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A new Protocol ("DMX") is presented for 3d DFFN (Discrete Fault and Fracture Network) modelling, a numerical code developed over the last 20 years in order to converge towards a more realistic Discontinuity (fault and fracture) Network representation in space. The protocol introduces the following new features: Fracture interaction, truncation, termination and cross cutting in 3d space based on newly designed collision algorithms and fracture propagation principles; Modelling at any scale range of unlimited basic 3d fracture shapes, specific 3d fracture morphology, and 3d fracture aperture types; A complete integration between classical geological/geomechanical drivers such as stress ellipse, fault zones with 3d slip vectors, and different fold models (axial plane, fold axis and bedding orientation conditioning), geological assembly modelling such as joint spacing and set dependency, offset/faulting, and probabilistic conditioning of any of the parameters and drivers. Examples of the application of the protocol are presented to illustrate few of the unlimited amount of combinations that can be generated in 3d space. Furthermore, an example of the complete flow chart of a calibration to real observed cases is provided. The protocol constitutes a complete game change and opens a range of technological challenges for the future applications in Mining, Civil Engineering and Conventional and Unconventional Oil and Gas Exploration and Production.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in London, United Kingdom, 10-13 June 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract We have observed that pressure transient data gathered in most naturally fractured reservoirs tend not to exhibit the wellknown characteristic behavior, including pressure derivative, of the Warren and Root (1963) dual-porosity reservoir model. In reality, there are a rich variety of flow regimes dependent on the fracture distribution, spatial intensity and fracture conductivity. A semi-analytical solution for pressure transient behavior of fractured reservoirs has recently been presented that can be used to model the pressure response of formations with an arbitrary fracture distribution, density, and conductivity. The fractured system can be distributed discretely or continuously (network) with conductivities ranging from very low to infinite. Using the semi-analytical solution for fractured reservoirs, we perform a sensitivity analysis to identify which reservoir and geological parameters can be estimated from pressure transient test data collected from single or multiple well locations. We employ principal component analysis to explore the model parameterization as a pre-screening step.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In this paper, we present the interpretation of pressure transient well test data from discretely fractured reservoirs, where the fractures provide conduits for fluid flow and displacement, but where the fracture network is poorly connected. For this reason, dual porosity models such as Warren and Root's formulation are not usually applicable. We first outline the gaps in the existing pressure transient well test interpretation methodology for these reservoirs, then we introduce two new techniques developed to address these gaps: 1) a reservoir model-based inversion technique for the identification of spatial variation in reservoir parameters from pressure transient data, and 2) a boundary-element method for determining the pressure transient behavior of the reservoir with arbitrarily distributed finite and/or infinite conductivity vertical fractures. Using these two new techniques, we defined a new integrated interpretation methodology for reservoirs with discrete natural fractures and incorporating openhole log data, seismic, and the preliminary geological reservoir model. This is an important step in reconciling static and dynamic reservoir data to update the geological reservoir model with meaningful parameters.
The calculation of effective flow properties of naturally fractured reservoir (NFR) has been the purpose of research works for many years. Based on a static characterization of the fracture system (orientations and densities), equivalent flow properties provide continuum representations of discrete systems from which multiphase flows can be simulated using dual-permeability and dual-porosity models. Common flow properties include anisotropic permeability tensors attached to the fracture system itself, and block sizes or shape-factors, which characterize the capability of the fracture and matrix media, to exchange fluids.
Analytical and numerical calculation methods are now proposed by different commercial software tools, or have been the purpose of in-house developments. All methods rely on some conceptual models that are necessarily simplified representations of actual fracture systems, both complex and very partially known. Whether the underlying conceptual models are relevant certainly depends on the particular features of each fracture system. More important is the capability of models to capture features that are consequential for reservoir production. Only then can one expect to build meaningful NFR models likely to be calibrated to match production history data and to perform reliable reservoir forecasting. The CPU-time or memory requirements of implemented methods may also be a concern, as potentially relevant methods or software are unable to get through the calculations when full-field modelling is required.
It follows that the comparison and validation of equivalent flow-property calculation methods and NFR modelling software is anything but an easy task. As a first contribution to this end, we review and compare several equivalent permeability calculation methods available from two commercial software suites and from our own proprietary tool (GoFraK). We first present the numerical and analytical methods that were tested, including the original ones we developed which were expected to show better calculation and speed performances. We then detail the realistic benchmark case studies used to compare the different methods, from the calculation of equivalent flow properties to the multiphase flow simulation of forecast production.
The results are finally presented and discussed. They show that the numerical methods offered by commercial products, based on 3D discrete fracture networks (DFN) to compute equivalent permeability tensors, are generally unable to manage full-field models, and that their simpler analytical methods are to be used with great caution because of important underlying assumptions. These results also validate the approach and methods we developed in GoFraK and demonstrate their robustness and efficiency. Multiphase flow simulations were carried out to evaluate the impact of dual-media models on production forecast. They confirm that permeability tensors are not the only important effective flow properties, block sizes and more generally fracture/matrix transfer functions being also highly consequential. We finally end with preliminary conclusions about the ease of building NFR models and the reliability that can be given to such models.