Improved Calculations for Viscous and Gravity Displacement in Matrix Blocks in Dual-Porosity Simulators (includes associated papers 17851, 17921, 18017, 18018, 18939, 19038, 19361 and 20174 )

1988 ◽  
Vol 40 (01) ◽  
pp. 60-70 ◽  
Author(s):  
J.R. Gilman ◽  
H. Kazemi
Keyword(s):  
Dual Porosity ◽  
Matrix Blocks

Gravity-Drainage and Oil-Reinfiltration Modeling in Naturally Fractured Reservoir Simulation

2009 ◽  
Vol 12 (03) ◽  
pp. 380-389 ◽  
Author(s):  
Juan Ernesto Ladron de Guevara-Torres ◽  
Fernando Rodriguez-de la Garza ◽  
Agustin Galindo-Nava
Keyword(s):  
Reservoir Simulation ◽  
Fractured Reservoirs ◽  
Dual Porosity ◽  
Gravity Drainage ◽  
Fractured Reservoir ◽  
Fluid Exchange ◽  
Production Forecast ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
Refined Grid

Summary The gravity-drainage and oil-reinfiltration processes that occur in the gas-cap zone of naturally fractured reservoirs (NFRs) are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in the presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results. Gravity-drainage and oil-reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudofunctions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in the fractured reservoir simulation. The modified dual-porosity equations were implemented in SIMPUMA-FRAC (Galindo-Nava 1998; Galindo-Nava et al. 1998), and solutions were verified with good results against those obtained from the equivalent single porosity refined grid simulations. The same simulations--considering gravity drainage and oil reinfiltration processes--were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC. Introduction One of the most important aspects in the numerical simulation of fractured reservoirs is the description of the processes that occur during the rock-matrix/fracture fluid exchange and the connection with the fractured network. This description was initially done in a simplified manner and therefore incomplete (Gilman and Kazemi 1988; Saidi and Sakthikumar 1993). Experiments and theoretical and numerical studies (Saidi and Sakthikumar 1993; Horie et al. 1998; Tan and Firoozabadi 1990; Coats 1989) have allowed to understand that there are mechanisms and processes, such as oil reinfiltritation or oil imbibition and capillary continuity between matrix blocks, that were not taken into account with sufficient detail in the original dual-porosity formulations to model them properly and that modify significantly the oil-production forecast and the ultimate recovery in an NFR. The main idea of this paper is to study in further detail the oil reinfiltration process that occurs in the gas invaded zone (gas cap zone) in an NFR and to evaluate its modeling to implement it in a dual-porosity numerical simulator.

A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 670-684 ◽  
Author(s):  
S.. Geiger ◽  
M.. Dentz ◽  
I.. Neuweiler
Keyword(s):  
Fractured Reservoirs ◽  
Dual Porosity ◽  
Transfer Rates ◽  
Wide Range ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
Dual Porosity Model ◽  
The Matrix ◽  
Water Cut ◽  
Porosity Model

Summary A major part of the world's remaining oil reserves is in fractured carbonate reservoirs, which are dual-porosity (fracture-matrix) or multiporosity (fracture/vug/matrix) in nature. Fractured reservoirs suffer from poor recovery, high water cut, and generally low performance. They are modeled commonly by use of a dual-porosity approach, which assumes that the high-permeability fractures are mobile and low-permeability matrix is immobile. A single transfer function models the rate at which hydrocarbons migrate from the matrix into the fractures. As shown in many numerical, laboratory, and field experiments, a wide range of transfer rates occurs between the immobile matrix and mobile fractures. These arise, for example, from the different sizes of matrix blocks (yielding a distribution of shape factors), different porosity types, or the inhomogeneous distribution of saturations in the matrix blocks. Thus, accurate models are needed that capture all the transfer rates between immobile matrix and mobile fracture domains, particularly to predict late-time recovery more reliably when the water cut is already high. In this work, we propose a novel multi-rate mass-transfer (MRMT) model for two-phase flow, which accounts for viscous-dominated flow in the fracture domain and capillary flow in the matrix domain. It extends the classical (i.e., single-rate) dual-porosity model to allow us to simulate the wide range of transfer rates occurring in naturally fractured multiporosity rocks. We demonstrate, by use of numerical simulations of waterflooding in naturally fractured rock masses at the gridblock scale, that our MRMT model matches the observed recovery curves more accurately compared with the classical dual-porosity model. We further discuss how our multi-rate dual-porosity model can be parameterized in a predictive manner and how the model could be used to complement traditional commercial reservoir-simulation workflows.

Material-Balance Method for Dual-Porosity Reservoirs With Recovery Curves To Model the Matrix/Fracture Transfer

2015 ◽  
Vol 18 (02) ◽  
pp. 171-186 ◽  
Author(s):  
Georg M. Mittermeir
Keyword(s):  
Material Balance ◽  
Dual Porosity ◽  
Reservoir Pressure ◽  
Full Field ◽  
Recovery Curves ◽  
Matrix Fracture ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
The Matrix ◽  
Two Parameters

Summary This paper presents a material-balance (MB) method applicable to naturally fractured dual-porosity reservoirs by considering the matrix/fracture transfer. The method is based on the recognition that the performance of water and gas displacement from matrix blocks can be depicted in the form of recovery factor vs. time. These recovery curves determine the matrix/fracture oil transfer. The reservoir pressure change depends on the original fluids in place and the strength of the aquifer. Thus, a close relationship between the recovery curves and the observed reservoir state (e.g., pressure, position of the phase contacts, water cut, and gas/oil ratio), the aquifer parameters, and the matrix/fracture oil transfer exists. Concerning the matrix blocks, the surrounding fracture continuum sets the boundary conditions by acting as an injector. The injection rates are predefined by the provided recovery curves, which one can obtain with different methods. They can be calculated by fine-scale single matrix-block models (Pirker et al. 2007), derived from conventional full-field numerical models, measured in a laboratory autoclave (Mattax and Kyte 1962), or determined by theoretical means (Davis and Hill 1982). The recovery curves can be scaled and normalized, making them applicable within a certain rock type to a wide range of rock parameters, namely shape factor, permeability, and porosity (Amiry 2014). While in a full-field model, various rock types can be identified; in MB calculations, however, they must be reduced to a single rock type. MB calculations—irrespective of conventional single-porosity methods or the herein-presented approach for dual-porosity naturally fractured reservoirs—are always conducted on a homogenized reservoir model. Therefore, variations in rock and pressure/volume/temperature properties cannot be taken into account. The recovery process is governed by two parameters—the asymptotic value of the recovery function and the time-scaling factor. These two parameters can be used for matching the observed reservoir performance. The new MB method matches both the reservoir pressure and the positions of the phase contacts. It also provides aquifer and matrix/fracture fluid-transfer models. Applying the parameters of those models in prediction mode and assuming a future production strategy, reservoir-pressure decline and phase-contact movements can be forecasted. The paper presents the calculation schema and the successful application to a field with more than 500 million STB of original oil in place and a 35-year production history. For the first time, it becomes possible to realistically—this means by fully considering the governing recovery mechanisms and thus the matrix/fracture transfer—calculate MB for naturally fractured dual-porosity reservoirs.

A Fully Implicit, Compositional, Parallel Simulator for IOR Processes in Fractured Reservoirs

SPE Journal ◽  
2007 ◽  
Vol 12 (03) ◽  
pp. 367-381 ◽  
Author(s):  
Reza Naimi-Tajdar ◽  
Choongyong Han ◽  
Kamy Sepehrnoori ◽  
Todd James Arbogast ◽  
Mark A. Miller
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Fractured Reservoir ◽  
Matrix Fracture ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
Dual Porosity Model ◽  
The Matrix ◽  
Porosity Model

Summary Naturally fractured reservoirs contain a significant amount of the world oil reserves. A number of these reservoirs contain several billion barrels of oil. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Parallel reservoir simulators developed for naturally fractured reservoirs can effectively address the computational problem. A new accurate parallel simulator for large-scale naturally fractured reservoirs, capable of modeling fluid flow in both rock matrix and fractures, has been developed. The simulator is a parallel, 3D, fully implicit, equation-of-state compositional model that solves very large, sparse linear systems arising from discretization of the governing partial differential equations. A generalized dual-porosity model, the multiple-interacting-continua (MINC), has been implemented in this simulator. The matrix blocks are discretized into subgrids in both horizontal and vertical directions to offer a more accurate transient flow description in matrix blocks. We believe this implementation has led to a unique and powerful reservoir simulator that can be used by small and large oil producers to help them in the design and prediction of complex gas and waterflooding processes on their desktops or a cluster of computers. Some features of this simulator, such as modeling both gas and water processes and the ability of 2D matrix subgridding are not available in any commercial simulator to the best of our knowledge. The code was developed on a cluster of processors, which has proven to be a very efficient and convenient resource for developing parallel programs. The results were successfully verified against analytical solutions and commercial simulators (ECLIPSE and GEM). Excellent results were achieved for a variety of reservoir case studies. Applications of this model for several IOR processes (including gas and water injection) are demonstrated. Results from using the simulator on a cluster of processors are also presented. Excellent speedup ratios were obtained. Introduction The dual-porosity model is one of the most widely used conceptual models for simulating naturally fractured reservoirs. In the dual-porosity model, two types of porosity are present in a rock volume: fracture and matrix. Matrix blocks are surrounded by fractures and the system is visualized as a set of stacked volumes, representing matrix blocks separated by fractures (Fig. 1). There is no communication between matrix blocks in this model, and the fracture network is continuous. Matrix blocks do communicate with the fractures that surround them. A mass balance for each of the media yields two continuity equations that are connected by matrix-fracture transfer functions which characterize fluid flow between matrix blocks and fractures. The performance of dual-porosity simulators is largely determined by the accuracy of this transfer function. The dual-porosity continuum approach was first proposed by Barenblatt et al. (1960) for a single-phase system. Later, Warren and Root (1963) used this approach to develop a pressure-transient analysis method for naturally fractured reservoirs. Kazemi et al. (1976) extended the Warren and Root method to multiphase flow using a 2D, two-phase, black-oil formulation. The two equations were then linked by means of a matrix-fracture transfer function. Since the publication of Kazemi et al. (1976), the dual-porosity approach has been widely used in the industry to develop field-scale reservoir simulation models for naturally fractured reservoir performance (Thomas et al. 1983; Gilman and Kazemi 1983; Dean and Lo 1988; Beckner et al. 1988; Rossen and Shen 1989). In simulating a fractured reservoir, we are faced with the fact that matrix blocks may contain well over 90% of the total oil reserve. The primary problem of oil recovery from a fractured reservoir is essentially that of extracting oil from these matrix blocks. Therefore it is crucial to understand the mechanisms that take place in matrix blocks and to simulate these processes within their container as accurately as possible. Discretizing the matrix blocks into subgrids or subdomains is a very good solution to accurately take into account transient and spatially nonlinear flow behavior in the matrix blocks. The resulting finite-difference equations are solved along with the fracture equations to calculate matrix-fracture transfer flow. The way that matrix blocks are discretized varies in the proposed models, but the objective is to accurately model pressure and saturation gradients in the matrix blocks (Saidi 1975; Gilman and Kazemi 1983; Gilman 1986; Pruess and Narasimhan 1985; Wu and Pruess 1988; Chen et al. 1987; Douglas et al. 1989; Beckner et al. 1991; Aldejain 1999).

Fractal permeability model for dual-porosity media embedded with natural tortuous fractures

Fuel ◽  
2021 ◽  
Vol 295 ◽  
pp. 120610
Author(s):  
Yafei Luo ◽  
Binwei Xia ◽  
Honglian Li ◽  
Huarui Hu ◽  
Mingyang Wu ◽  
...  
Keyword(s):  
Dual Porosity ◽  
Permeability Model

scholarly journals Development of Permeability Models for Saturated Fluid Flow across Arrays of Fibre Clusters

2002 ◽  
Vol 11 (3) ◽  
pp. 096369350201100
Author(s):  
E.M. Gravel ◽  
T.D. Papathanasiou
Keyword(s):  
Analytical Models ◽  
Dual Porosity ◽  
Hydraulic Permeability ◽  
Fibrous Media ◽  
Fibre Bundles ◽  
Hexagonal Packing ◽  
Composites Manufacturing ◽  
Starting Point ◽  
Wide Range ◽  
Flow Through

Dual porosity fibrous media are important in a number of applications, ranging from bioreactor design and transport in living systems to composites manufacturing. In the present study we are concerned with the development of predictive models for the hydraulic permeability ( Kp) of various arrays of fibre bundles. For this we carry out extensive computations for viscous flow through arrays of fibre bundles using the Boundary Element Method (BEM) implemented on a multi-processor computer. Up to 350 individual filaments, arranged in square or hexagonal packing within bundles, which are also arranged in square of hexagonal packing, are included in each simulation. These are simple but not trivial models for fibrous preforms used in composites manufacturing – dual porosity systems characterised by different inter- and intra-tow porosities. The way these porosities affect the hydraulic permeability of such media is currently unknown and is elucidated through our simulations. Following numerical solution of the governing equations, ( Kp) is calculated from the computed flowrate through Darcy's law and is expressed as function of the inter- and intra-tow porosities (φ, φt) and of the filament radius ( Rf). Numerical results are also compared to analytical models. The latter form the starting point in the development of a dimensionless correlation for the permeability of such dual porosity media. It is found that the numerically computed permeabilities follow that correlation for a wide range of φ i, φt and Rf.

Mass transport of solutes in dual-porosity media

1981 ◽  
Vol 17 (4) ◽  
pp. 1075-1081 ◽  
Author(s):  
Robert Bibby
Keyword(s):  
Mass Transport ◽  
Dual Porosity
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