A method and system for determining the permeability of a porous medium region in a fractured-vuggy reservoir

Abstract

The present application discloses a method and a system for determining the permeability of a porous medium region in a fractured-vuggy reservoir. The method includes: constructing a filling model for the porous medium region; performing a simulation based on the Navier-Stokes flow equation on the filling model of the porous medium region, and establishing a macroscopic simulation flow field according to the simulation; obtaining the inlet-outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field, and determining the equivalent permeability based on the macroscopic simulation flow field; using the inlet-outlet pressure difference, the outlet flow rate, the inlet-outlet length, and the equivalent permeability to determine the permeability of the porous medium region in the fractured-vuggy reservoir. The system of the present invention is based on the above method. The present invention solves the problem in the prior art that the permeability of a fractured-vuggy reservoir cannot be accurately determined, realizes the accurate determination of the permeability parameter field, and provides an input for reservoir characteristic simulation.

Description

Technical Field

[0001] The present application relates to the technical field of oil extraction, and in particular, to a method and system for determining the permeability of a porous medium region in a fractured-vuggy reservoir. Background Art

[0002] In the field of oil extraction, permeability is a parameter that quantitatively measures the permeability of a rock, and permeability is the property of a rock that allows fluids to pass through. Usually, permeability is a directional vector, and the parameter that appears synchronously with permeability is porosity, which mainly measures the storage capacity of a rock.

[0003] The patent document with the publication number CN103410502B discloses a method for obtaining the three-dimensional permeability field of a network-shaped fractured-vuggy reservoir. First, a three-dimensional porosity field of the network-shaped reservoir is established to determine the quantitative relationship between the reservoir porosity and permeability; the equivalent permeability of flat and circular tubular fracture-vug bodies is obtained, and the minimum critical permeability value is determined. Then, the critical permeability value is used as the maximum value to perform truncation processing on the permeability value of this value to obtain the equivalent permeability value; the tracer and interference well test results are used to correct the truncated permeability field; numerical simulation methods are used to correct the permeability field. Although the permeability obtained by this patent document is decisive for reservoir production prediction and well pattern and well spacing optimization, it is difficult to determine the permeability of a fractured-vuggy reservoir, which brings great inconvenience to oil extraction. Summary of the Invention

[0004] Embodiments of the present application provide a method and system for determining the permeability of a porous medium region in a fractured-vuggy reservoir, which solves the problem that the permeability of a fractured-vuggy reservoir cannot be accurately determined in the prior art, realizes the accurate determination of the permeability parameter field, and provides an input for reservoir characteristic simulation.

[0005] In a first aspect, an embodiment of the present invention provides a method for determining the permeability of a porous medium region in a fractured-vuggy reservoir, including:

[0006] Construct a filling model for the porous medium region;

[0007] Perform simulation on the filling model of the porous medium region based on the Navier-Stokes flow equation, and establish a macroscopic simulation flow field according to the simulation;

[0008] Obtain the inlet and outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field, and determine the equivalent permeability based on the macroscopic simulation flow field;

[0009] Use the inlet and outlet pressure difference, the outlet flow rate, the inlet and outlet lengths, and the equivalent permeability to determine the permeability of the porous medium region in the fractured-vuggy reservoir.

[0010] Based on the first aspect, in a possible implementation manner, the construction of the porous medium region filling model includes:

[0011] Partition the fractured-vuggy reservoir into multiple porous medium regions, and determine the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous medium region;

[0012] Determine the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region;

[0013] Use multiple filling rates to construct multiple filling models, and each filling model represents a porous medium region;

[0014] Merge the multiple filling models into a porous medium region filling model.

[0015] More specifically, when constructing the porous medium region filling model, considering that the radii, row spacings, and row spacings of the fractures and vugs in different units are different, in order to improve the model accuracy, the present invention uses different methods for partitioning different fractured-vuggy reservoirs. In principle, the radii, row spacings, and row spacings of the fractures and vugs in the same partition are as the same as possible, so that each filling model can more accurately simulate the fractured-vuggy reservoir. The present invention combines multiple filling models into an overall model according to the actual fractured-vuggy reservoir, which is convenient for simulation. In order to obtain a higher-precision simulation result, the present invention also eliminates the physical property changes of the fractured-vuggy reservoir. More specifically, the method for the present invention to eliminate the physical property changes of the fractured-vuggy reservoir is: adopting displacement simulation, constructing an unstructured grid, and using a boundary adaptive transition grid between unstructured grids. The aspect ratio, orthogonality, and the size of each unit in the unstructured grid are minimized as much as possible to avoid the sudden change of the unstructured grid from affecting the balance of pressure-velocity-density when the flow equation simulates fluid flow. Furthermore, the present invention divides each porous medium region into grid units by using the unstructured grid division method, and the grid unit preferably adopts 1 / (15 - 23)* filling particle radius, and uses a boundary adaptive transition grid to obtain a high-quality grid.

[0016] Based on the first aspect, in a possible implementation manner, the simulation of the porous medium region filling model based on the Navier-Stokes flow equation includes:

[0017] In the porous medium region, establish a simulation using the Navier-Stokes flow equation:

[0018]

[0019] In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force acting on the fluid;

[0020] In Equation (1), the stress tensor τ is expressed as:

[0021]

[0022] In Equation (2), μ is the phase viscosity, I is the unit vector, and in the left - hand side term represents the theoretical volume, and in the right - hand side term represents the volume expansion effect.

[0023] Based on the first aspect, in a possible implementation, the establishment of the macroscopic simulation flow field according to the simulation includes:

[0024] Establish a simulation using the Navier - Stokes flow equation;

[0025] Use a fluid simulation processing tool to process the simulation to obtain simulation parameters, where the simulation parameters include: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criterion, and relaxation coefficient;

[0026] Use the simulation parameters to calculate the input parameters of the porous media region filling model, where the input parameters include fluid pressure - velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate;

[0027] Input the input parameters into the porous media region filling model to obtain the inlet - outlet pressure difference, outlet flow rate, and equivalent permeability.

[0028] Based on the first aspect, in a possible implementation, inputting the input parameters into the porous media region filling model to obtain the inlet - outlet pressure difference, outlet flow rate, and equivalent permeability includes:

[0029] Statistically calculate the flow rate in the X - direction of each face in the porous media region filling model at the outlet to obtain the outlet flow rate. More specifically, use Equation (3) to obtain the outlet flow rate from the statistically calculated flow rate in the X - direction of each face,

[0030]

[0031] In Equation (3), Ω out is the outlet boundary condition, v f，x is the flow velocity of the boundary grid f in the x - direction, and A f is the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x - direction and the boundary area of the boundary grid f are obtained from the porous media region filling model;

[0032] Statistically calculate the fluid pressure at the inlet, and use the volume-weighted average method to calculate the average pressure at the inlet. More specifically, use Equation (4) to calculate the average pressure at the inlet:

[0033]

[0034] In Equation (4), Ω in is the inlet boundary condition, P f is the pressure parameter of grid f on the boundary, V f is the volume fraction of boundary grid f;

[0035] Calculate the equivalent permeability according to Equation (5) and Equation (6),

[0036]

[0037] In Equation (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous medium region, and k is the permeability;

[0038]

[0039] In Equation (6), A Ω is the boundary area, Q out is obtained from Equation (3), P in is the average pressure at the inlet, obtained from Equation (4), μ is the fluid viscosity, and k * is the equivalent permeability.

[0040] In a second aspect, an embodiment of the present invention provides a system for determining the permeability of a porous medium region in a fractured-vuggy reservoir, including: an input unit, a processing unit, and an output unit that are connected in sequence;

[0041] A porous medium region filling model runs in the processing unit;

[0042] The input unit inputs the input simulation parameters into the porous medium region filling model of the processing unit, and the processing unit performs simulation on the porous medium region filling model,

[0043] The processing unit establishes a macroscopic simulation flow field based on the simulation, and obtains the inlet and outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field; the processing unit also determines the equivalent permeability based on the macroscopic simulation flow field; and determines the permeability of the porous medium region in the fractured-vuggy reservoir using the inlet and outlet pressure difference, the outlet flow rate, the inlet and outlet lengths, and the equivalent permeability; the processing unit sends the permeability of the porous medium region in the fractured-vuggy reservoir to the output unit;

[0044] The output unit outputs the permeability of the porous medium region in the fractured-vuggy reservoir transmitted by the processing unit.

[0045] Based on the second aspect, in a possible implementation, a porous medium region filling model runs in the processing unit, and the processing unit also constructs a porous medium region filling model;

[0046] The processing unit constructing the porous medium region filling model includes:

[0047] Partitioning the fractured-vuggy reservoir into multiple porous medium regions, and determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles for each porous medium region;

[0048] Determining the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region;

[0049] Using multiple filling rates to construct multiple filling models, and each filling model represents a porous medium region;

[0050] Combining the multiple filling models into a porous medium region filling model.

[0051] More specifically, when constructing the porous medium region filling model, considering that the radii, row spacings, and row spacings of the fractures and vugs in different units are different, in order to improve the model accuracy, the present invention uses different methods for partitioning different fractured-vuggy reservoirs. In principle, the radii, row spacings, and row spacings of the fractures and vugs in the same partition are as the same as possible, so that each filling model can more accurately simulate the fractured-vuggy reservoir. The present invention combines multiple filling models into an overall model according to the actual fractured-vuggy reservoir, which is convenient for simulation. In order to obtain a higher-precision simulation result, the present invention also eliminates the physical property changes of the fractured-vuggy reservoir. More specifically, the method for the present invention to eliminate the physical property changes of the fractured-vuggy reservoir is: adopting displacement simulation, constructing an unstructured grid, and using a boundary adaptive transition grid between the unstructured grids. The aspect ratio, orthogonality, and the size of each unit in the unstructured grid are minimized as much as possible to avoid the sudden change of the unstructured grid affecting the balance of pressure-velocity-density when the flow equation simulates fluid flow. Furthermore, the present invention divides each porous medium region into grid cells by using the unstructured grid division method, and the grid cells preferably adopt 1 / (15-23)* filling particle radius, and use a boundary adaptive transition grid to obtain a high-quality grid.

[0052] Based on the second aspect, in a possible implementation, the processing unit performs a simulation based on the Navier-Stokes flow equation on the porous medium region filling model, including:

[0053] In the porous medium region, establishing a simulation using the Navier-Stokes flow equation:

[0054]

[0055] In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force acting on the fluid;

[0056] In Equation (1), the stress tensor τ is expressed as:

[0057]

[0058] In Equation (2), μ is the phase viscosity, I is the unit vector, and in the left - hand side term represents the theoretical volume, and in the right - hand side term represents the volume expansion effect.

[0059] Based on the second aspect, in a possible implementation, the processing unit establishes a macroscopic simulation flow field according to the simulation, including:

[0060] Establishing the simulation using the Navier - Stokes flow equation;

[0061] Processing the simulation using a fluid simulation processing tool to obtain simulation parameters, where the simulation parameters include: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criteria, and relaxation coefficient;

[0062] Calculating the input parameters of the porous medium region filling model using the simulation parameters, where the input parameters include fluid pressure - velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate;

[0063] Inputting the input parameters into the porous medium region filling model to obtain the inlet - outlet pressure difference, outlet flow rate, and equivalent permeability.

[0064] Based on the second aspect, in a possible implementation, when the processing unit inputs the input parameters into the porous medium region filling model to obtain the inlet - outlet pressure difference, outlet flow rate, and equivalent permeability, it includes:

[0065] Statistically calculating the flow rate in the x - direction of each face in the porous medium region filling model at the outlet to obtain the outlet flow rate. More specifically, the outlet flow rate is obtained from the statistically calculated flow rate in the x - direction of each face using Equation (3),

[0066]

[0067] In Equation (3), Ω out is the outlet boundary condition, v f，x is the flow velocity of the boundary grid f in the x - direction, and A fis the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x - direction and the boundary area of the boundary grid f are obtained from the porous - medium - region filling model;

[0068] Statistically analyze the fluid pressure at the inlet, and calculate the average pressure at the inlet using the volume - weighted average method. More specifically, use formula (4) to calculate the average pressure at the inlet:

[0069]

[0070] In formula (4), Ω in is the inlet boundary condition, P f is the pressure parameter of the grid f on the boundary, V f is the volume fraction of the boundary grid f;

[0071] Calculate the equivalent permeability according to formula (5) and formula (6),

[0072]

[0073] In formula (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous - medium region, and k is the permeability;

[0074]

[0075] In formula (6), A Ω is the boundary area, Q out is obtained from formula (3), P in is the average pressure at the inlet, obtained from formula (4), μ is the fluid viscosity, k * is the equivalent permeability.

[0076] One or more technical solutions provided in the embodiments of the present invention have at least the following technical effects or advantages:

[0077] The embodiments of the present invention solve the problem that the permeability of the fracture - cave reservoir in the prior art cannot be accurately determined, realize the accurate determination of the permeability parameter field, and provide input for the simulation of reservoir characteristics. BRIEF DESCRIPTION OF THE DRAWINGS

[0078] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for the description of the embodiments of the present invention or the prior art. Obviously, the drawings in the following description are some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on these drawings without creative efforts.

[0079] Figure 1 is a flow - chart of a method for determining the permeability of the porous - medium region of a fracture - cave reservoir provided by the embodiments of this application;

[0080] Figure 2 This is a schematic block diagram of a system for determining the permeability of the porous media region in a fractured-vuggy reservoir provided by an embodiment of the present application;

[0081] Figure 3 This is a schematic diagram of a filling model for the porous media region provided by an embodiment of the present application;

[0082] Figure 4 This is a schematic diagram of the boundary conditions of the filling model for the porous media region provided by an embodiment of the present application;

[0083] Figure 5 This is a list of simulation parameters provided by an embodiment of the present application;

[0084] Figure 6 This is an application example of the filling model for the porous media region provided by an embodiment of the present application;

[0085] Figure 7 This is a displacement process diagram with different injection volume percentages provided by an embodiment of the present application. Detailed implementation manners

[0086] Next, the technical solutions in the embodiments of the present invention will be clearly and completely described in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, rather than all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative efforts shall fall within the protection scope of the present invention.

[0087] Please refer to Figure 1 , an embodiment of the present invention provides a method for determining the permeability of the porous media region in a fractured-vuggy reservoir, including:

[0088] Construct a filling model for the porous media region;

[0089] Perform a simulation on the filling model for the porous media region based on the Navier-Stokes flow equation, and establish a macroscopic simulation flow field according to the simulation;

[0090] Obtain the inlet-outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field, and determine the equivalent permeability based on the macroscopic simulation flow field;

[0091] Use the inlet-outlet pressure difference, the outlet flow rate, the inlet-outlet length, and the equivalent permeability to determine the permeability of the porous media region in the fractured-vuggy reservoir.

[0092] In practical applications, Figure 3The figure shows a schematic diagram of the filling model for the porous medium region. The schematic diagram of the filling model for the porous medium region is established based on the specific filling rate of the porous medium region. The displacement simulation depends on the grid model. Excessive aspect ratio, orthogonality, and sudden changes in element size will affect the conservation of the pressure-velocity-density balance, resulting in sudden changes in physical properties. To obtain higher-precision flow simulation results, the embodiments of the present invention use unstructured grids, with the grid element size being R / 20 and boundary adaptive transition grids being adopted to obtain high-quality grids.

[0093] Assuming that the permeability is a geometric property independent of the fluid, a single-phase fluid displacement from left to right is applied to the model. For the consideration of improving the calculation speed and facilitating analysis, the fluid viscosity is set to 1 mPa·s and the density is set to 1000 kg / m 3 . To visually display the displacement results, the displacing fluid and the original fluid are divided into two phases with the same parameters. Please refer to Figure 4 the schematic diagram of the boundary conditions of the filling model for the porous medium region shown. On the left side of the embodiments of the present invention, a Neumann constant flow boundary condition is set, and the injection flow rate is 0.01 PV / s (0.01 times the effective cavity volume per second); on the right side, a Dirichlet constant pressure boundary condition is set. Since we are concerned about the pressure difference between the left and right sides of the system and do not need to care about the absolute value, for simplicity, the pressure value on the right side is set to 0 Pa. In the pores of the above filling model, the internal flow law belongs to free flow, and the Navier-Stokes equation (abbreviated as the NS equation) is used to describe it. The NS equation model is also applicable to porous media such as pores and microfractures, but the boundaries of these media are complex, and it is difficult to establish flow boundaries. Even if flow boundaries can be established, a huge number of grids must be established to reflect the flow boundaries, and the computational amount required for reservoir-scale models is currently difficult to achieve by computers. However, for the specific region studied in this solution, it is possible to perform flow simulation of the model based on the NS equation.

[0094] Based on the above solution, further, a filling model for the porous medium region is constructed, including:

[0095] Dividing the fracture-vug reservoir into multiple porous medium regions, and determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous medium region;

[0096] Determining the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region;

[0097] Using multiple filling rates to construct multiple filling models, and each filling model represents a porous medium region;

[0098] Combine multiple filling models into a porous medium region filling model.

[0099] More specifically, when constructing the porous medium region filling model, considering that the radii, row spacings, and column spacings of the fractures and cavities in different units are different, in order to improve the model accuracy, the present invention uses different methods to partition different fracture-cavity reservoirs. In principle, the radii, row spacings, and column spacings of the fractures and cavities in the same partition are as identical as possible, so that each filling model can more accurately simulate the fracture-cavity reservoir. The present invention combines multiple filling models into an overall model according to the actual fracture-cavity reservoir, which is convenient for simulation. In order to obtain a higher-precision simulation result, the present invention also eliminates the physical property changes of the fracture-cavity reservoir. More specifically, the method for the present invention to eliminate the physical property changes of the fracture-cavity reservoir is: adopt displacement simulation, construct an unstructured grid, and use a boundary adaptive transition grid between the unstructured grids. The aspect ratio, orthogonality, and the size of each unit in the unstructured grid are minimized as much as possible to avoid the sudden change of the unstructured grid from affecting the balance of pressure-velocity-density when the flow equation simulates fluid flow. Furthermore, the present invention divides each porous medium region into grid cells by using the unstructured grid division method. The grid cells preferably adopt 1 / (15-23)* the radius of the filling particles, and use a boundary adaptive transition grid to obtain a high-quality grid.

[0100] Based on the above solution, further, perform a simulation on the porous medium region filling model based on the Navier-Stokes flow equation, including:

[0101] In the porous medium region, establish a simulation using the Navier-Stokes flow equation:

[0102]

[0103] In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force acting on the fluid;

[0104] In Equation (1), the stress tensor τ is expressed as:

[0105]

[0106] In Equation (2), μ is the phase viscosity, I is the unit vector, and in the left-hand side term represents the theoretical volume, and in the right-hand side term represents the volume dilation effect.

[0107] Based on the above solution, please refer to Figure 5 , further, establish a macroscopic simulation flow field according to the simulation, including:

[0108] Establish a simulation using the Navier-Stokes flow equation;

[0109] Use a fluid simulation processing tool to process the simulation, and obtain simulation parameters, including: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criterion, and relaxation factor;

[0110] Use the simulation parameters to calculate the input parameters of the porous medium region filling model, including fluid pressure-velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate;

[0111] Input the input parameters into the porous medium region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability.

[0112] Based on the above scheme, further, input the input parameters into the porous medium region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability, including:

[0113] Statistically calculate the flow rate in the x-direction of each face in the porous medium region filling model at the outlet to obtain the outlet flow rate. More specifically, use Equation (3) to obtain the outlet flow rate from the statistically calculated flow rate in the x-direction of each face.

[0114]

[0115] In Equation (3), Ω out is the outlet boundary condition, v f，x is the flow velocity of the boundary grid f in the x-direction, and A f is the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x-direction and the boundary area of the boundary grid f are obtained from the porous medium region filling model;

[0116] Statistically calculate the fluid pressure at the inlet, and use the volume-weighted average method to calculate the average pressure at the inlet. More specifically, use Equation (4) to calculate the average pressure at the inlet:

[0117]

[0118] In Equation (4), Ω in is the inlet boundary condition, P f is the pressure parameter of the grid f on the boundary, and V f is the volume fraction of the boundary grid f;

[0119] Calculate the equivalent permeability according to Equation (5) and Equation (6).

[0120]

[0121] In Equation (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous medium region, and k is the permeability;

[0122]

[0123] In formula (6), A Ω is the boundary area, Q out is obtained from formula (3), and P in is the average pressure at the inlet, obtained from formula (4), μ is the fluid viscosity, and k * is the equivalent permeability.

[0124] Please refer to Figure 2 , an embodiment of the present invention provides a system for determining the permeability of the porous medium region in a fracture-cavity reservoir, including: an input unit, a processing unit, and an output unit connected in sequence;

[0125] A porous medium region filling model runs in the processing unit;

[0126] The input unit inputs the input simulation parameters into the porous medium region filling model of the processing unit, and the processing unit simulates the porous medium region filling model.

[0127] The processing unit establishes a macroscopic simulation flow field based on the simulation, and obtains the inlet and outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field; the processing unit also determines the equivalent permeability based on the macroscopic simulation flow field; and uses the inlet and outlet pressure difference, the outlet flow rate, the inlet and outlet lengths, and the equivalent permeability to determine the permeability of the porous medium region in the fracture-cavity reservoir; the processing unit sends the permeability of the porous medium region in the fracture-cavity reservoir to the output unit;

[0128] The output unit outputs the permeability of the porous medium region in the fracture-cavity reservoir transmitted by the processing unit.

[0129] Based on the above solution, further, a porous medium region filling model runs in the processing unit, and the processing unit also constructs a porous medium region filling model;

[0130] The processing unit constructs a porous medium region filling model including:

[0131] Dividing the fracture-cavity reservoir into multiple porous medium regions, and determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous medium region;

[0132] Determining the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region;

[0133] Using multiple filling rates to construct multiple filling models, each filling model representing a porous medium region;

[0134] Combining multiple filling models into a porous medium region filling model.

[0135] More specifically, when constructing the filling model of the porous medium region, considering that the radii, row spacings, and column spacings of the fractures and caves in different units are different, in order to improve the accuracy of the model, the present invention partitions different fracture-cave reservoirs using different methods. In principle, the radii, row spacings, and column spacings of the fractures and caves in the same partition are as identical as possible, so that each filling model can more accurately simulate the fracture-cave reservoir. The present invention combines multiple filling models into an overall model according to the actual fracture-cave reservoir, which is convenient for simulation. In order to obtain a simulation result with higher accuracy, the present invention also eliminates the change in the physical properties of the fracture-cave reservoir. More specifically, the method for the present invention to eliminate the change in the physical properties of the fracture-cave reservoir is as follows: displacement simulation is adopted to construct an unstructured grid, and a boundary adaptive transition grid is used between the unstructured grids. In the unstructured grid, the aspect ratio, orthogonality, and the size of each unit in the grid are minimized as much as possible to avoid the sudden change of the unstructured grid from affecting the balance of pressure-velocity-density when the flow equation simulates fluid flow. Further, the present invention divides each porous medium region into grid cells using the unstructured grid division method. The grid cells preferably adopt 1 / (15 - 23)* the radius of the filling particles, and a boundary adaptive transition grid is used to obtain a high-quality grid.

[0136] Based on the above solution, further, the processing unit performs a simulation on the filling model of the porous medium region based on the Navier-Stokes flow equation, including:

[0137] In the porous medium region, a simulation is established using the Navier-Stokes flow equation:

[0138]

[0139] In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force acting on the fluid;

[0140] In Equation (1), the stress tensor τ is expressed as:

[0141]

[0142] In Equation (2), μ is the phase viscosity, I is the unit vector, the left end term represents the theoretical volume, and the right end term represents the volume dilation effect.

[0143] Based on the above solution, further, the processing unit establishes a macroscopic simulation flow field according to the simulation, including:

[0144] A simulation is established using the Navier-Stokes flow equation;

[0145] Use a fluid simulation processing tool to process the simulation, obtaining simulation parameters, which include: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criteria, and relaxation factor;

[0146] Use the simulation parameters to calculate the input parameters of the porous media region filling model, which include fluid pressure-velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate;

[0147] Input the input parameters into the porous media region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability.

[0148] Based on the above scheme, further, the processing unit inputs the input parameters into the porous media region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability, including:

[0149] Statistically calculate the flow rate in the x-direction of each face in the porous media region filling model at the outlet to obtain the outlet flow rate. More specifically, use Equation (3) to obtain the outlet flow rate from the statistically calculated flow rate in the x-direction of each face.

[0150]

[0151] In Equation (3), Ω out is the outlet boundary condition, v f，x is the flow velocity of the boundary grid f in the x-direction, and A f is the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x-direction and the boundary area of the boundary grid f are obtained from the porous media region filling model;

[0152] Statistically calculate the fluid pressure at the inlet, and use the volume-weighted average method to calculate the average pressure at the inlet. More specifically, use Equation (4) to calculate the average pressure at the inlet:

[0153]

[0154] In Equation (4), Ω in is the inlet boundary condition, P f is the pressure parameter of the boundary grid f, and V f is the volume fraction of the boundary grid f;

[0155] Calculate the equivalent permeability according to Equation (5) and Equation (6).

[0156]

[0157] In Equation (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous media region, and k is the permeability;

[0158]

[0159] In formula (6), A Ω is the boundary area, Q out is obtained from formula (3), P in is the average pressure at the inlet, obtained from formula (4), μ is the fluid viscosity, and k * is the equivalent permeability.

[0160] One or more technical solutions provided in the embodiments of the present invention have at least the following technical effects or advantages:

[0161] The embodiments of the present invention solve the problem that the permeability of fractured-vuggy reservoirs cannot be accurately determined in the prior art, realize the accurate determination of the permeability parameter field, and provide input for reservoir characteristic simulation.

[0162] In practical applications, for the conceptual model of the porous medium region filling in the embodiments of the present invention, please refer to Figure 5 , for Figure 5 the porous medium region model with a filling rate of 54.5% (porosity of 45.5%) shown, the flow fields (pressure field and velocity field) corresponding to different injection times are obtained. Figure 6 The figure shows the displacement process diagrams for different injection volume percentages (PVI). When the flow rate is stable, the average pressure at the inlet end can be obtained as 13.4 Pa, the average pressure at the outlet end is 0 Pa, and the flow rate is 5.4E-8 m 3 / s. According to Darcy's formula, the equivalent permeability of the system can be obtained:

[0163]

[0164] The embodiments of the present invention solve the problem that the permeability of fractured-vuggy reservoirs cannot be accurately determined in the prior art, realize the accurate determination of the permeability parameter field, and provide input for reservoir characteristic simulation.

[0165] The various embodiments in this specification are described in a progressive manner. For the same or similar parts between the various embodiments, reference can be made to each other. The key points described in each embodiment are the differences from other embodiments.

[0166] The above embodiments are only used to illustrate the technical solutions of the present application, rather than to limit the present application. Although the present application has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that they can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements for some or all of the technical features; and these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the present application.

Claims

1. A method for determining the permeability of the porous media region in a fractured-vuggy reservoir, characterized in that, it includes: Constructing a filling model for the porous media region, including: dividing the fractured-vuggy reservoir into multiple porous media regions, determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous media region; determining the filling rate of each porous media region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous media region; using multiple filling rates to construct multiple filling models, each filling model representing a porous media region; combining the multiple filling models into a filling model for the porous media region; Performing a simulation based on the Navier-Stokes flow equation on the filling model of the porous media region, and establishing a macroscopic simulation flow field according to the simulation; wherein, establishing the macroscopic simulation flow field according to the simulation includes: establishing a simulation model using the Navier-Stokes flow equation; processing the simulation model using a fluid simulation processing tool to obtain simulation parameters, the simulation parameters including: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criterion, and relaxation coefficient; calculating the input parameters of the filling model of the porous media region using the simulation parameters, the input parameters including fluid pressure-velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate; inputting the input parameters into the filling model of the porous media region to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability; Obtaining the inlet-outlet pressure difference and outlet flow rate based on the macroscopic simulation flow field, and determining the equivalent permeability based on the macroscopic simulation flow field; Determining the permeability of the porous media region in the fractured-vuggy reservoir using the inlet-outlet pressure difference, outlet flow rate, inlet-outlet length, and equivalent permeability.

2. The method for determining the permeability of the porous media region in a fractured-vuggy reservoir according to claim 1, characterized in that, performing the simulation based on the Navier-Stokes flow equation on the filling model of the porous media region includes: In the porous media region, establishing a simulation using the Navier-Stokes flow equation: In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force exerted on the fluid; In Equation (1), the stress tensor τ is expressed as: In Equation (2), μ is the phase viscosity, I is the unit vector, and in the left-hand term represents the theoretical volume, and in the right-hand term represents the volume expansion effect.

3. The method for determining the permeability of the porous media region in a fractured-vuggy reservoir according to claim 1, characterized in that, inputting the input parameters into the filling model of the porous media region to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability includes: Counting the flow rate in the X direction of each face in the filling model of the porous media region at the outlet to obtain the outlet flow rate. More specifically, the outlet flow rate is obtained from the counted flow rate in the X direction of each face using Equation (3), In formula (3), Ω out is the outlet boundary condition, v f,x is the flow velocity of the boundary grid f in the x direction, and A f is the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x direction and the boundary area of the boundary grid f are obtained from the porous medium region filling model; Counting the fluid pressure at the inlet, and calculating the average pressure at the inlet using the volume-weighted average method. More specifically, the average pressure at the inlet is calculated using Equation (4): In Equation (4), Ω in is the inlet boundary condition, P f is the pressure parameter of grid f on the boundary, and V f is the volume fraction of boundary grid f; Calculate the equivalent permeability according to Formula (5) and Formula (6). In Formula (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous medium region, and k is the permeability. In Equation (6), A Ω is the boundary area, Q out is obtained from Equation (3), P in is the average pressure at the inlet, obtained from Equation (4), μ is the fluid viscosity, k * is the equivalent permeability.

4. A system for determining the permeability of the porous medium region in a fractured-vuggy reservoir Characterized in that It includes An input unit, a processing unit, and an output unit connected in sequence A porous medium region filling model runs in the processing unit, including: dividing the fractured-vuggy reservoir into multiple porous medium regions, determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous medium region; determining the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region; using multiple filling rates to construct multiple filling models, each filling model characterizing a porous medium region; merging the multiple filling models into a porous medium region filling model The input unit inputs the input simulation parameters into the porous medium region filling model of the processing unit, and the processing unit simulates the porous medium region filling model The processing unit establishes a macroscopic simulation flow field based on the simulation, and obtains the inlet and outlet pressure difference and the outlet flow rate based on the macroscopic simulation flow field; the processing unit also determines the equivalent permeability based on the macroscopic simulation flow field; and determines the permeability of the porous medium region in the fractured-vuggy reservoir using the inlet and outlet pressure difference, the outlet flow rate, the inlet and outlet length, and the equivalent permeability; the processing unit sends the permeability of the porous medium region in the fractured-vuggy reservoir to the output unit; wherein, establishing the macroscopic simulation flow field based on the simulation includes: establishing a simulation model using the Navier-Stokes flow equation; processing the simulation model using a fluid simulation processing tool to obtain simulation parameters, the simulation parameters including: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criterion, and relaxation coefficient; calculating the input parameters of the porous medium region filling model using the simulation parameters, the input parameters including fluid pressure velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate; inputting the input parameters into the porous medium region filling model to obtain the inlet and outlet pressure difference, the outlet flow rate, and the equivalent permeability The output unit outputs the permeability of the porous medium region in the fractured-vuggy reservoir transmitted by the processing unit 5. The system for determining the permeability of the porous medium region in a fractured-vuggy reservoir according to Claim 4 Characterized in that A porous medium region filling model runs in the processing unit, and the processing unit also constructs a porous medium region filling model The processing unit constructs the porous medium region filling model including Dividing the fractured-vuggy reservoir into multiple porous medium regions, and determining the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in each porous medium region Determine the filling rate of each porous medium region according to the filling particle radius, the center point spacing of each row of filling particles, and the row spacing of each row of filling particles in the porous medium region; Construct multiple filling models using multiple filling rates, and each filling model represents a porous medium region; Combine the multiple filling models into a porous medium region filling model.

6. The system for determining the permeability of the porous medium region in a fractured-vuggy reservoir according to claim 4, wherein, the processing unit performs a simulation based on the Navier-Stokes flow equation on the porous medium region filling model, including: In the porous medium region, establish a simulation using the Navier-Stokes flow equation: In Equation (1), μ is the phase viscosity, p is the fluid pressure, τ is the fluid stress tensor, ρg is the gravity term, and f is the body force acting on the fluid; In Equation (1), the stress tensor τ is expressed as: In Equation (2), μ is the phase viscosity, I is the unit vector, and in the left-hand term represents the theoretical volume, and in the right-hand term represents the volume expansion effect.

7. The system for determining the permeability of the porous medium region in a fractured-vuggy reservoir according to claim 4, wherein, the processing unit establishes a macroscopic simulation flow field based on the simulation, including: Establish a simulation using the Navier-Stokes flow equation; Use a fluid simulation processing tool to process the simulation to obtain simulation parameters, and the simulation parameters include: inlet boundary conditions, outlet boundary conditions, number of time steps, time step size, number of iterations per time step, convergence criterion, and relaxation coefficient; Use the simulation parameters to calculate the input parameters of the porous medium region filling model, and the input parameters include fluid pressure-velocity coupling scheme, gradient parameter, pressure parameter, momentum parameter, volume fraction, kinetic energy parameter, and specific dissipation rate; Input the input parameters into the porous medium region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability.

8. The system for determining the permeability of the porous medium region in a fractured-vuggy reservoir according to claim 7, wherein, the step of inputting the input parameters into the porous medium region filling model to obtain the inlet-outlet pressure difference, outlet flow rate, and equivalent permeability includes: Statistically calculate the flow rate in the X direction of each face in the porous medium region filling model at the outlet to obtain the outlet flow rate. More specifically, use Equation (3) to obtain the outlet flow rate from the statistically calculated flow rate in the X direction of each face; In Equation (3), Ω out is the outlet boundary condition, v f，x is the flow velocity of the boundary grid f in the x direction, and A f is the boundary area of the boundary grid f; the flow velocity of the boundary grid f in the x direction and the boundary area of the boundary grid f are obtained from the porous medium region filling model; Statistically calculate the fluid pressure at the inlet, and use the volume-weighted average method to calculate the average pressure at the inlet. More specifically, use Equation (4) to calculate the average pressure at the inlet: In Equation (4), Ω in is the inlet boundary condition, P f is the pressure parameter of grid f on the boundary, and V f is the volume fraction of boundary grid f; Calculate the equivalent permeability according to Equation (5) and Equation (6), In Equation (5), μ is the fluid viscosity, p is the fluid static pressure, μ is the phase viscosity, A is the area of the porous medium region, and k is the permeability; In Equation (6), A Ω is the boundary area, Q out is obtained from Equation (3), P in is the average pressure at the inlet, obtained from Equation (4), μ is the fluid viscosity, k * is the equivalent permeability.

Images