Modeling of Matrix/Fracture Transfer with Nonuniform-Block Distributions in Low-Permeability Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2653-2670 ◽  
Author(s):  
Didier–Yu Ding
Keyword(s):  
Shale Gas ◽  
Shape Factor ◽  
Oil Reservoirs ◽  
Dual Porosity ◽  
Tight Oil ◽  
Fracture Networks ◽  
Matrix Block ◽  
Matrix Fracture ◽  
Discrete Fracture ◽  
The Matrix

Summary Unconventional shale–gas and tight oil reservoirs are commonly naturally fractured, and developing these kinds of reservoirs requires stimulation by means of hydraulic fracturing to create conductive fluid–flow paths through open–fracture networks for practical exploitation. The presence of the multiscale–fracture network, including hydraulic fractures, stimulated and nonstimulated natural fractures, and microfractures, increases the complexity of the reservoir simulation. The matrix–block sizes are not uniform and can vary in a very wide range, from several tens of centimeters to meters. In such a reservoir, the matrix provides most of the pore volume for storage but makes only a small contribution to the global flow; the fracture supplies the flow, but with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix/fracture interaction. So, it is essential to accurately model the matrix/fracture transfers with a reservoir simulator. For the fluid–flow simulation in shale–gas and tight oil reservoirs, dual–porosity models are widely used. In a commonly used dual–porosity–reservoir simulator, fractures are homogenized from a discrete–fracture network, and a shape factor based on the homogenized–matrix–block size is applied to model the matrix/fracture transfer. Even for the embedded discrete–fracture model (EDFM), the matrix/fracture interaction is also commonly modeled using the dual–porosity concept with a constant shape factor (or matrix/fracture transmissibility). However, in real cases, the discrete–fracture networks are very complex and nonuniformly distributed. It is difficult to determine an equivalent shape factor to compute matrix/fracture transfer in a multiple–block system. So, a dual–porosity approach might not be accurate for the simulation of shale-gas and tight oil reservoirs because of the presence of complex multiscale–fracture networks. In this paper, we study the multiple–interacting–continua (MINC) method for flow modeling in fractured reservoirs. MINC is commonly considered as an improvement of the dual–porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always correctly handle the matrix/fracture transfers when the matrix–block sizes are not uniformly distributed. To overcome this insufficiency, some new approaches for the MINC subdivision and the transmissibility computations are presented in this paper. Several examples are presented to show that using the new approaches significantly improves the dual–porosity model and the standard MINC method for nonuniform–block–size distributions.

Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models

2002 ◽  
Vol 5 (02) ◽  
pp. 154-162 ◽  
Author(s):  
S. Sarda ◽  
L. Jeannin ◽  
R. Basquet ◽  
B. Bourbiaux
Keyword(s):  
Reservoir Simulation ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Dual Porosity ◽  
Fractured Reservoir ◽  
Fracture Networks ◽  
Matrix Fracture ◽  
Discrete Fracture ◽  
The Matrix

Summary Advanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However, these pictures must be validated against dynamic data like flowmeter, well-test, interference-test, or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of those dynamic tests. What has to be overcome is the challenge of both accurately representing large and complex fracture networks and simulating matrix/ fracture exchanges with a minimum number of gridblocks. This paper presents an efficient, patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists of developing an optimized, explicit representation of the fractured medium and specific treatments of matrix/fracture exchanges and matrix/matrix flows. In this approach, matrix blocks of different volumes and shapes are associated with each fracture cell depending on the local geometry of the surrounding fractures. The matrix-block geometry is determined with a rapid image-processing algorithm. The great advantage of this approach is that it can simulate local matrix/fracture exchanges on large fractured media in a much faster and more appropriate way. Indeed, the simulation can be carried out with a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages owing to its great flexibility. Indeed, it accurately handles the cases in which flows are not controlled by fractures alone; either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well-test cases demonstrate the reliability of the method and its range of application. Introduction In recent years, numerous research programs have been focusing on the topic of fractured reservoirs. Major advances were made, and oil companies now benefit from efficient methodologies, tools, and software for fractured reservoir studies. Nowadays, a study of a fractured reservoir, from fracture detection to full-field simulation, includes the following main steps: geological fracture characterization, hydraulic characterization of fractures, upscaling of fracture properties, and fractured reservoir simulation. Research on fractured reservoir simulation has a long history. In the early 1960s, Barenblatt and Zheltov1 first introduced the dual-porosity concept, followed by Warren and Root,2 who proposed a simplified representation of fracture networks to be used in dual-porosity simulators. Based on this concept, reservoir simulators3 are now able to correctly reproduce the main driving mechanisms occurring in fractured reservoirs, such as water imbibition, gas/oil and water/oil gravity drainage, molecular diffusion, and convection in fractures. Even single-medium simulators can perform fractured reservoir simulation when adequate pseudocapillary pressure curves and pseudorelative permeability curves can be input. Indeed, except for particular cases such as thermal recovery processes, full-field simulation of fractured reservoirs is no longer a problem. Geological characterization of fractures progressed considerably in the 1990s. The challenge was to analyze and integrate all the available fracture data to provide a reliable description of the fracture network both at field scale and at local reservoir cell scale. Tools have been developed for merging seismic, borehole imaging, lithological, and outcrop data together with the help of geological and geomechanical rules.3 These tools benefited from the progress of seismic acquisition and borehole imaging. Indeed, accurate seismic data lead to reliable models of large-scale fracture networks, and borehole imaging gives the actual fracture description along the wells, which enables a reliable statistical determination of fracture attributes. Finally, these tools provide realistic pictures of fracture networks. They are applied successfully in numerous fractured-reservoir studies. The upscaling of fracture properties is the problem of translating the geological description of fracture networks into reservoir simulation parameters. Two approaches are possible. In the first one, the fractured reservoir is considered as a very heterogeneous matrix reservoir; therefore, one applies the classical techniques available for heterogeneous single-medium upscaling. The second approach is based on the dual-porosity concept and consists of upscaling the matrix and the fracture separately. Based on this second approach, methodologies and software were developed in the 1990s to calculate equivalent fracture parameters with respect to the dual-porosity concept (i.e., a fracture-permeability tensor with main flow directions and anisotropy and a shape factor that controls the matrix/fracture exchange kinetics3–5). For a given reservoir grid cell, the upscaling procedures consist of generating the corresponding 3D discrete fracture network and computing the equivalent parameters from this network. In particular, the permeability tensor is computed from the results of steady-state flow simulations in the discrete fracture network alone (without the matrix).

Upscaling Discrete Fracture Characterizations to Dual-Porosity, Dual-Permeability Models for Efficient Simulation of Flow With Strong Gravitational Effects

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 58-67 ◽  
Author(s):  
Bin Gong ◽  
Mohammad Karimi-Fard ◽  
Louis J. Durlofsky
Keyword(s):  
Shape Factor ◽  
Fractured Reservoirs ◽  
Fracture Model ◽  
Dual Porosity ◽  
Scale Model ◽  
Permeability Model ◽  
Gravitational Effects ◽  
Discrete Fracture Model ◽  
Discrete Fracture ◽  
The Matrix

Summary The geological complexity of fractured reservoirs requires the use of simplified models for flow simulation. This is often addressed in practice by using flow modeling procedures based on the dual-porosity, dual-permeability concept. However, in most existing approaches, there is not a systematic and quantitative link between the underlying geological model [in this case, a discrete fracture model (DFM)] and the parameters appearing in the flow model. In this work, a systematic upscaling procedure is presented to construct a dual-porosity, dual-permeability model from detailed discrete fracture characterizations. The technique, referred to as a multiple subregion (MSR) model, represents an extension of an earlier method that did not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus account for the fracture distribution and can represent accurately the matrix-matrix and matrix-fracture transfer. The matrix subregions are connected to matrices in vertically adjacent blocks (as in a dual-permeability model) to capture phase segregation caused by gravity. Two-block problems are solved to provide fracture-fracture flow effects. All connections in the coarse-scale model are characterized in terms of upscaled transmissibilities, and the resulting coarse model can be used with any connectivity-based reservoir simulator. The method is applied to simulate 2D and 3D fracture models, with viscous, gravitational, and capillary pressure effects, and is shown to provide results in close agreement with the underlying DFM. Speedups of approximately a factor of 120 are observed for a complex 3D example. Introduction The accurate simulation of fractured reservoirs remains a significant challenge. Although improvements in many technical areas are required to enable reliable predictions, there is a clear need for procedures that provide accurate and efficient flow models from highly resolved geological characterizations. These geological descriptions are often in the form of discrete fracture representations, which are generally too detailed for direct use in reservoir simulation. Dual-porosity modeling is the standard simulation technique for flow prediction of fractured reservoirs. This model was first proposed by Barenblatt and Zheltov (1960) and introduced to the petroleum industry by Warren and Root (1963). The key aspect of this approach is to separate the flow through the fractures from the flow inside the matrix. The reservoir model is represented by two overlapping continua—one continuum to represent the fracture network, where the main flow occurs, and another continuum to represent the matrix, which acts as a source for the fracture continuum. The interaction between these two continua is modeled through a transfer function, also called the shape factor. Though very useful, the model is quite simple in that the geological and flow complexity is reduced to a single parameter, the shape factor. This parameter is in general different for each gridblock depending on the underlying geology and the type of flow.

Coupled Effect of Imbibition Capillary Pressure and Matrix-Fracture Transfer on Oil Recovery from Dual-Permeability Reservoirs

2021 ◽  
Author(s):  
Aymen AlRamadhan ◽  
Yildiray Cinar ◽  
Arshad Hussain ◽  
Nader BuKhamseen
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Shape Factor ◽  
Numerical Study ◽  
Fractured Reservoirs ◽  
Matrix Block ◽  
Matrix Fracture ◽  
The Matrix ◽  
The Impact

Abstract This paper presents a numerical study to examine how the interplay between the matrix imbibition capillary pressure (Pci) and matrix-fracture transfer affects oil recovery from naturally-fractured reservoirs under waterflooding. We use a dual-porosity, dual-permeability (DPDP) finite difference simulator to investigate the impact of uncertainties in Pci on the waterflood recovery behavior and matrix-fracture transfer. A comprehensive assessment of the factors that control the matrix-fracture transfer, namely Pci, gravity forces, shape factor and fracture-matrix permeabilities is presented. We examine how the use of Pci curves in reservoir simulation can affect the recovery assessment. We present two conceptual scenarios to demonstrate the impact of spontaneous and forced imbibition on the flood-front movement, waterflood recovery processes, and ultimate recovery in the DPDP reservoir systems of varying reservoir quality. The results demonstrate that the inclusion of Pci in reservoir simulation delays the breakthrough time due to a higher displacement efficiency. The study reveals that the matrix-fracture transfer is mainly controlled by the fracture surface area, fracture permeability, shape factor, and the uncertainty in Pci. We underline a discrepancy among various shape factors proposed in the literature due to three main factors: (1) the variations in matrix-block geometries considered, (2) how the physics of imbibition forces that control the multiphase fluid transfer is captured, and (3) how the assumption of pseudo steady-state flow is addressed.

scholarly journals Modeling of transient shape factor in fractured reservoirs considering the effect of heterogeneity, pressure-dependent properties and quadratic pressure gradient

2019 ◽  
Vol 74 ◽  
pp. 89
Author(s):  
Mahdi Abbasi ◽  
Alireza Kazemi ◽  
Mohammad Sharifi
Keyword(s):  
Pressure Gradient ◽  
Shape Factor ◽  
Fractured Reservoirs ◽  
Dual Porosity ◽  
Rock Properties ◽  
High Porosity ◽  
Matrix Block ◽  
Dual Porosity Model ◽  
The Matrix ◽  
Porosity Model

Fractured reservoirs contain most of the oil in the world’s reserves. The existence of two systems of matrix and fracture with completely different characteristics has caused the modeling of the mechanisms of fractured reservoirs to be more complex than conventional ones. Modeling of this type of reservoirs is possible using two methods of single and dual porosity model. Modeling via single porosity scheme is very time-consuming as it takes into account huge matrix blocks (low permeability and high porosity) and small fractures (high permeability and low porosity) alongside each other explicitly. The dual porosity model, however, attempts to solve this problem using the concept of shape factor, which is defined as the amount of fluid transferred from the matrix to the fracture. The shape factor coefficients expressed so far have been derived via simplifying assumptions which keep them away from real conditions prevailing in fractured reservoirs. In this paper, shape factor is calculated more realistically with consideration of the quadratic pressure gradient in the diffusivity equation, the heterogeneity of the matrix block and the change of the rock properties by pressure change. For these three cases, the analytical modeling of the flow of fluid from the matrix to the fracture system has been discussed and its results with previous models have been compared. In addition, the dependence of shape factor on the stated parameters was evaluated and in order to validate the results of the proposed analytical model, its results were compared with the results of a commercial simulator. Investigating the shape factor with the assumptions about the physics of the fractured reservoirs will improve our understanding of the fluid transfer between the matrix and the fracture, and this capability will allow numerical and commercial simulators to predict the behavior of fractured reservoirs more accurately.

An analysis of stochastic discrete fracture networks on shale gas recovery

2018 ◽  
Vol 167 ◽  
pp. 78-87 ◽  
Author(s):  
Linkai Li ◽  
Hanqiao Jiang ◽  
Junjian Li ◽  
Keliu Wu ◽  
Fanle Meng ◽  
...  
Keyword(s):  
Shale Gas ◽  
Fracture Networks ◽  
Gas Recovery ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

scholarly journals An Integrally Embedded Discrete Fracture Model for Flow Simulation in Anisotropic Formations

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3070
Author(s):  
Renjie Shao ◽  
Yuan Di ◽  
Dawei Wu ◽  
Yu-Shu Wu
Keyword(s):  
Flow Simulation ◽  
Fracture Model ◽  
Fluid Exchange ◽  
Two Phase ◽  
Fine Grid ◽  
Discrete Fracture Model ◽  
Matrix Fracture ◽  
Discrete Fracture ◽  
The Matrix ◽  
Anisotropic Formation

The embedded discrete fracture model (EDFM), among different flow simulation models, achieves a good balance between efficiency and accuracy. In the EDFM, micro-scale fractures that cannot be characterized individually need to be homogenized into the matrix, which may bring anisotropy into the matrix. However, the simplified matrix–fracture fluid exchange assumption makes it difficult for EDFM to address the anisotropic flow. In this paper, an integrally embedded discrete fracture model (iEDFM) suitable for anisotropic formations is proposed. Structured mesh is employed for the anisotropic matrix, and the fracture element, which consists of a group of connected fractures, is integrally embedded in the matrix grid. An analytic pressure distribution is derived for the point source in anisotropic formation expressed by permeability tensor, and applied to the matrix–fracture transmissibility calculation. Two case studies were conducted and compared with the analytic solution or fine grid result to demonstrate the advantage and applicability of iEDFM to address anisotropic formation. In addition, a two-phase flow example with a reported dataset was studied to analyze the effect of the matrix anisotropy on the simulation result, which also showed the feasibility of iEDFM to address anisotropic formation with complex fracture networks.

Development of an Embedded Discrete Fracture Model for Multi-Phase Flow in Fractured Reservoir

2014 ◽  
Vol 668-669 ◽  
pp. 1488-1492
Author(s):  
Fang Qi Zhou
Keyword(s):  
Neumann Boundary ◽  
Fracture Model ◽  
Fractured Reservoir ◽  
Discrete Fracture Model ◽  
Matrix Fracture ◽  
Discrete Fracture ◽  
The Matrix ◽  
Multi Phase Flow ◽  
Multi Phase ◽  
Fracture Interface

Considering the discontinuities of the phase saturations and pressure gradients at the matrix-fracture interface, a modified algorithm for the embedded discrete fracture model is proposed. In this algorithm, the exchange rate between fracture and matrix on two sides of the interface are calculated separately. To avoid the problem for defining the physical variables on the matrix grid blocks overlaid by fracture, the Neumann boundary conditions are instead in the calculations of other matrix grid blocks. The numerical examples show that the simulation results of the proposed algorithm agree very well with those of the discrete fracture model. In reservoir with high matrix capillary pressure, the grids must be enough refined in the neighborhood of the matrix-fracture interface to achieve high numerical accuracy.

Simulation Of Dual-Porosity Flow In Discrete Fracture Networks

1990 ◽  
Author(s):  
T.W. Doe ◽  
M. Uchida ◽  
J.S. Kindred ◽  
W.S. Dershowitz
Keyword(s):  
Dual Porosity ◽  
Fracture Networks ◽  
Discrete Fracture Networks ◽  
Discrete Fracture
Sign in / Sign up

Export Citation Format

Share Document