scholarly journals Impact of Fracture Topology on the Fluid Flow Behavior of Naturally Fractured Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (17) ◽  
pp. 5488
Author(s):  
Leidy Laura Alvarez ◽  
Leonardo José do Nascimento Guimarães ◽  
Igor Fernandes Gomes ◽  
Leila Beserra ◽  
Leonardo Cabral Pereira ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Numerical Simulations ◽  
Shape Factor ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Discrete Fracture Network ◽  
Naturally Fractured Reservoirs ◽  
Equivalent Permeability ◽  
Discrete Fracture ◽  
Naturally Fractured

Fluid flow modeling of naturally fractured reservoirs remains a challenge because of the complex nature of fracture systems controlled by various chemical and physical phenomena. A discrete fracture network (DFN) model represents an approach to capturing the relationship of fractures in a fracture system. Topology represents the connectivity aspect of the fracture planes, which have a fundamental role in flow simulation in geomaterials involving fractures and the rock matrix. Therefore, one of the most-used methods to treat fractured reservoirs is the double porosity-double permeability model. This approach requires the shape factor calculation, a key parameter used to determine the effects of coupled fracture-matrix fluid flow on the mass transfer between different domains. This paper presents a numerical investigation that aimed to evaluate the impact of fracture topology on the shape factor and equivalent permeability through hydraulic connectivity (f). This study was based on numerical simulations of flow performed in discrete fracture network (DFN) models embedded in finite element meshes (FEM). Modeled cases represent four hypothetical examples of fractured media and three real scenarios extracted from a Brazilian pre-salt carbonate reservoir model. We have compared the results of the numerical simulations with data obtained using Oda’s analytical model and Oda’s correction approach, considering the hydraulic connectivity f. The simulations showed that the equivalent permeability and the shape factor are strongly influenced by the hydraulic connectivity (f) in synthetic scenarios for X and Y-node topological patterns, which showed the higher value for f (0.81) and more expressive values for upscaled permeability (kx-node = 0.1151 and ky-node = 0.1153) and shape factor (25.6 and 14.5), respectively. We have shown that the analytical methods are not efficient for estimating the equivalent permeability of the fractured medium, including when these methods were corrected using topological aspects.

scholarly journals Development of an Efficient Embedded Discrete Fracture Model for 3D Compositional Reservoir Simulation in Fractured Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 19 (02) ◽  
pp. 289-303 ◽  
Author(s):  
Ali Moinfar ◽  
Abdoljalil Varavei ◽  
Kamy Sepehrnoori ◽  
Russell T. Johns
Keyword(s):  
Fluid Flow ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Fracture Model ◽  
Continuum Models ◽  
Fine Grid ◽  
Discrete Fracture Model ◽  
Discrete Fracture ◽  
Naturally Fractured

Summary Many naturally fractured reservoirs around the world have depleted significantly, and improved-oil-recovery (IOR) processes are necessary for further development. Hence, the modeling of fractured reservoirs has received increased attention recently. Accurate modeling and simulation of naturally fractured reservoirs (NFRs) is still challenging because of permeability anisotropies and contrasts. Nonphysical abstractions inherent in conventional dual-porosity and dual-permeability models make them inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent technologies for discrete fracture modeling may suffer from large simulation run times, and the industry has not used such approaches widely, even though they give more-accurate representations of fractured reservoirs than dual-continuum models. We developed an embedded discrete fracture model (DFM) for an in-house compositional reservoir simulator that borrows the dual-medium concept from conventional dual-continuum models and also incorporates the effect of each fracture explicitly. The model is compatible with existing finite-difference reservoir simulators. In contrast to dual-continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity of a typical NFR. The accuracy of the embedded DFM is confirmed by comparing the results with the fine-grid, explicit-fracture simulations for a case study including orthogonal fractures and a case with a nonaligned fracture. We also perform a grid-sensitivity study to show the convergence of the method as the grid is refined. Our simulations indicate that to achieve accurate results, the embedded discrete fracture model may only require moderate mesh refinement around the fractures and hence offers a computationally efficient approach. Furthermore, examples of waterflooding, gas injection, and primary depletion are presented to demonstrate the performance and applicability of the developed method for simulating fluid flow in NFRs.

scholarly journals Enhancing fracture-network characterization and discrete-fracture-network simulation with high-resolution surveys using unmanned aerial vehicles

2020 ◽  
Vol 28 (7) ◽  
pp. 2285-2302
Author(s):  
Mahawa Essa Mabossani Akara ◽  
Donald M. Reeves ◽  
Rishi Parashar
Keyword(s):  
Fluid Flow ◽  
Fracture Network ◽  
Pumping Test ◽  
Discrete Fracture Network ◽  
Granitic Rocks ◽  
Equivalent Permeability ◽  
Fracture Length ◽  
Discrete Fracture ◽  
Network Scale ◽  
Aperture Scaling

Abstract A workflow is presented that integrates unmanned aerial vehicle (UAV) imagery with discrete fracture network (DFN) geometric characterization and quantification of fluid flow. The DFN analysis allows for reliable characterization and reproduction of the most relevant features of fracture networks, including: identification of orientation sets and their characteristics (mean orientation, dispersion, and prior probability); scale invariance in distributions of fracture length and spatial location/clustering; and the distribution of aperture values used to compute network-scale equivalent permeability. A two-dimensional DFN-generation approach honors field data by explicitly reproducing observed multi-scale fracture clustering using a multiplicative cascade process and power law distribution of fracture length. The influence of aperture on network-scale equivalent permeability is investigated using comparisons between a sublinear aperture-to-length relationship and constant aperture. To assess the applicability of the developed methodology, DFN flow simulations are calibrated to pumping test data. Results suggest that even at small scales, UAV surveys capture the essential geometrical properties required for fluid flow characterization. Both the constant and sublinear aperture scaling approaches provide good matches to the pumping test results with only minimal calibration, indicating that the reproduced networks sufficiently capture the geometric and connectivity properties characteristic of the granitic rocks at the study site. The sublinear aperture scaling case honors the directions of dominant fractures that play a critical role in connecting fracture clusters and provides a realistic representation of network permeability.

Estimation of Fracture Porosity of Naturally Fractured Reservoirs With No Matrix Porosity Using Fractal Discrete Fracture Networks

2009 ◽  
Vol 12 (02) ◽  
pp. 232-242 ◽  
Author(s):  
Tae H. Kim ◽  
David S. Schechter
Keyword(s):  
Fractured Reservoirs ◽  
Fracture Network ◽  
Naturally Fractured Reservoirs ◽  
Fracture Aperture ◽  
Fracture Networks ◽  
Fracture Porosity ◽  
Fracture Systems ◽  
Discrete Fracture ◽  
Naturally Fractured ◽  
Matrix Porosity

Summary Matrix porosity is relatively easy to measure and estimate compared to fracture porosity. On the other hand, fracture porosity is highly heterogeneous and very difficult to measure and estimate. When matrix porosity of naturally fractured reservoirs (NFRs) is negligible, it is very important to know fracture porosity to evaluate reservoir performance. Because fracture porosity is highly uncertain, fractal discrete fracture network (FDFN) generation codes were developed to estimate fracture porosity. To reflect scale-dependent characteristics of fracture networks, fractal theories are adopted. FDFN modeling technique enables the systematic use of data obtained from image log and core analysis for estimating fracture porosity. As a result, each fracture has its own fracture aperture distribution, so that generated FDFN are similar to actual fracture systems. The results of this research will contribute to properly evaluating the fracture porosity of NFR where matrix porosity is negligible.

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