The Experts below are selected from a list of 12 Experts worldwide ranked by ideXlab platform

C.a. Kossack - One of the best experts on this subject based on the ideXlab platform.

  • Realistic Numerical Models for Fractured Reservoirs
    SPE Journal, 2000
    Co-Authors: Omer M. Gurpinar, C.a. Kossack
    Abstract:

    Summary Characterization and forecasting in fractured Reservoirs is one of the most challenging topics in the oil and gas industry. Managing such Reservoirs requires construction of representative Reservoir models that can handle both fracture and matrix systems, and their interaction, correctly. Data integration from all disciplines is required for construction of these Reservoir models. Commercial numerical models capable of handling flow in fractured Reservoirs have been present in the industry for quite some time. However, the correct application of those simulators for representative Reservoir models is not easy. This paper will discuss parametric ways to improve construction of representative Reservoir models. Discussion will focus on transition from single-porosity representation to dual-porosity models and pseudoization of capillary pressure process employed in between. A fractured Reservoir undergoing a waterflood is simulated with a single-porosity formulation, where the matrix blocks are subdivided into core-plug-size gridblocks and the fractures are subdivided into even smaller blocks. The results from this fine grid are considered the "solution" to the displacement in the fractured Reservoir. The grid is coarsened and the effects of scale-up are observed. Pseudos are developed for a coarse grid so that the results match the solution. The Reservoir is then simulated with a dual-porosity simulator. The sensitivity of the dual-porosity results to the refinement of the numerical grid is studied. A comparison is made between the solution and the dual-porosity simulator results. Several of the advanced features found in commercial dual-porosity models are tested to see how well they improve the comparison. A scale-up pseudoization is determined that allows the dual-porosity simulation to match the solution. A larger sector model is then simulated with the pseudocapillary pressure to investigate the robustness of the scale-up pseudoization. Recommendations are provided that describe a procedure for using the dual-porosity model to simulate displacements in a fractured Reservoir in a more accurate way. The scale-up process discussed in this paper is just the first step of a two-step procedure. The next step is to scale-up these curves to a field-scale gridblock (i.e., 100×100×20 ft or m). If one uses nested matrix blocks for this first step of the scale-up process: the numerical computation problem is much more difficult and expensive and the next step scale-up calculation is confusing and difficult. Thus, this process is preferred in the final analysis. Introduction Since the initial approximations of Warren and Root1 and Gilman and Kazemi,2,3 fractured Reservoirs have been approximated by an orthogonal array of matrix blocks surrounded by fractures. The simulation of fluid flow in the fracture-matrix system with a standard "single-porosity" Reservoir simulator would require subdividing all the details of the matrix blocks and fractures into many small gridblocks. The fracture gridblocks resulting from this process would have pore volumes with only a fraction of a Reservoir Barrel. The discretization of an entire Reservoir, in idealized form, would require millions to hundreds of millions of gridblocks. The magnitude of the time steps that a typical simulator would allow in such a grid would be measured in seconds. To overcome the dual problems of millions of very small gridblocks and very small time steps, an approximate numerical simulation technique was developed.2 This approximate numerical simulator involves discretizing the Reservoir so that one subset of gridblocks represents the matrix blocks and another subset represents the fractures. The flow of fluids between the matrix material and the fractures is approximated by a matrix-fracture transfer coefficient, which is proportional to the matrix block surface area per unit volume. This transfer coefficient is usually represented by the variable s. The flow in a numerical model between the gridblocks representing the fractures and matrix material is calculated by a special transmissibility that involves this parameter. If the fracture and matrix gridblocks are not adjacent in the numerical grid, then non-neighbor connections are created in the simulators.4 These Reservoir simulators are usually called dual-porosity models. Although flow to the wells mostly comes through the fracture system, to properly simulate flow in naturally fractured Reservoirs, the capillary pressure and relative permeability in the matrix material are essential. Special core analysis is usually done on matrix rock obtained from coring operations. These rock curves (relative permeability and capillary pressure as functions of saturations) are valid for the core/core-plug-size pieces of matrix material where they are measured. Yet in a field-scale simulation of a fractured Reservoir, these curves and a single value of permeability and porosity are assigned to the matrix gridblocks, which are usually tens or hundreds of feet (meters) in three dimensions. The error incurred when one uses these curves and the "averaged" value of permeability and porosity to large numerical gridblocks is called scale-up error. Thus, the typical simulation of a fractured Reservoir with a dual-porosity Reservoir simulator has two problems: the approximate numerical flow model used may not represent the fluid flow found in the Reservoir, and the laboratory rock curves need to be scaled up before they are used in the large gridblocks used in a typical field simulation. When historical production data are available, history matching is employed to help the numerical model simulate the Reservoir results and overcome, to a certain extent, the problems. Unfortunately, history matching at this level has severe non-uniqueness problems. Also, commercial numerical Reservoir simulators have, over the years, added advanced features to the original approximation to improve the results. The ability of these advanced features to model the displacement process correctly is unknown since the solution we are trying to reach is uncertain. The questions that this paper attempts to answer are:What is the exact numerical solution to the displacement of oil by water in a fractured Reservoir?How does one scale up the numerical solution of the displacement in a single-porosity simulator?How does one scale up the displacement in a dual-porosity model?Is there a scale-up pseudoization process that will assure that dual-porosity models give the correct results? The results of this investigation show a process for simulating fluid flow in a fractured Reservoir with a dual-porosity simulator so that the results are close to a detailed single-porosity simulation.

  • Realistic Numerical Models for Fractured Reservoirs
    All Days, 2000
    Co-Authors: Omer M. Gurpinar, C.a. Kossack
    Abstract:

    Abstract Characterization and forecasting in fractured Reservoirs is one of the most challenging topics in the oil and gas industry. Managing such Reservoirs requires construction of representative Reservoir models that can handle both fracture and matrix systems, and their interaction, correctly. Data integration from all disciplines is required for construction of these Reservoir models. Commercial numerical models capable of handling flow in fractured Reservoirs have been present in the industry for quite some time. However the correct application of those simulators for representative Reservoir models is not easy. This paper will discuss parametric ways to improve construction of representative Reservoir models. Discussion will focus on transition from single porosity representation to dual porosity models and pseudoization process employed in between. A fractured Reservoir undergoing a waterflood is simulated with a single porosity formulation, where the matrix blocks are sub-divided into core plug size grid blocks and the fractures are sub-divided into even smaller blocks. The results from this fine grid are considered the "solution" to the displacement in the fractured Reservoir. The grid is coarsened and the effects of scale-up are observed. Pseudos are developed for a coarse grid so that the results match the "solution". The Reservoir is then simulated with a Dual Porosity simulator. The sensitivity of the dual porosity results to the refinement of the numerical grid is studied. A comparison is made between the "solution" and the Dual Porosity simulator results. Several of the advanced features found in commercial Dual Porosity models are tested to see how well they improve the comparison. A scale-up pseudoization is determined that allows the Dual Porosity simulation to match the "solution". A larger sector model is then simulated with the pseudo capillary pressure to investigate the robustness of the scale-up pseudoization. Recommendations are provided that describe a procedure for using the Dual Porosity Model to simulate displacements in a fractured Reservoir in a more accurate way. Introduction Since the initial approximations of Warren and Root 1 and Gilman and Kazemi 2,3, fractured Reservoirs have been approximated by an orthogonal array of matrix blocks surrounded by fractures. The simulation of fluid flow in the fracture-matrix system with a standard "Single Porosity" Reservoir simulator would require sub-dividing all the details of the matrix blocks and fractures into many small grid blocks. The fracture grid blocks resulting from this process would have pore volumes with only a fraction of a Reservoir Barrel. The discritization of an entire Reservoir, in idealized form, would require millions to hundreds of millions of grid blocks. The magnitude of the time steps that a typical simulator would allow in such a grid would be measured in seconds. To overcome the dual problems of millions of very small grid blocks and very small time steps, an approximate numerical simulation technique was developed.2 This approximate numerical simulator involves discretizing the Reservoir so that one subset of grid blocks represent the matrix blocks and another subset represents the fractures. The flow of fluids between the matrix material and the fractures is approximated by a matrix-fracture transfer coefficient, which is proportional to the matrix block surface area per unit volume. This transfer coefficient is usually represented by the variable sigma, s. The flow in a numerical model between the grid blocks representing the fractures and matrix material is calculated by a special transmissibility that involves this parameter. If the fracture and matrix grid blocks are not adjacent in the numerical grid, then non-neighbor connections are created in the simulators.4 These Reservoir simulators are usually called Dual Porosity Models.

R.j. Koopmans - One of the best experts on this subject based on the ideXlab platform.

  • Experimental study and modeling of oscillating flow of high density polyethylenes
    Journal of Rheology, 1996
    Co-Authors: V. Durand, Bruno Vergnes, Jean-françois Agassant, E. Benoit, R.j. Koopmans
    Abstract:

    The influence of flow rate and die geometry on the observable flow rate/pressure relationship of a linear high density polyethylene is investigated using a capillary rheometer. The experimental results are applied to an adapted version of the relaxation–oscillation model proposed by Molenaar and Koopmans for describing the oscillating flow regime. The current model allows for a quantitative description of the hysteresis cycle in the oscillating flow regime in terms of the main experimental variables, such as imposed flow rate, Reservoir (Barrel) volume, and material compressibility.

Omer M. Gurpinar - One of the best experts on this subject based on the ideXlab platform.

  • Realistic Numerical Models for Fractured Reservoirs
    SPE Journal, 2000
    Co-Authors: Omer M. Gurpinar, C.a. Kossack
    Abstract:

    Summary Characterization and forecasting in fractured Reservoirs is one of the most challenging topics in the oil and gas industry. Managing such Reservoirs requires construction of representative Reservoir models that can handle both fracture and matrix systems, and their interaction, correctly. Data integration from all disciplines is required for construction of these Reservoir models. Commercial numerical models capable of handling flow in fractured Reservoirs have been present in the industry for quite some time. However, the correct application of those simulators for representative Reservoir models is not easy. This paper will discuss parametric ways to improve construction of representative Reservoir models. Discussion will focus on transition from single-porosity representation to dual-porosity models and pseudoization of capillary pressure process employed in between. A fractured Reservoir undergoing a waterflood is simulated with a single-porosity formulation, where the matrix blocks are subdivided into core-plug-size gridblocks and the fractures are subdivided into even smaller blocks. The results from this fine grid are considered the "solution" to the displacement in the fractured Reservoir. The grid is coarsened and the effects of scale-up are observed. Pseudos are developed for a coarse grid so that the results match the solution. The Reservoir is then simulated with a dual-porosity simulator. The sensitivity of the dual-porosity results to the refinement of the numerical grid is studied. A comparison is made between the solution and the dual-porosity simulator results. Several of the advanced features found in commercial dual-porosity models are tested to see how well they improve the comparison. A scale-up pseudoization is determined that allows the dual-porosity simulation to match the solution. A larger sector model is then simulated with the pseudocapillary pressure to investigate the robustness of the scale-up pseudoization. Recommendations are provided that describe a procedure for using the dual-porosity model to simulate displacements in a fractured Reservoir in a more accurate way. The scale-up process discussed in this paper is just the first step of a two-step procedure. The next step is to scale-up these curves to a field-scale gridblock (i.e., 100×100×20 ft or m). If one uses nested matrix blocks for this first step of the scale-up process: the numerical computation problem is much more difficult and expensive and the next step scale-up calculation is confusing and difficult. Thus, this process is preferred in the final analysis. Introduction Since the initial approximations of Warren and Root1 and Gilman and Kazemi,2,3 fractured Reservoirs have been approximated by an orthogonal array of matrix blocks surrounded by fractures. The simulation of fluid flow in the fracture-matrix system with a standard "single-porosity" Reservoir simulator would require subdividing all the details of the matrix blocks and fractures into many small gridblocks. The fracture gridblocks resulting from this process would have pore volumes with only a fraction of a Reservoir Barrel. The discretization of an entire Reservoir, in idealized form, would require millions to hundreds of millions of gridblocks. The magnitude of the time steps that a typical simulator would allow in such a grid would be measured in seconds. To overcome the dual problems of millions of very small gridblocks and very small time steps, an approximate numerical simulation technique was developed.2 This approximate numerical simulator involves discretizing the Reservoir so that one subset of gridblocks represents the matrix blocks and another subset represents the fractures. The flow of fluids between the matrix material and the fractures is approximated by a matrix-fracture transfer coefficient, which is proportional to the matrix block surface area per unit volume. This transfer coefficient is usually represented by the variable s. The flow in a numerical model between the gridblocks representing the fractures and matrix material is calculated by a special transmissibility that involves this parameter. If the fracture and matrix gridblocks are not adjacent in the numerical grid, then non-neighbor connections are created in the simulators.4 These Reservoir simulators are usually called dual-porosity models. Although flow to the wells mostly comes through the fracture system, to properly simulate flow in naturally fractured Reservoirs, the capillary pressure and relative permeability in the matrix material are essential. Special core analysis is usually done on matrix rock obtained from coring operations. These rock curves (relative permeability and capillary pressure as functions of saturations) are valid for the core/core-plug-size pieces of matrix material where they are measured. Yet in a field-scale simulation of a fractured Reservoir, these curves and a single value of permeability and porosity are assigned to the matrix gridblocks, which are usually tens or hundreds of feet (meters) in three dimensions. The error incurred when one uses these curves and the "averaged" value of permeability and porosity to large numerical gridblocks is called scale-up error. Thus, the typical simulation of a fractured Reservoir with a dual-porosity Reservoir simulator has two problems: the approximate numerical flow model used may not represent the fluid flow found in the Reservoir, and the laboratory rock curves need to be scaled up before they are used in the large gridblocks used in a typical field simulation. When historical production data are available, history matching is employed to help the numerical model simulate the Reservoir results and overcome, to a certain extent, the problems. Unfortunately, history matching at this level has severe non-uniqueness problems. Also, commercial numerical Reservoir simulators have, over the years, added advanced features to the original approximation to improve the results. The ability of these advanced features to model the displacement process correctly is unknown since the solution we are trying to reach is uncertain. The questions that this paper attempts to answer are:What is the exact numerical solution to the displacement of oil by water in a fractured Reservoir?How does one scale up the numerical solution of the displacement in a single-porosity simulator?How does one scale up the displacement in a dual-porosity model?Is there a scale-up pseudoization process that will assure that dual-porosity models give the correct results? The results of this investigation show a process for simulating fluid flow in a fractured Reservoir with a dual-porosity simulator so that the results are close to a detailed single-porosity simulation.

  • Realistic Numerical Models for Fractured Reservoirs
    All Days, 2000
    Co-Authors: Omer M. Gurpinar, C.a. Kossack
    Abstract:

    Abstract Characterization and forecasting in fractured Reservoirs is one of the most challenging topics in the oil and gas industry. Managing such Reservoirs requires construction of representative Reservoir models that can handle both fracture and matrix systems, and their interaction, correctly. Data integration from all disciplines is required for construction of these Reservoir models. Commercial numerical models capable of handling flow in fractured Reservoirs have been present in the industry for quite some time. However the correct application of those simulators for representative Reservoir models is not easy. This paper will discuss parametric ways to improve construction of representative Reservoir models. Discussion will focus on transition from single porosity representation to dual porosity models and pseudoization process employed in between. A fractured Reservoir undergoing a waterflood is simulated with a single porosity formulation, where the matrix blocks are sub-divided into core plug size grid blocks and the fractures are sub-divided into even smaller blocks. The results from this fine grid are considered the "solution" to the displacement in the fractured Reservoir. The grid is coarsened and the effects of scale-up are observed. Pseudos are developed for a coarse grid so that the results match the "solution". The Reservoir is then simulated with a Dual Porosity simulator. The sensitivity of the dual porosity results to the refinement of the numerical grid is studied. A comparison is made between the "solution" and the Dual Porosity simulator results. Several of the advanced features found in commercial Dual Porosity models are tested to see how well they improve the comparison. A scale-up pseudoization is determined that allows the Dual Porosity simulation to match the "solution". A larger sector model is then simulated with the pseudo capillary pressure to investigate the robustness of the scale-up pseudoization. Recommendations are provided that describe a procedure for using the Dual Porosity Model to simulate displacements in a fractured Reservoir in a more accurate way. Introduction Since the initial approximations of Warren and Root 1 and Gilman and Kazemi 2,3, fractured Reservoirs have been approximated by an orthogonal array of matrix blocks surrounded by fractures. The simulation of fluid flow in the fracture-matrix system with a standard "Single Porosity" Reservoir simulator would require sub-dividing all the details of the matrix blocks and fractures into many small grid blocks. The fracture grid blocks resulting from this process would have pore volumes with only a fraction of a Reservoir Barrel. The discritization of an entire Reservoir, in idealized form, would require millions to hundreds of millions of grid blocks. The magnitude of the time steps that a typical simulator would allow in such a grid would be measured in seconds. To overcome the dual problems of millions of very small grid blocks and very small time steps, an approximate numerical simulation technique was developed.2 This approximate numerical simulator involves discretizing the Reservoir so that one subset of grid blocks represent the matrix blocks and another subset represents the fractures. The flow of fluids between the matrix material and the fractures is approximated by a matrix-fracture transfer coefficient, which is proportional to the matrix block surface area per unit volume. This transfer coefficient is usually represented by the variable sigma, s. The flow in a numerical model between the grid blocks representing the fractures and matrix material is calculated by a special transmissibility that involves this parameter. If the fracture and matrix grid blocks are not adjacent in the numerical grid, then non-neighbor connections are created in the simulators.4 These Reservoir simulators are usually called Dual Porosity Models.

V. Durand - One of the best experts on this subject based on the ideXlab platform.

  • Experimental study and modeling of oscillating flow of high density polyethylenes
    Journal of Rheology, 1996
    Co-Authors: V. Durand, Bruno Vergnes, Jean-françois Agassant, E. Benoit, R.j. Koopmans
    Abstract:

    The influence of flow rate and die geometry on the observable flow rate/pressure relationship of a linear high density polyethylene is investigated using a capillary rheometer. The experimental results are applied to an adapted version of the relaxation–oscillation model proposed by Molenaar and Koopmans for describing the oscillating flow regime. The current model allows for a quantitative description of the hysteresis cycle in the oscillating flow regime in terms of the main experimental variables, such as imposed flow rate, Reservoir (Barrel) volume, and material compressibility.

Bruno Vergnes - One of the best experts on this subject based on the ideXlab platform.

  • Experimental study and modeling of oscillating flow of high density polyethylenes
    Journal of Rheology, 1996
    Co-Authors: V. Durand, Bruno Vergnes, Jean-françois Agassant, E. Benoit, R.j. Koopmans
    Abstract:

    The influence of flow rate and die geometry on the observable flow rate/pressure relationship of a linear high density polyethylene is investigated using a capillary rheometer. The experimental results are applied to an adapted version of the relaxation–oscillation model proposed by Molenaar and Koopmans for describing the oscillating flow regime. The current model allows for a quantitative description of the hysteresis cycle in the oscillating flow regime in terms of the main experimental variables, such as imposed flow rate, Reservoir (Barrel) volume, and material compressibility.