CN109389684B - Numerical simulation method for equivalence of zonal weighting media of fracture-cave oil reservoir - Google Patents
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Abstract
The invention provides a numerical simulation method for the equivalence of zone weighting media of a fracture-cavity type oil reservoir. The method not only utilizes the result of geological modeling, but also completes the equivalent of the weighting medium in different areas, and realizes the slot-hole simulation of the oil field level scale; the medium equivalent weight of the region can be selected according to the actual condition of the region, and the technical problems that the numerical simulator cannot be converged or the time step used for convergence is small and the calculation time is too long due to large permeability level difference caused by uniform medium weight of the simulation region are solved well.
Description
Technical Field
The invention belongs to the field of oil and gas field development, and particularly relates to a numerical simulation method for zonal weighting medium equivalence of a fracture-cavity type oil reservoir.
Background
The existing numerical simulation methods of fracture-cavity oil reservoirs mainly comprise two types, namely a method based on a discrete fracture-cavity network model, wherein matrix rock blocks and a fracture system are used as seepage areas, a karst-cavity system is used as a free flow area, a coupling mathematical model is established, seepage-free flow coupling flow characteristics are carved, for example, a two-phase flow mathematical model of seepage-free flow coupling is deduced and established through two scale upgrading based on a volume average method, and a set of medium equivalent flow simulation theory and method are established based on the discrete fracture-cavity network model so as to be suitable for flow simulation research of oil field level large scale. One is a method based on a multi-medium concept, which is to equate a fracture cavern medium into a single, double or triple continuous medium, for example, a seepage model of a carbonate rock triple-medium oil reservoir is established on the basis of a seepage mechanics theory, and triple-medium numerical simulation software is written.
The two simulation methods have advantages and disadvantages, and although the discrete fracture-cavity network model truly describes the geological distribution characteristics of the fracture-cavity and the influence of the fracture-cavity on the fluid flow to a certain extent, the numerical simulation has a huge calculation amount due to huge data volume of the fracture-cavity, so that when the discrete fracture-cavity network model is used for simulating the three-dimensional solid oil deposit, an equivalent mode is required to be searched on the basis of the discrete fracture-cavity network model. The current equivalent simulation method assumes that cracks and karst caves are highly developed and uniformly distributed, the sizes of the cracks and the karst caves cannot be overlarge, and the biggest defect of the equivalent simulation method adopted in conventional commercial software is that equivalent weight of a simulation area is uniformly set, and the equivalent weight is applied to the whole simulation area.
For fracture-cavity oil reservoirs with various medium combination types, namely, areas with the characteristics of dual mediums of pores and cavities and areas with the characteristics of triple mediums of pores and cavities exist, and single cracks or solution cavity mediums can exist, so that the multiple mediums with uniform specific weight are difficult to be used for equivalence. For example, a region with only solution pore development and a region with more developed fracture solution pores, the conventional commercial software can only simulate by using an integral dual medium model, and the solution pore development region must be approximated by a very small fracture permeability, which causes too large permeability level difference, so that the numerical simulator cannot converge or the time step for convergence is very small, and the calculation time is too long.
Disclosure of Invention
In order to solve the technical problems that a numerical simulator cannot be converged or the time step for convergence is very small and the calculation time is too long due to large permeability level difference caused by uniformly setting the weight of a simulation area in the prior art, the invention provides a numerical simulation method for regional variable weight medium equivalence of an oil fracture-cavity oil reservoir, which has the following specific scheme:
a numerical simulation method for the equivalence of weighting media in different regions of a fracture-cavity oil reservoir is characterized by establishing a geological model, dividing the geological model into grids, fusing pore permeability attributes according to the established geological model, and selecting the equivalent weighting number of the media in different regions.
Preferably, a large karst cave region and a large fracture region in the fracture-cavity type oil reservoir are selected, and medium equivalent weight is selected in other regions except the large karst cave region and the large fracture region in the fracture-cavity type oil reservoir according to medium development conditions.
Preferably, the large cavern region is a region only containing large cavern media with the diameter larger than 1 meter, and the large crack region is a region only containing large crack media with the crack sheet opening larger than 0.1 mm.
Preferably, selecting an area which only develops any single medium in cracks, karst caves and solution holes as a single medium equivalent area in other areas of the fracture-cave type oil reservoir except a large karst cave area and a large fracture area;
selecting a region in which only cracks and karst caves simultaneously develop and a region in which only cracks and karst caves simultaneously develop as a dual-medium equivalent region from other regions of the fracture-cave type oil reservoir except a large karst cave region and a large fracture region;
and selecting the regions which only simultaneously develop cracks, karst caves and solution holes as triple medium equivalent regions in other regions of the fracture-cave type oil reservoir except the large karst cave region and the large fracture region.
Preferably, adjacent grids are connected through a medium for controlling global flow so as to determine the connection relationship between the adjacent grids.
Preferably, a grid of dual medium equivalent regions and triple medium equivalent regions that control the globally flowing medium to be fissures;
the single dense medium equivalent region, the large cavern region and the large fracture region are grids, and the medium controlling the global flow is the medium in the region.
Preferably, the flow relationship between the adjacent grids is calculated by a finite volume method according to the connection relationship between the adjacent grids.
Preferably, in the process of calculating the flow relationship between the adjacent grids, the fluidity is calculated by the following formula:
wherein k isrβIs the relative permeability of the beta phase, pβIs the density of the beta phase, muβFor the viscosity of the beta phase, the subscript ij +1/2 indicates that the property parameters used for calculation in parentheses are all weighted averages of the property parameters of the adjacent grid i and grid j;
the conductivity was calculated by the following formula:
wherein,
is a weighted average of the absolute permeabilities of the neighboring meshes i and j, AijIs the contact area of the adjacent grid i and grid j. di，djRespectively the distance from the central point of each of the adjacent grids i and j to the grid contact surface;
the formula for the weighted average of absolute permeability is as follows:
wherein KiIs the absolute permeability of grid i, KjIs the absolute permeability of grid j.
Preferably, quasi-steady state cross flow is adopted among multiple media in the grids to control conduction, and seepage is adopted among the grids to control global flow.
Preferably, a geological model is built by using a classification modeling method.
Compared with the prior art, the invention provides a numerical simulation method for the zonal weighting medium equivalence of the fracture-cavity oil reservoir, which comprises the steps of establishing a geological model, meshing the geological model, fusing the pore permeability attribute according to the established geological model, and regionally selecting the medium equivalent weight. The method not only utilizes the result of geological modeling, but also completes the equivalent of the weighting medium in different areas, and realizes the slot-hole simulation of the oil field level scale; the medium equivalent weight of the region can be selected according to the actual condition of the region, and the technical problems that the numerical simulator cannot be converged or the time step used for convergence is very small and the calculation time is too long due to the large permeability difference caused by the uniform medium weight of the simulation region are solved well.
Drawings
The invention will be described in more detail hereinafter on the basis of embodiments and with reference to the accompanying drawings. Wherein:
FIG. 1 is a flow chart of a method of an embodiment of the present invention;
FIG. 2 is a schematic diagram of the distribution of the variable heavy medium equivalent regions of a fracture-cavity reservoir in an embodiment of the present invention;
3 a-3 b are schematic diagrams of the boundary grid connection relationship of a fracture-cavity reservoir in an embodiment of the invention;
FIGS. 4 a-4 b are schematic diagrams illustrating flow relationships and related parameters between adjacent grids of a fractured-vuggy reservoir according to an embodiment of the invention;
FIG. 5 is a distribution and weighted-medium equivalent area distribution plot for a given reservoir injection and production well numerically modeled in an example of the present invention;
fig. 6 is a comparison graph of oil production curves and water production curves of four production wells obtained by the equivalent numerical simulation of the variable weight medium in the embodiment of the invention, wherein fig. 6a is the comparison graph of the oil production curves, and fig. 6b is the comparison graph of the water production curves.
In the drawings, like parts are designated with like reference numerals, and the drawings are not necessarily to scale.
Detailed Description
The invention will be further described with reference to the accompanying drawings.
The embodiment provides a method for simulating the regional variable-weight medium equivalence numerical simulation of a fracture-cavity oil reservoir. The method not only utilizes the result of geological modeling, but also completes the equivalent of the weighting medium in different areas, and realizes the slot-hole simulation of the oil field level scale; the medium equivalent weight of the region can be selected according to the actual condition of the region, and the technical problems that the numerical simulator cannot be converged or the time step used for convergence is small and the calculation time is too long due to large permeability level difference caused by uniform medium weight of the simulation region are solved well.
Fig. 1 shows a flow chart of the method of the present embodiment, and a geological model is established for a fracture-cavity type oil reservoir that needs to be numerically simulated, preferably, the geological modeling method adopted in the present embodiment is a classification modeling method, which is an existing mature modeling method in the field, and a relatively accurate geological model can be obtained by using the method. For the gridding of the established geological model, preferably, an unstructured grid is used in the embodiment. Quasi-steady state cross flow is adopted among multiple media in grids to control conduction, and seepage is adopted among the grids to control global flow. A large karst cave region and a large fracture region are selected from a fracture-cavity type oil reservoir needing numerical simulation, the preferable large karst cave region in the embodiment is a region only containing large karst cave media with the diameter larger than 1 meter, and the large fracture region is a region only containing large fracture media with the fracture piece opening larger than 0.1 mm. Due to the fact that the medium size in the large cavern area and the large crack area is large, the influence of other parameters different from other areas needs to be considered when the flow relation between grids in the area is calculated, and equivalent processing is not needed in the area. The fracture-vug type oil reservoir is different from other areas except a large cavern area and a large fracture area, the sizes of the caverns and the fractures in the other areas are relatively small, even karst caves with extremely small sizes are also provided, the karst caves with extremely small sizes are called as caverns, and for the classification of the caverns, the classification standard of the field is universal. In this embodiment, the cavern medium for weight-changing medium equivalence refers to a cavern with a diameter of 1 meter or less and not falling within the size range of the cavern, and the fracture medium for weight-changing medium equivalence refers to a fracture with a fracture piece opening of 0.1mm or less. The equivalent treatment is carried out in other areas except a large karst cave area and a large fracture area in the fracture-cave type oil reservoir. Therefore, a large karst cave region and a large fracture region in the fracture-cavity type oil reservoir needing numerical simulation are selected, other regions except the large karst cave region are subjected to variable weight medium equivalence, and the equivalent weight number of the medium is selected in different regions, so that the numerical simulation result is closer to the actual situation. The establishment of the flow relationships between the internal grids of either the large cavern region or the large fracture region is a mature prior art for those skilled in the art and will not be described in detail herein. The medium equivalent weight mentioned in this embodiment refers to the number of types of media used when performing equivalent processing on a certain region, and when performing equivalent processing on a large cavern region and other regions outside the large fracture region, a certain region only develops a medium, i.e., a cavern, and the region is a single heavy medium equivalent region and is subjected to equivalent processing through a cavern medium. In a similar way, if a certain region only develops a medium of a crack, the region is a single heavy medium equivalent region, and equivalent treatment is carried out through the crack medium; and (3) only developing a medium of the lysopore in a certain area, wherein the area is a single heavy medium equivalent area and is subjected to equivalent treatment through the lysopore medium. When a certain region only develops two mediums, namely a crack medium and a karst cave medium, the region is a dual-medium equivalent region, and equivalent treatment is carried out through the crack medium and the karst cave medium; only two mediums, namely a crack medium and a pore dissolving medium, are developed in a certain area at the same time, and the area is a double-medium equivalent area and is subjected to equivalent treatment by the crack medium and the pore dissolving medium together; the double-medium equivalent region does not have the condition that only two mediums, namely karst cave and karst pore, are developed simultaneously. When a certain region only develops three mediums, namely a crack medium, a karst cave medium and a karst pore medium, the region is a triple medium equivalent region, and equivalent treatment is carried out through the crack medium, the karst cave medium and the karst pore medium. In this embodiment, the single mediator equivalent region, the double mediator equivalent region and the triple mediator equivalent region determined according to the development condition of the mediator are both referred to as a variable mediator equivalent region. Fig. 2 shows the distribution of the heavy medium equivalent regions in a fractured-vuggy reservoir, as shown in fig. 2, wherein a region 1 is a karst cave, solution pore and fracture triple medium equivalent region, a region 2 is a fracture single medium equivalent region, a region 3 is a fracture and solution pore double medium equivalent region, a region 4 is a fracture and solution cave double medium equivalent region, and a region 5 is a solution cave single medium equivalent region. The five media are characterized by porosity and permeability in numerical simulation, different media correspond to different porosity ranges and permeability ranges, and the permeability level difference corresponding to different media is large. A single dense medium equivalent zone, the medium of any lattice thereof being equivalently characterized by the porosity and permeability of the medium, e.g., the medium of any lattice of a cavernous single dense medium zone being equivalently characterized by the porosity and permeability of the cavernous, the rest being similar. The media of any grid of the multi-media equivalent zone is jointly equivalently characterized by the porosity and permeability of the different media, e.g., the media of any grid of the triple-media zone where the cavern, the pore, and the fracture coexist is jointly equivalently characterized by the porosity and permeability of the cavern, the pore, and the pore. The grid of the large karst cave area is characterized by the porosity and the permeability of a large karst cave medium, and the grid of the large fracture area is characterized by the porosity and the permeability of a large fracture medium. As can be seen by comparing the permeability of each medium in the table 1, the permeability of different media is not in the same order of magnitude, and the level difference is large. In the examples shown in table 1, the fracture permeability was 10 times the cavern permeability, and the cavern permeability was about 9 times the cavern permeability.
After the equivalent weight of the medium is selected in different areas, the connection relation between the adjacent grids is set up, and the adjacent grids are connected through the medium controlling the global flow to determine the connection relation between the adjacent grids. Preferably, a grid of dual medium equivalent regions and triple medium equivalent regions that control the globally flowing medium to be fissures; the single dense medium equivalent region, the large cavern region and the large fracture region are grids, and the medium controlling the global flow is the medium in the region. Specifically, the grid of the karst cave single heavy medium equivalent region controls the medium flowing globally to be the karst cave; controlling the globally flowing medium to be a crack by the grid of the crack single heavy medium equivalent area; the grid of the single heavy medium equivalent area of the solution hole controls the medium flowing globally to be the solution hole; the grid of the large karst cave area controls the medium flowing globally to be a large karst cave medium; the grid of the large fracture area controls the medium flowing globally to be a large fracture medium; the grid of the crack and karst cave double medium equivalent area controls the medium flowing globally to be a crack; the grid of the crack and dissolved hole dual medium equivalent area controls the medium flowing globally to be a crack; the grids of the equivalent areas of the three mediums of the cracks, the karst caves and the solution holes control the medium flowing globally to be the cracks. Some examples of the connection relationship between grids are illustrated in conjunction with fig. 3 according to the connection principle between two adjacent grids. Fig. 3(a) is a mesh division diagram in the geological model, and fig. 3(b) is a schematic diagram in which mesh planes in the model are laid out in order to facilitate the description of the connection relationship between meshes, and as shown in fig. 3(b), a single cube representing a solution pore, a solution cavity, and a fracture is drawn only for the purpose of clearly expressing a medium in the mesh that has a connection relationship with the remaining meshes, and does not mean that 2 or 3 meshes are subdivided again in the mesh 9 and the mesh 8 according to the number of medium weights. The boundary grid refers to a grid at the boundary position of two adjacent regions, in fig. 3(a), a grid 6 in fig. 3(b) is a boundary grid of a single dissolved pore medium equivalent region, a grid 9 is a boundary grid of a dissolved pore and crack dual medium equivalent region, and the grid 6 is connected with a crack medium which controls global flow in the grid 9 through a dissolved pore medium which controls global flow, so that the connection between the grid 6 and the grid 9 is realized; the grid 8 is a boundary grid of a triple medium equivalent region of a solution hole, a crack and a solution cavity, and the grid 9 is connected with a crack medium which controls the global flow in the grid 8 by controlling the global flow of the crack medium, so that the connection between the grid 9 and the grid 8 is realized; the grid 7 is a boundary grid of a karst cave single heavy medium equivalent region, and the grid 8 is connected with the karst cave medium which controls the global flow in the grid 7 through controlling the global flow of the crack medium, so that the connection between the grid 8 and the grid 7 is realized. Also for example, the grids in the triple-medium equivalent region are connected through a crack medium for controlling global flow to realize connection between grids; the triple medium equivalent area boundary grids are connected with the large karst cave medium which controls the global flow by controlling the global flow of the crack medium and the large karst cave area boundary grids to realize the connection among the grids; the triple medium equivalent zone boundary grids realize the connection among the grids by connecting the crack medium for controlling the global flow with the large crack medium for controlling the global flow of the large crack zone boundary grids. The establishment of fluid flow relationships within large fracture zones or large cavern zones is prior art and is not within the scope of the present discussion.
According to the connection relation between any adjacent grids determined by the method, the flow relation between the adjacent grids is calculated by using a finite volume method. The flow relationships between any adjacent cells can be calculated by finite volume methods. It has been mentioned above that the establishment of the flow relationship inside the fluid large cavern region or large fracture region is a mature prior art, and the present embodiment calculates only the flow relationship between other grids, including the flow relationship between the boundary grid of the large cavern or large fracture region and the boundary grid of the adjacent weighting medium region, the flow relationship between the grids inside the weighting medium region, and the flow relationship between the boundary grids of the adjacent weighting medium region.
In all formulas of the present embodiment, n represents the nth time, and n cannot be interpreted as the nth power of a certain variable. In all formulas of this embodiment, i and j represent grid i and grid j, respectively, and grid i and grid j are adjacent grids.
The flow equation between any adjacent cells is as follows:
in the formula (1), the reaction mixture is,
for the mass of the β phase at the next time point to be solved, i.e., at the time point of n +1, in the embodiment of the present invention, the β phase, i.e., the fluid for which the flow equation is calculated, for example, the flow relationship of oil between adjacent grids is calculated, and then the mass of the β phase is the mass of the oil phase;
quality of beta-phase for grid i at the current time point, i.e. n time pointN represents a current time point; in the formula of the embodiment of the invention, the superscripts n and n +1 only represent time points and cannot be interpreted as the power n or the power n + 1; vi is the volume of grid i; Δ t is the time step; etaiIs a set of grids j adjacent to grid i;
a mass flow term of beta phase between adjacent grid i and grid j at the moment n + 1;
is the source and sink term of the beta phase in the grid i at the moment n + 1.
For intercrystalline Darcy seepage, the mass flow term F in equation (1)β,ijThat is, the flow relationship between any two adjacent grids i, j is expressed as follows:
Fβ,ij＝λβ,ij+1/2γij[ψβj-ψβi] (2)
in the formula (2), λβ,ij+1/2Is the fluidity of the beta phase, gammaijPsi i is the pressure potential of grid i and psi j is the pressure potential of grid j, for conductivity coefficients. Wherein the expression of fluidity is:
in the formula (3), krβIs the relative permeability of the beta phase, pβIs the density of the beta phase, muβFor the viscosity of the beta phase, the subscript ij +1/2 indicates that the property parameters used in the calculations within the brackets are all weighted averages of the adjacent grid property parameters. In this embodiment, the neighboring grids are grid i and grid j, and the parameter k is usedrβFor example, it takes the value of the weighted average of the relative permeability of the beta phase in grid i and the relative permeability of the beta phase in grid j. The rest parameters in parentheses in the formula (3) and so on.
The expression of the conductivity in the formula (2) is:
in the formula (4), the reaction mixture is,
is a weighted average of the absolute permeabilities of grid i and grid j, AijIs the contact area of grid i and grid j. di，djRespectively, the distance from the central point of each of the grids i and j to the grid contact surface.
Weighted average of absolute permeabilities of grid i and grid j
The expression of (a) is:
in the formula (5), KiIs the absolute permeability of grid i, KjIs the absolute permeability of grid j.
Fig. 4(a) and 4(b) show the flow relationships between the grids and some of the relevant parameters used in the calculation in the process of establishing the flow relationships. In the figure xi，xjThe respective center points of grid i and grid j, and the remaining parameters are explained with reference to the above formula.
The above explains the parameters of the flow equation between any adjacent grids. Specifically, taking oil as an example, the flow equation of oil between any two adjacent grids is expressed as follows:
phi is porosity; soIs the oil saturation;
is the density of the oil phase under reservoir conditions; viIs the volume of the grid; Δ t is the time step; lambda [ alpha ]oIs the fluidity of the oil phase; gamma rayijIs the conductivity coefficient; psiβi、ψβiThe pressure potential of the beta phase in grid i and the pressure potential of the beta phase in grid j are respectively,
is the source-sink term, η, of the beta-phase within the grid i at time n +1iIs a set of grids j adjacent to grid i; the meaning of the subscript ij +1/2 refers to the explanations in formula (3).
And (3) changing the oil phase parameter in the formula (6) into the corresponding water phase parameter according to the expression of the water phase flow equation between any adjacent grids.
The flow relationship of the fluid among the grids is obtained, so that the oil and water producing conditions of the oil reservoir can be accurately simulated.
Fig. 5 shows that the method provided in the above embodiment is used to perform numerical simulation on a certain oil reservoir, build a geological model, and grid the geological model, wherein the grid number is 40 × 5. The oil reservoir area for numerical simulation adopts a one-injection four-production well model, an injection well WEL1 is positioned in the center of a square area for numerical simulation of the oil reservoir, four production wells are positioned at four corners of the oil reservoir and are respectively a well WEL2, a well WEL3, a well WEL4 and a well WEL 5. The injection amount of the injection well is fixed, and the bottom hole flow pressure production of the production well is fixed. The periphery of the injection well is divided into four regions according to the medium development condition, namely a fracture and solution pore double medium equivalent region 10, a fracture single heavy medium equivalent region 11, a fracture and solution pore double medium equivalent region 12 and a fracture, solution pore and solution pore triple medium equivalent region 13. The parameters used in the numerical reservoir simulation are shown in table 1, and the results of the final numerical simulation of the oil production curves and the water production curves of the four production wells of the reservoir are shown in fig. 6, wherein fig. 6a is a comparison graph of the oil production curves of the four production wells obtained by the numerical simulation, and fig. 6b is a comparison graph of the water production curves of the four production wells obtained by the numerical simulation.
TABLE 1 parameters for simulation calculation of equivalent values of variable weight media
While the invention has been described with reference to a preferred embodiment, various modifications may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In particular, the various features mentioned in the various embodiments may be combined in any combination as long as there is no logical or structural conflict. It is intended that the invention not be limited to the particular embodiments disclosed, but that the invention will include all embodiments falling within the scope of the appended claims.
Claims (8)
1. A numerical simulation method for the equivalence of weighting media in a fracture-cavity oil reservoir sub-region is characterized in that a geological model is built, a grid is divided for the geological model, the fusion of pore permeability attributes is carried out according to the built geological model, and the equivalent weighting number of the media is selected in a sub-region manner; selecting a large karst cave region and a large fracture region in the fracture-cavity type oil reservoir, and selecting medium equivalent weight numbers in other regions except the large karst cave region and the large fracture region in the fracture-cavity type oil reservoir according to medium development conditions;
selecting an area which only develops any single medium in cracks, karst caves and solution holes as a single medium equivalent area in other areas of the fracture-vug type oil reservoir except a large karst cave area and a large fracture area;
selecting a region in which only cracks and karst caves simultaneously develop and a region in which only cracks and karst caves simultaneously develop as a dual-medium equivalent region from other regions of the fracture-cave type oil reservoir except a large karst cave region and a large fracture region;
and selecting the regions which only simultaneously develop cracks, karst caves and solution holes as triple medium equivalent regions in other regions of the fracture-cave type oil reservoir except the large karst cave region and the large fracture region.
2. The method according to claim 1, wherein the large cavern region is a region only containing large cavern media with the diameter larger than 1 meter, and the large fracture region is a region only containing large fracture media with the fracture piece opening larger than 0.1 mm.
3. The method of claim 1, wherein adjacent grids are connected by a medium that controls global flow to determine the connection relationship between the adjacent grids.
4. The method of claim 3, wherein the grid of dual medium equivalent regions and triple medium equivalent regions that control the globally flowing medium is a fracture;
the single dense medium equivalent region, the large cavern region and the large fracture region are grids, and the medium controlling the global flow is the medium in the region.
5. The method of claim 3, wherein the flow relationship between adjacent grids is calculated using a finite volume method based on the connection relationship between the adjacent grids.
6. The method of claim 5, wherein in calculating the flow relationship between adjacent grids, the fluidity is calculated by the following formula:
wherein k isrβIs the relative permeability of the beta phase, pβIs the density of the beta phase, muβFor the viscosity of the beta phase, the subscript ij +1/2 indicates that the property parameters used for calculation in parentheses are all weighted averages of the property parameters of the adjacent grid i and grid j;
the conductivity was calculated by the following formula:
wherein,
is a weighted average of the absolute permeabilities of the neighboring meshes i and j, AijIs the contact area of the adjacent grid i and grid j, di，djRespectively the distance from the central point of each adjacent grid i and grid j to the grid contact surface;
the formula for the weighted average of absolute permeability is as follows:
wherein KiIs the absolute permeability of grid i, KjIs the absolute permeability of grid j.
7. The method of claim 1, wherein quasi-steady state cross flow is used between multiple media in a grid to control conduction, and seepage is used between grids to control global flow.
8. The method of claim 1, wherein the geologic model is created using a classification modeling method.
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