A Fast Screening Tool for Assessing the Impact of Poro-Mechanics on Fractured Reservoirs Using Dual-Porosity Flow Diagnostics

2021 ◽  
Author(s):  
Lesly Gutierrez-Sosa ◽  
Sebastian Geiger ◽  
Florian Doster
Keyword(s):  
Fluid Flow ◽  
Steady State ◽  
Uncertainty Quantification ◽  
Reservoir Simulation ◽  
Fractured Reservoirs ◽  
Dual Porosity ◽  
Simulation Studies ◽  
Governing Equations ◽  
Flow Diagnostics ◽  
Stress Dependent

Abstract Accounting for poro-mechanical effects in full-field reservoir simulation studies and uncertainty quantification workflows is still limited, mainly because of their high computational cost. We introduce a new approach that couples hydrodynamics and poro-mechanics with dual-porosity flow diagnostics to analyse how poro-mechanics could impact reservoir dynamics in naturally fractured reservoirs without significantly increasing computational overhead. Our new poro-mechanical informed dual-porosity flow diagnostics account for steady-state and singlephase flow conditions in the fractured medium while the fracture-matrix fluid exchange is approximated using a physics-based transfer rate constant which models two-phase flow using an analytical solution for spontaneous imbibition or gravity drainage. The deformation of the system is described by the dualporosity poro-elastic theory, which is based on mixture theory and micromechanics to compute the effective stresses and strains of the rock matrix and fractures. The solutions to the fluid flow and rock deformation equations are coupled sequentially. The governing equations for fluid flow are discretised using a finite volume method with two-point flux-approximation while the governing equations for poro- mechanics are discretised using the virtual element method. The solution of the coupled system considers stress-dependent permeabilities for fractures and matrix. Our framework is implemented in the open source MATLAB Reservoir Simulation Toolbox (MRST). We present a case study using a fractured carbonate reservoir analogue to illustrate the integration of poro-mechanics within the dual-porosity flow diagnostics framework. The extended flow diagnostics calculations enable us to quickly screen how the dynamics in fractured reservoirs (e.g. reservoir connectivity, sweep efficiency, fracture-matrix transfer rates) are affected by the complex interactions between poro-mechanics and fluid flow where changes in pore pressure and effective stress modify petrophysical properties and hence impact reservoir dynamics. Due to the steady-state nature of the calculations and the effective coupling strategy, these calculations do not incur significant computational overheads. They hence provide an efficient complement to traditional reservoir simulation and uncertainty quantification workflows as they enable us to assess a broader range of reservoir uncertainties (e.g. geological, petrophysical and hydro-mechanical uncertainties). The capability of studying a much broader range of uncertainties allows the comparison and ranking from a large ensemble of reservoir models and select individual candidates for more detailed full-physics reservoir simulation studies without compromising on assessing the range of uncertainties inherent to fractured reservoirs.

scholarly journals The Influence of Different Types of Nanofluid on Thermal and Fluid Flow Performance of Liquid Cold Plate

2018 ◽  
Vol 7 (4.35) ◽  
pp. 148 ◽  
Author(s):  
Nur Irmawati Om ◽  
Rozli Zulkifli ◽  
P. Gunnasegaran
Keyword(s):  
Heat Transfer ◽  
Fluid Flow ◽  
Steady State ◽  
Pressure Drop ◽  
Volume Fraction ◽  
Cold Plate ◽  
Governing Equations ◽  
Flow And Heat Transfer ◽  
Different Types ◽  
Volume Method

The influence of utilizing different nanofluids types on the liquid cold plate (LCP) is numerically investigated. The thermal and fluid flow performance of LCP is examined by using pure ethylene glycol (EG), Al2O3-EG and CuO-EG. The volume fraction of the nanoparticle for both nanofluid is 2%. The finite volume method (FVM) has been used to solved 3-D steady state, laminar flow and heat transfer governing equations. The presented results indicate that Al2O3-EG able to provide the lowest surface temperature of the heater block followed by CuO-EG and EG, respectively. It is also found that the pressure drop and friction factor are higher for Al2O3-EG and CuO-EG compared to the pure EG.

scholarly journals The Role of In Situ Stress in Organizing Flow Pathways in Natural Fracture Networks at the Percolation Threshold

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-14 ◽  
Author(s):  
Chuanyin Jiang ◽  
Xiaoguang Wang ◽  
Zhixue Sun ◽  
Qinghua Lei
Keyword(s):  
Fluid Flow ◽  
Percolation Threshold ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
In Situ Stress ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
Dilation Effect ◽  
Stress Dependent

We investigated the effect of in situ stresses on fluid flow in a natural fracture network. The fracture network model is based on an actual critically connected (i.e., close to the percolation threshold) fracture pattern mapped from a field outcrop. We derive stress-dependent fracture aperture fields using a hybrid finite-discrete element method. We analyze the changes of aperture distribution and fluid flow field with variations of in situ stress orientation and magnitude. Our simulations show that an isotropic stress loading tends to reduce fracture apertures and suppress fluid flow, resulting in a decrease of equivalent permeability of the fractured rock. Anisotropic stresses may cause a significant amount of sliding of fracture walls accompanied with shear-induced dilation along some preferentially oriented fractures, resulting in enhanced flow heterogeneity and channelization. When the differential stress is further elevated, fracture propagation becomes prevailing and creates some new flow paths via linking preexisting natural fractures, which attempts to increase the bulk permeability but attenuates the flow channelization. Comparing to the shear-induced dilation effect, it appears that the propagation of new cracks leads to a more prominent permeability enhancement for the natural fracture system. The results have particularly important implications for predicting the hydraulic responses of fractured rocks to in situ stress fields and may provide useful guidance for the strategy design of geofluid production from naturally fractured reservoirs.

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.

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).

General Transfer Functions for Multiphase Flow in Fractured Reservoirs

SPE Journal ◽  
2008 ◽  
Vol 13 (03) ◽  
pp. 289-297 ◽  
Author(s):  
Huiyun Lu ◽  
Ginevra Di Donato ◽  
Martin J. Blunt
Keyword(s):  
Transfer Function ◽  
Reservoir Simulation ◽  
Transfer Rate ◽  
Unit Volume ◽  
Fractured Reservoirs ◽  
Dual Porosity ◽  
Permeability Model ◽  
Dual Porosity Model ◽  
The Matrix ◽  
Porosity Model

Summary We propose a physically motivated formulation for the matrix/fracture transfer function in dual-porosity and dual-permeability reservoir simulation. The approach currently applied in commercial simulators (Barenblatt et al. 1960; Kazemi et al. 1976) uses a Darcy-like flux from matrix to fracture, assuming a quasisteady state between the two domains that does not correctly represent the average transfer rate in a dynamic displacement. On the basis of 1D analyses in the literature, we find expressions for the transfer rate accounting for both displacement and fluid expansion at early and late times. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term to model fluid expansion. The transfer function is validated through comparison with 1D and 2D fine-grid simulations and is compared to predictions using the traditional Kazemi et al. (1976) formulation. Our method captures the dynamics of expansion and displacement more accurately. Introduction The conventional macroscopic treatment of flow in fractured reservoirs assumes that there are two communicating domains: a flowing region containing connected fractures and high permeability matrix and a stagnant region of low-permeability matrix (Barenblatt et al. 1960; Warren and Root 1963). Conventionally, these are referred to as fracture and matrix, respectively. Transfer between fracture and matrix is mediated by gravitational and capillary forces. In a dual-porosity model, it is assumed that there is no viscous flow in the matrix; a dual-permeability model allows flow in both fracture and matrix. In a general compositional model (where black-oil and incompressible flow are special cases) we can write[Equation 1], where where Gc is a transfer term with units of mass per unit volume per unit time--it is a rate (units of inverse time) times a density (mass per unit volume). c is a component density (concentration) with units of mass of component per unit volume. The subscript p labels the phase, and c labels the component. Gc represents the transfer of component c from fracture to matrix. The subscript f refers to the flowing or fractured domain. The first term is accumulation, and the second term represents flow--this is the same as in standard (nonfractured) reservoir simulation. We can write a corresponding equation for the matrix, m,[Equation 2] where we have assumed a dual-porosity model (no flow in the matrix); for a dual-permeability model, a flow term is added to Eq. 2.

Fluid Flow in a Fractured Reservoir Using a Geomechanically Constrained Fault-Zone-Damage Model for Reservoir Simulation

2009 ◽  
Vol 12 (04) ◽  
pp. 562-575 ◽  
Author(s):  
Pijush K. Paul ◽  
Mark D. Zoback ◽  
Peter H. Hennings
Keyword(s):  
Fluid Flow ◽  
Reservoir Simulation ◽  
Fractured Reservoirs ◽  
Damage Zone ◽  
Simulation Models ◽  
Rupture Propagation ◽  
Dynamic Rupture ◽  
Dynamic Rupture Propagation ◽  
Secondary Fractures ◽  
Fault Growth

Summary Secondary fractures and faults associated with reservoir-scale faults affect both permeability and permeability anisotropy and hence play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in damage zones adjacent to large faults. Because there are usually inadequate data to fully incorporate damage-zone fractures and faults into reservoir-simulation models, this study uses the principles of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir-scale faults. We include geomechanical constraints in our reservoir model and propose a generalized workflow to incorporate damage zones into reservoir-simulation models more routinely. The model we propose calculates the extent of the damage zone along the fault plane by estimating the volume of rock brought to failure by the stress perturbation associated with dynamic-rupture propagation. We apply this method to a real reservoir using both field- and well-scale observations. At the rupture front, damage intensity gradually decreases as we move away from the rupture front or fault plane. In the studied reservoir, the secondary-failure planes in the damage zone are high-angle normal faults striking subparallel to the parent fault, which may affect the permeability of the reservoir in both horizontal and vertical directions. We calibrate our modeling with both outcrop and well observations from a number of studies. We show that dynamic-rupture propagation gives a reasonable first-order approximation of damage zones in terms of permeability and permeability anisotropy in order to be incorporated into reservoir simulators. Introduction Fractures and faults in reservoirs present both problems and opportunities for exploration and production. The heterogeneity and complexity of fluid-flow paths in fractured rocks make it difficult to predict how to produce a fractured reservoir optimally. It is usually not possible to fully define the geometry of the fractures and faults controlling flow, and it is difficult to integrate data from markedly different scales (i.e., seismic, well log, core) into reservoir-simulation models. A number of studies in hydrogeology and the petroleum industry have dealt with modeling fractured reservoirs (Martel and Peterson 1991; Lee et al. 2001; Long and Billaux 1987; Gringarten 1996; Matthäi et al. 2007). Various methodologies, both deterministic and stochastic, have been developed to model the effects of reservoir heterogeneity on hydrocarbon flow and recovery. The work by Smart et al. (2001), Oda (1985, 1986), Maerten et al. (2002), Bourne and Willemse (2001), and Brown and Bruhn (1998) quantifies the stress sensitivity of fractured reservoirs. Several studies (Barton et al. 1995; Townend and Zoback 2000; Wiprut and Zoback 2000) that include fracture characterizations from wellbore images and fluid conductivity from the temperature and the production logs indicate fluid flow from critically stressed fractures. Additional studies emphasize the importance and challenges of coupling geomechanics in reservoir fluid flow (Chen and Teufel 2000; Couples et al. 2003; Bourne et al. 2000). These studies found that a variety of geomechanical factors may be very significant in some of the fractured reservoirs. Secondary fractures and faults associated with large-scale faults also appear to be quite important in controlling the permeability of some reservoirs. Densely concentrated secondary fractures and faults near large faults are often referred to as damage zones, which are created at various stages of fault evolution: before faulting (Aydin and Johnson 1978; Lyakhovsky et al. 1997; Nanjo et al. 2005), during fault growth (Chinnery 1966; Cowie and Scholz 1992; Anders and Wiltschko 1994; Vermily and Scholz 1998; Pollard and Segall 1987; Reches and Lockner 1994), and during the earthquake slip events (Freund 1974; Suppe 1984; Chester and Logan 1986) along the existing faults. Lockner et al. (1992) and Vermilye and Scholz (1998) show that the damage zones from the prefaulting stage are very narrow and can be ignored for reservoir-scale faults. The damage zone formed during fault growth can be modeled using dynamic rupture propagation along a fault plane (Madariaga 1976; Kostov 1964; Virieux and Madariaga 1982; Harris and Day 1997). Damage zones caused by slip on existing faults are important, especially when faults are active in present-day stress conditions because slip creates splay fractures at the tips of the fault and extends the damage zone created during the fault-growth stage (Collettini and Sibson 2001; Faulkner et al. 2006; Lockner and Byerlee 1993; Davatzes and Aydin 2003; Myers and Aydin 2004). In this paper, we first introduce a reservoir in which there appears to be significant permeability anisotropy associated with flow parallel to large reservoir-scale faults. Next, we build a geomechanical model of the field and then discuss the relationship between fluid flow and geomechanics at well-scale fracture and fault systems. To consider what happens in the reservoir at larger scale, we use dynamic rupture modeling to theoretically predict the size and extent of damage zones associated with the reservoir-scale faults.

Numerical Study of Fluid Flow Through a Confined Porous Square Cylinder

2019 ◽  
Vol 11 (1) ◽  
pp. 87-98
Author(s):  
Salah Guerbaai ◽  
Mouna Touiker ◽  
Kamel Meftah ◽  
Abdeslam Omara
Keyword(s):  
Nusselt Number ◽  
Fluid Flow ◽  
Steady State ◽  
Numerical Study ◽  
Simple Algorithm ◽  
Square Cylinder ◽  
Governing Equations ◽  
Flow Through ◽  
Forchheimer Model ◽  
Volume Method

Abstract A numerical study is performed to analyze steady state forced convection fluid flow through a confined porous square cylinder. The Darcy-Brinkman-Forchheimer model is adopted for the porous region. The finite volume method and the iterative SIMPLE algorithm are used to solve the governing equations. The results obtained are presented for the streamlines, variation of Nusselt number and drag coefficient for the range of conditions as 5 ≤ Re ≤ 40 and 10−2 ≤ Da ≤ 10−6.

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