Abstract:Two novel control-volume methods are presented for flow in fractured media, and involve coupling the controlvolume distributed multi-point flux approximation (CVD-MPFA) constructed with full pressure support (FPS), to two types of discrete fracture-matrix approximation for simulation on unstructured grids; (i) involving hybrid grids and (ii) a lower dimensional fracture model. Flow is governed by Darcy's law together with mass conservation both in the matrix and the fractures, where large discontinuities in pe… Show more
“…Our convergence ratios and errors magnitude are very close to those presented by Ahmed et al, 20 as shown in Figure 7, despite the errors magnitude, for = 1, of both CVD-MPFA versions (TPS and FPS) being slightly lower than those of the MPFA-D. Otherwise, for the other values of (for all values of a) the errors magnitude obtained by the MPFA-D are basically the same and never bigger than those of the CVD-MPFA (Figure 7).…”
Section: F I G U R Esupporting
confidence: 91%
“…In the convergence test, the proposed formulation performed very well when compared to the CVD-MPFA, method that has been recently adapted in the Hybrid-Grid context, 20 being capable to return similar error magnitudes and equivalent convergence rates.…”
Section: Discussionmentioning
confidence: 91%
“…In this section, the results of the application of the MPFA-D in the context of HyG for the simulation of one-and two-phase flows in naturally fractured reservoirs are presented. The first example is a convergence test, comparing the results of the MPFA-D/HyG with some results of Ahmed et al 20 The second and the third examples are one-phase flow problems. In the second one, we compare the MPFA-D with the MPFA-O (multipoint flux approximation with "O" stencil), [4][5][6] both in HyG context.…”
Section: Resultsmentioning
confidence: 99%
“…The errors magnitudes of all tested cases are close to each other. The results of the MPFA-D were compared with those presented, for the same test, by Ahmed et al 20 These authors obtained their results using the CVD-MPFA (control-volume distributed multipoint flux aproximation), also in a hybrid-grid context, in two different versions, the triangle-pressure support and the full-pressure support.…”
Section: One-phase Flow In a Reservoir With A Central Fracturementioning
confidence: 97%
“…17 In the LDFMs, 8,16,18 the flow equations for the fractures are discretized separately from the matrix, in a (n − 1)-dimensional subdomain. On the other hand, in the HyGs, 12,19,20 the fractures are expanded to n-dimensional objects in the computational domain, and the equations for fractures and the rock matrix can be discretized together, taking advantage from full pressure support (FPS) MPFA methods to solve the pressure equation. 20 Therefore, the HyG seems to present a good compromise between accuracy and computational costs, due its capability to properly represent complex geometries and anisotropy within fractures, without the computational overhead associated to the explicit discretization of fractures of the equidimensional approach.…”
Summary
Two‐phase flows of oil and water in naturally fractured reservoirs can be described by a system of nonlinear partial differential equations that comprises of an elliptic pressure equation and hyperbolic saturation equation coupled through the total velocity field. Modeling this problem is a great challenge, due to the complexity of the depositional environments, including inclined layers and fractures with different sizes and shapes, and random spatial distribution. In this work, to solve the pressure equation, we adopted a cell‐centered finite‐volume method with a multipoint flux approximation that uses the “diamond stencil” (MPFA‐D) coupled with a hybrid‐grid method (HyG) to deal with the fractures. The classical first‐order upwind method was used to solve the saturation equation, in its explicit and implicit versions. The MPFA‐D is a very robust and flexible formulation that is capable of handling highly heterogeneous and anisotropic domains using general polygonal meshes. In the strategy developed in this work, the mesh that discretize the domain must fit the spatial position of the fractures, so that they are associated to the control surfaces—as (n − 1)D cells—therefore, the calculation of the fluxes in these control surfaces is dependent on the pressures on fractures and on the adjacent volumes. In HyG, the fractures are expanded to nD in the computational domain. The proposed formulation presented quite remarkable results when compared with similar formulations using classical full pressure support and triangle pressure support methods, or even the with MPFA‐D itself when the fractures are treated as nD geometric entities.
“…Our convergence ratios and errors magnitude are very close to those presented by Ahmed et al, 20 as shown in Figure 7, despite the errors magnitude, for = 1, of both CVD-MPFA versions (TPS and FPS) being slightly lower than those of the MPFA-D. Otherwise, for the other values of (for all values of a) the errors magnitude obtained by the MPFA-D are basically the same and never bigger than those of the CVD-MPFA (Figure 7).…”
Section: F I G U R Esupporting
confidence: 91%
“…In the convergence test, the proposed formulation performed very well when compared to the CVD-MPFA, method that has been recently adapted in the Hybrid-Grid context, 20 being capable to return similar error magnitudes and equivalent convergence rates.…”
Section: Discussionmentioning
confidence: 91%
“…In this section, the results of the application of the MPFA-D in the context of HyG for the simulation of one-and two-phase flows in naturally fractured reservoirs are presented. The first example is a convergence test, comparing the results of the MPFA-D/HyG with some results of Ahmed et al 20 The second and the third examples are one-phase flow problems. In the second one, we compare the MPFA-D with the MPFA-O (multipoint flux approximation with "O" stencil), [4][5][6] both in HyG context.…”
Section: Resultsmentioning
confidence: 99%
“…The errors magnitudes of all tested cases are close to each other. The results of the MPFA-D were compared with those presented, for the same test, by Ahmed et al 20 These authors obtained their results using the CVD-MPFA (control-volume distributed multipoint flux aproximation), also in a hybrid-grid context, in two different versions, the triangle-pressure support and the full-pressure support.…”
Section: One-phase Flow In a Reservoir With A Central Fracturementioning
confidence: 97%
“…17 In the LDFMs, 8,16,18 the flow equations for the fractures are discretized separately from the matrix, in a (n − 1)-dimensional subdomain. On the other hand, in the HyGs, 12,19,20 the fractures are expanded to n-dimensional objects in the computational domain, and the equations for fractures and the rock matrix can be discretized together, taking advantage from full pressure support (FPS) MPFA methods to solve the pressure equation. 20 Therefore, the HyG seems to present a good compromise between accuracy and computational costs, due its capability to properly represent complex geometries and anisotropy within fractures, without the computational overhead associated to the explicit discretization of fractures of the equidimensional approach.…”
Summary
Two‐phase flows of oil and water in naturally fractured reservoirs can be described by a system of nonlinear partial differential equations that comprises of an elliptic pressure equation and hyperbolic saturation equation coupled through the total velocity field. Modeling this problem is a great challenge, due to the complexity of the depositional environments, including inclined layers and fractures with different sizes and shapes, and random spatial distribution. In this work, to solve the pressure equation, we adopted a cell‐centered finite‐volume method with a multipoint flux approximation that uses the “diamond stencil” (MPFA‐D) coupled with a hybrid‐grid method (HyG) to deal with the fractures. The classical first‐order upwind method was used to solve the saturation equation, in its explicit and implicit versions. The MPFA‐D is a very robust and flexible formulation that is capable of handling highly heterogeneous and anisotropic domains using general polygonal meshes. In the strategy developed in this work, the mesh that discretize the domain must fit the spatial position of the fractures, so that they are associated to the control surfaces—as (n − 1)D cells—therefore, the calculation of the fluxes in these control surfaces is dependent on the pressures on fractures and on the adjacent volumes. In HyG, the fractures are expanded to nD in the computational domain. The proposed formulation presented quite remarkable results when compared with similar formulations using classical full pressure support and triangle pressure support methods, or even the with MPFA‐D itself when the fractures are treated as nD geometric entities.
Some of the greatest challenges currently facing humanity have roots in the Earth and Energy Sciences. Policymakers rely on scientific research to answer questions related to the transition to green renewable energy, mitigate the climate crisis, and ensure global stability with reliable energy and water resources. A common thread in
Modeling of fluid flow in porous media is a pillar in geoscience applications. Previous studies have revealed that heterogeneity and fracture distribution have considerable influence on fluid flow. In this work, a numerical investigation of two-phase flow in heterogeneous fractured reservoir is presented. First, the discrete fracture model is implemented based on a hybrid-dimensional modeling approach, and an equivalent continuum approach is integrated in the model to reduce computational cost. A multilevel adaptive strategy is devised to improve the numerical robustness and efficiency. It allows up to 4-levels adaption, where the adaptive factors can be modified flexibly. Then, numerical tests are conducted to verify the the proposed method and to evaluate its performance. Different adaptive strategies with 3-levels, 4-levels and fixed time schemes are analyzed to evaluate the computational cost and convergence history. These evaluations demonstrate the merits of this method compared to the classical method. Later, the heterogeneity in permeability field, as well as initial saturation, is modeled in a layer model, where the effect of layer angle and permeability on fluid flow is investigated. A porous medium containing multiple length fractures with different distributions is simulated. The fine-scale fractures are upscaled based on the equivalent approach, while the large-scale fractures are retained. The conductivity of the rock matrix is enhanced by the upscaled fine-scale fractures. The difference of hydraulic property between homogeneous and heterogeneous situations is analyzed. It reveals that the heterogeneity may influence fluid flow and production, while these impacts are also related to fracture distribution and permeability.
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