Streamline Tracing and Applications in Naturally Fractured Reservoirs Using Embedded Discrete Fracture Models

2018 ◽  
Author(s):  
Hongquan Chen ◽  
Tsubasa Onishi ◽  
Feyisayo Olalotiti-Lawal ◽  
Akhil Datta-Gupta
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Discrete Fracture ◽  
Naturally Fractured ◽  
Fracture Models ◽  
Streamline Tracing

scholarly journals Comparison of Flow Solutions for Naturally Fractured Reservoirs Using Complex Analysis Methods (CAM) and Embedded Discrete Fracture Models (EDFM): Fundamental Design Differences and Improved Scaling Method

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-20
Author(s):  
Aaditya Khanal ◽  
Ruud Weijermars
Keyword(s):  
Complex Analysis ◽  
Fractured Reservoirs ◽  
Fluid Velocity ◽  
Naturally Fractured Reservoirs ◽  
Natural Fractures ◽  
Flow Distortion ◽  
Cubic Equation ◽  
Analysis Methods ◽  
Discrete Fracture ◽  
Fracture Models

The present study compares flow paths in reservoirs with natural fractures, solved with Complex Analysis Methods (CAM), to those solved with Embedded Discrete Fracture Models (EDFM). One aim is to define scaling rules for the strength (flux) of the discrete natural fractures used in CAM models, which was previously theoretically defined based on the expected flow distortion. A major hurdle for quantitative benchmarks of CAM with EDFM results is that each of the two methods accounts for natural fractures with different assumptions and input parameters. For example, EDFM scales the permeability of the natural fractures based on a cubic equation, while CAM uses a flux strength. The results from CAM and EDFM are used to scale the flux strength of the natural fractures and improve the equivalent permeability contrast estimation for CAM. The permeability contrast for CAM is calculated from the ratio of the enhanced velocity inside natural fractures to the unperturbed matrix fluid velocity. A significant advantage of flow and pressure models based on CAM is the high resolution without complex gridding. Particle tracking results are presented for fractures with different hydraulic conductivity ranging from highly permeable to impervious.

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 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.

Tensor Analysis of the Relative Permeability in Naturally Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 162-184
Author(s):  
Mohammad H. Sedaghat ◽  
Siroos Azizmohammadi ◽  
Stephan K. Matthäi
Keyword(s):  
Relative Permeability ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Permeability Tensor ◽  
Absolute Permeability ◽  
Scalar Quantity ◽  
In Situ Conditions ◽  
Discrete Fracture ◽  
Naturally Fractured ◽  
The Absolute

Summary Fluid evidence shows that prediction of water breakthrough and oil recovery from fractured reservoirs cannot be performed accurately without upscaled relative permeability functions. Relative permeability is commonly assumed to be a scalar quantity, although the justification of that—specifically for naturally fractured reservoirs (NFRs)—is rarely attempted. In this study, we investigate the validity of this scalar-quantity assumption and how it affects fracture/matrix equivalent relative permeabilities, kri(Sw), achieved by a numerical simulation of unsteady-state waterflooding of discrete-fracture/matrix models (DFMs). Numerical determination of relative permeability requires a realistic model, a spatially adaptive simulation approach, and a sophisticated analysis procedure. To fulfil these requirements, we apply the discrete-fracture/matrix modeling to well-characterized outcrop analogs at the hectometer to kilometer scale. These models are parameterized with aperture and capillary entry pressure data, taking into account variations from fracture segment to segment, trying to emulate in-situ conditions. The finite-element-centered finite-volume method is used to simulate two-phase flow in the fractured rock, while also considering a range of wettability conditions from water-wet to oil-wet. Our results indicate that the fracture/matrix equivalent relative permeability is a weakly anisotropic property. The tensors are not necessarily symmetric, and the absolute-permeability tensor is the most influential factor, determining the level of anisotropy of kri. The anisotropy ratio (AR) changes with saturation, is influenced by the fracture/matrix-interface wetted area (Awf), and differs for each phase. In addition, the diagonal terms of the equivalent relative permeability tensor (krii), determined using our novel approach, can be different from those obtained using the assumption that kri is scalar. The magnitude of the difference is controlled by the absolute permeability, wettability, flow rate, and orientation of the fractures in the model. It is worth mentioning that the type and direction of imbibition can be determined by off-diagonal terms of the kri tensor. Furthermore, krii largely depends on the direction of the waterflood along the i-axis.

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