantifying porosity and permeability. Apertures are difficult to obtain from either outcropping or subsurface data and are therefore often based on fracture size or scaling relationships, but these do not consider the orientation and spatial distribution of fractures with respect to the in situ stress field. Using finite-element simulations, mechanical aperture can be modeled explicitly, but because changes in fracture geometry require renewed meshing and simulating, this approach is not easily integrated into subsurface DFN modeling workflows. We present a geometrically based method for calculating the shear-induced hydraulic aperture, that is, an aperture of up to 0.5 mm (0.02 in.) that can result from shear displacement along irregular fracture walls. The geometrically based method does not require numerical simulations, but it can instead be directly applied to DFNs using the fracture orientation and spacing distributions in combination with an estimate of the regional stress tensor and orientation. The frequency distribution of hydraulic aperture from the geometrically based method is compared with finite-element models constructed from five real fracture networks, digitized from outcropping pavements. These networks cover a wide range of possible geometries and spatial distributions. The geometrically based method predicts the average hydraulic aperture and equivalent permeability of fractured porous media with error margins of less than 5%.

An integrated workflow for stress and flow modelling using outcrop-derived discrete fracture networks

Fluid flow in naturally fractured reservoirs is often controlled by subseismic-scale fracture networks. Although the fracture network can be partly sampled in the direct vicinity of wells, the inter-well scale network is poorly constrained in fractured reservoir models. Outcrop analogues can provide data for populating domains of the reservoir model where no direct measurements are available. However, extracting relevant statistics from large outcrops representative of inter-well scale fracture networks remains challenging. Recent advances in outcrop imaging provide high-resolution datasets that can cover areas of several hundred by several hundred meters, i.e. the domain between adjacent wells, but even then, data from the high-resolution models is often upscaled to reservoir flow grids, resulting in loss of accuracy. We present a workflow that uses photorealistic georeferenced outcrop models to construct geomechanical and fluid flow models containing thousands of discrete fractures covering sufficiently large areas, that does not require upscaling to model permeability. This workflow seamlessly integrates geomechanical Finite Element models with flow models that take into account stress-sensitive fracture permeability and matrix flow to determine the full permeability tensor. The applicability of this workflow is illustrated using an outcropping carbonate pavement in the Potiguar basin in Brazil, from which 1082 fractures are digitised. The permeability tensor for a range of matrix permeabilities shows that conventional upscaling to effective grid properties leads to potential underestimation of the true permeability and the orientation of principal permeabilities. The presented workflow yields the full permeability tensor model of discrete fracture networks with stress-induced apertures, instead of relying on effective properties as most conventional flow models do. Display Omitted A new workflow for realistic discrete fracture-matrix flow models is proposed.Realistic fracture geometries are obtained from outcrops using photogrammetry.Aperture and permeability are calculated from geomechanical Finite Element models.The result is a permeability tensor for large-scale discrete fracture-matrix models.

Assessing the Validity and Limitations of Dual-porosity Models Using Geological Well Testing for Fractured Formations

Geological well testing is a valuable tool that allows us to improve understanding of pressure transient behaviour in a fractured reservoir. However, not all wells in a fractured reservoir will show pressure transients that are expected for NFRs. Our findings demonstrate that high resolution models with proper grid refinement around the wells and fractures are required to model pressure transient behaviour adequately and produce a physically meaningful wellbore response for a fractured reservoir. The key concept for interpreting well test data from fractured reservoirs is the dual-porosity model. This model, originally developed by Warren and Root (1963) has been the industry standard for modelling NFRs and interpreting well-test data from NFRs for more than 50 years. Although there are a number of factors impacting the exact shape of the pressure transients, our results suggest that observing the classical “V-shape” in the pressure derivative, as expected from a dual-porosity model may be an exception, rather than a rule in NFR, even for well-connected fracture networks. Our work quantifies when and why the assumptions inherent to the dual-porosity model break down when interpreting well-test data from NFR.

Predicting Multi-scale Deformation and Fluid Flow Patterns in Folds Using 3D Outcrop Models and Mechanical Modelling

Natural fracture patterns in folded carbonates are highly heterogeneous. The present-day fractures are often the result of pre-folding, syn-folding and post-folding related fractures. Furthermore, syn-folding fractures may differ in different domains of the fold. Although there are studies that characterize fracture patterns in outcropping folds, there is still a poor understanding of the relation between large-scale deformation (i.e. folding), and small-scale deformation (i.e. fractures), especially in terms of stresses and process-based predictions of fractures. Our overarching goal is to assess the sensitivity of reservoir-scale flow to different fracture patterns and different fracture properties. Therefore we build multi-scale models of 3D fracture networks in outcropping folds in the foothills of the Tunisian Atlas (central Tunisia). The fracture data is collected from outcrops using efficient methods that collect both fractures and the 3D geometry of the outcrops. We interpret small-scale deformation in terms of stresses and combine this with fold-scale mechanical models to predict the fracture patterns in 3D throughout the fold. The 3D model is used to model fracture fluid flow. This work presents a new approach to outcrop studies, that distinguishes different stages of fracturing and uses stresses to make predictions about fracture patterns in similar structures.

Analysing the limitations of the dual-porosity response during well-tests in naturally fractured reservoirs

Geological reservoirs can be extensively fractured but the well-test signatures observed in the wells may not show a pressure transient response that is representative of naturally fractured reservoirs (NFRs): for example, one that indicates two distinct pore systems (i.e. the mobile fractures and immobile matrix). Yet, the production behaviour may still be influenced by these fractures. To improve the exploitation of hydrocarbons from NFRs, we therefore need to improve our understanding of fluid-flow behaviour in fractures. Multiple techniques are used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the analysis of well-test data in order to interpret the flow behaviour in an NFR. An important concept for interpreting well-test data from an NFR is the theory of dual-porosity model. However, several studies pointed out that the dual-porosity model may not be appropriate for interpreting well tests from all fractured reservoirs. This paper therefore uses geological well-testing insights to explore the limitations of the characteristic flow behaviour inherent to the dual-porosity model in interpreting well-test data from Type II and III NFRs of Nelsons classification. To achieve this, we apply a geoengineering workflow with discrete fracture matrix (DFM) modelling techniques and unstructured-grid reservoir simulations to generate synthetic pressure transient data in both idealized fracture geometries and real fracture networks mapped in an outcrop of the Jandaira Formation. We also present key reservoir features that account for the classic V-shape pressure derivative response in NFRs. These include effects of fracture skin, a very tight matrix permeability and wells intersecting a minor, unconnected fracture close to a large fracture or fracture network. Our findings apply to both connected and disconnected fracture networks.

Using outcrop data for geological well test modelling in fractured reservoirs

Outcrop fracture data sets can now be acquired with ever more accuracy using drone technology augmented by field observations. These models can be used to form realistic, deterministic models of fractured reservoirs. Fractured well test models are traditionally seen to be finite or infinite conductivity or double porosity - corresponding the fractures with or without matrix support. Using this simple field outcrop based geometrical model to generate typical well test responses for wells either intersecting fractures or well nearby fractures shows that such responses can occur in sequence as part as a diagnostic signature of naturally fractured reservoirs.

A Geologically Consistent Permeability Model of Fractured Folded Carbonate Reservoirs : Lessons from Outcropping Analogue

Presently adopted fracture-related permeability models of large folded reservoirs are simplistic and often unrelated to the geological setting and evolution of the considered structure. In order to improve predictions of fluid flow in more complex subsurface fractured reservoirs, we build a 3D fracture network model of an outcropping fold in Tunisia, and populate different structural domains with fracture data, collected from outcrops. Within the studied fold, we find large variations in deformation mechanisms between different formations, with the main mechanisms being Layer Parallel Shortening (LPS), resulting in regional deformation, and the more localized impact of fiber stresses and flexural slip. Within the steep flank of the anticline, we find that in one formation fracturing is mostly controlled by fiber stresses, whereas in the underlying formation flexural slip is the main deformation mechanism. These two formations are separated by a detachment surface. Using stress and strain fields, we aim at reconstructing the conditions at which these fractures have been formed. This can provide a better understanding of the relation between fracture patterns in different structural domains of a fold and the stress evolution that formed these fractures, and the subsequent impact of different fracture patterns on fluid flow in fractured folds.

A new methodology to train fracture network simulation using Multiple Point Statistic

(1) Department of Geoscience and Engineering, Delft University of Technology, Delft, the Netherlands. 6 (2) Centre d’hydrogéologie et de géothermie (CHYN), Université de Neuchâtel, Emile-Argand 11, CH-2000 7 Neuchâtel. 8 (3) Department of Mechanical Engineering, Section of Energy Technology, Eindhoven University of 9 Technology, Eindhoven the Netherlands. 10 (4) Shell Global Solutions International B.V., Grasweg 31, 1031HWAmsterdam, The Netherlands 11 (5) University of Lausanne, Institute of Earth Surface Dynamics (IDYST) UNIL-Mouline, Geopolis, office 12 3337, 1015 Lausanne, Switzerland 13 (6) ENI Spa, Upstream and Technical Services, San Donato Milanese, Italy. 14 15 * Corresponding author, p.b.r.bruna@tudelft.nl 16 17