A method for evaluating the accuracy of acid fracturing numerical simulation results by following fractures and finding holes

Abstract

The method for evaluating the accuracy of the acid fracturing numerical simulation results for finding fractures and cavities in the present invention involves establishing a fracture-cavity type three-dimensional stress field geological model capable of performing acid fracturing numerical simulations, conducting acid fracturing numerical simulation calculations for finding fractures and cavities in this model, determining the number of communicated cavities, calculating the theoretical stable liquid supply time at a specified production rate based on the reservoir volume of the communicated cavities; and comparing the theoretical stable liquid supply time with the stable liquid supply time in the actual production process, thereby raising the accuracy of the acid fracturing numerical simulation for finding fractures and cavities from qualitative to quantitative, and further improving the accuracy of the acid fracturing numerical simulation for finding fractures and cavities.

Description

Technical Field

[0001] The present invention relates to the technical field of development of fractured-vuggy reservoirs, and particularly to a method for evaluating the accuracy of acid fracturing numerical simulation results for finding vugs along fractures. Background Art

[0002] In China, oil and gas resources are relatively abundant, and most of them are stored in carbonate reservoirs. The prominent feature of carbonate reservoirs is the development of a large number of natural fractures and vugs. Exploration and development practices have shown that vugs are the storage spaces for oil and gas resources, while natural fractures are the main seepage channels for oil and gas. For fractured-vuggy oil and gas reservoirs, the key to the success of reservoir stimulation lies in whether the fractures can communicate with the vug reservoir bodies, and numerical simulation is an effective means to study the communication between fractures and vugs.

[0003] At present, there have been a large number of studies on acid fracturing numerical simulation of fractured-vuggy carbonate reservoirs, but generally they are for the mechanism study of single fractures and single vugs, which are not applicable to actual engineering situations. At the same time, the accuracy of acid fracturing numerical simulation results is generally judged by the microseismic method, that is, after actual construction, whether the fractures communicate with the vugs is judged by microseismic signals. The microseismic signals are greatly affected by reservoir heterogeneity structures such as fractures and vugs, and often cannot accurately represent the actual communication situation. Therefore, the evaluation results of this accuracy evaluation method are severely limited by the receiving and processing accuracy of microseismic signals, and this evaluation method has a high cost.

[0004] Therefore, it is necessary to propose a new numerical simulation result evaluation method for finding vugs along fractures in fractured-vuggy carbonate reservoirs. Summary of the Invention

[0005] The present invention provides a method for evaluating the accuracy of acid fracturing numerical simulation results for finding vugs along fractures, which is used for evaluating the acid fracturing numerical simulation results of carbonate reservoirs. By comparing the theoretical stable liquid supply time with the actual stable liquid supply time, the accuracy of acid fracturing numerical simulation for finding vugs along fractures is improved from qualitative to quantitative, thereby improving the accuracy of acid fracturing numerical simulation for finding vugs along fractures.

[0006] The technical solution of the present invention is as follows:

[0007] A method for evaluating the accuracy of acid fracturing numerical simulation results for finding vugs along fractures includes the following steps:

[0008] S1. In the finite element processing software, establish a three-dimensional geological model of the target fractured-vuggy oil and gas reservoir.

[0009] S2. According to the collected in-situ stress field data of the target fractured-vuggy oil and gas reservoir, establish a three-dimensional stress field distribution model of the target fractured-vuggy oil and gas reservoir based on the three-dimensional geological model in the finite element processing software.

[0010] S3. In the three-dimensional stress field distribution model, mark the positions of the solution caves and the oil and gas wells in the reservoir of the target fractured-vuggy oil and gas reservoir to form a three-dimensional stress field distribution model containing natural fractures and solution caves, and endow the three-dimensional stress field distribution model containing natural fractures and solution caves with a multi-scale mathematical model including a Darcy-scale model and a pore-scale model to form a fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation;

[0011] S4. Calculate or obtain the actual stable liquid supply time at a specified production rate;

[0012] S5. In the fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation, conduct a numerical simulation calculation of acid fracturing for finding vugs along fractures under the same production construction conditions as the actual stable liquid supply time at the specified production rate in S4, and determine the theoretical stable liquid supply time at the specified production rate;

[0013] S6. Judge the accuracy of the numerical simulation results of acid fracturing for finding vugs along fractures; if the absolute value of the relative error between the theoretical stable liquid supply time and the actual stable liquid supply time is within 5%, the numerical simulation results are accurate; if the absolute value of the relative error is greater than 5%, the numerical simulation results are inaccurate.

[0014] Preferably, in S4, when conducting a numerical simulation calculation of acid fracturing for finding vugs along fractures under different production construction conditions, after inputting the corresponding values under the actual production construction conditions, the fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation forms a main fracture and opens natural fractures, and the main fracture and the opened natural fractures communicate with the solution caves. After the numerical simulation calculation of acid fracturing for finding vugs along fractures is completed, the solution caves that can be communicated are finally determined.

[0015] Preferably, the theoretical stable liquid supply time is the ratio of the total volume of all solution caves communicated in the acid fracturing numerical simulation calculation to the specified production rate.

[0016] Preferably, the actual stable liquid supply time at the specified production rate refers to the time when, under the actual production construction conditions the same as those of the acid fracturing numerical simulation calculation, actual production is carried out at the specified production rate and the specified production rate is kept constant.

[0017] Preferably, the relative error between the theoretical stable liquid supply time and the actual stable liquid supply time is the ratio of the absolute value of the difference between the theoretical stable liquid supply time and the actual stable liquid supply time to the actual stable liquid supply time.

[0018] Preferably, in S3, a multi-scale mathematical model including a Darcy-scale model and a pore-scale model is given to the three-dimensional stress field distribution model to form a fracture-cavity three-dimensional stress field geological model capable of performing acid fracturing numerical simulation, including the following steps: S3.1 Establish a Darcy-scale model: The Darcy-scale model is used to describe a model of porous media from centimeter scale to micrometer scale, and acid fluid is Darcy flow in porous media from centimeter scale to micrometer scale;

[0019] (1) Acid fluid flow in the matrix

[0020] The acid fluid is injected into the formation at a certain speed. Under the macroscopic movement (convection) and concentration gradient (diffusion) of hydrogen ions in the acid fluid, mass transfer occurs from the pore medium fluid to the carbonate rock surface to react, thereby changing the formation porosity and permeability. The flow of acid fluid in the matrix formation is controlled by Darcy's law:

[0021]

[0022] The fluid pressure distribution is controlled by the continuity equation of incompressible fluid:

[0023]

[0024] The concentration distribution of hydrogen ions in the fluid is controlled by the convective-diffusion equation. The convective-diffusion equation has two cases. Case 1 is that the acid fluid does not completely dissolve the rock (ε < 1), and case 2 is that the acid fluid completely dissolves the rock (ε = 1);

[0025] For the convective-diffusion equation in the case where the acid fluid does not completely dissolve the rock (ε < 1), the consumption of hydrogen ions on the rock surface and the change of porosity need to be considered:

[0026]

[0027] For the convective-diffusion equation in the case where the acid fluid completely dissolves the rock (ε = 1), the consumption of hydrogen ions on the rock surface and the change of porosity do not need to be considered:

[0028]

[0029] In the formula, is the Darcy velocity vector, m / s; k is the formation permeability, m 2 ; μ is the acid fluid viscosity, Pa·s; P is the acid fluid pressure, Pa; ε is the formation porosity; t is the reaction time, s; C f is the acid fluid concentration in the rock pores, mol / m 3 ; De is the acid fluid diffusion tensor, m 2 / s; k c is the local mass transfer coefficient of the acid fluid, m / s; a vis the pore area per unit volume of rock, m 2 / m 3 ; C s is the acid concentration on the rock surface, mol / m 3 ; α is the mass of rock that can be dissolved by per mole of acid, kg / mol; ρ s is the rock density, kg / m 3 ;

[0030] (2) Acid flow in fractures

[0031] The flow of acid in natural fractures and in the matrix corresponds to different mechanisms. The flow in natural fractures is free flow, and the flow in the matrix is porous media seepage controlled by Darcy's law. According to the concept of equivalent permeability, the natural fractures in the flow of acid are regarded as regions with relatively high permeability. Using the above mathematical model, the dissolution phenomenon of acid in fractured formations is studied, and the natural fractures that have a greater impact on the pressure field are meshed more densely to accelerate the calculation speed and ensure the convergence of the calculation;

[0032] S3.2 Establish a pore-scale model to provide parameter support including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient for the Darcy-scale model;

[0033] S3.3 Mesh the constructed three-dimensional stress field distribution model containing natural fractures and solution cavities, and assign the parameters calculated by the multi-scale mathematical model to the grid cells and nodes of the three-dimensional stress field distribution model containing natural fractures and solution cavities; Obtain a three-dimensional stress field geological model of fractures and solution cavities that can perform acidification numerical simulation after meshing and assigning attribute parameters.

[0034] Preferably, in S3.2, when the pore-scale model provides parameter support including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient for the Darcy-scale model, the relationships among permeability, pore radius, specific surface area, and porosity include:

[0035] The formation permeability, pore radius, and specific surface area are directly related to porosity. The relationships among formation permeability, pore radius, specific surface area, and porosity are described by empirical formulas as:

[0036]

[0037] In the formula, ε (0 < ε < 1), k, r p , a v are porosity, permeability, pore radius, and specific surface area respectively; ε 0 , k 0 , r 0 , a 0They are the initial porosity, permeability, pore radius, and specific surface area respectively; β is a constant related to the pore structure, and β = 1 is taken.

[0038] Generally, the flow velocity of the acid fluid in the formation is very small and can be regarded as laminar flow. The fracture can be regarded as a relatively thin circular pipe, and the circular pipe laminar flow formula is used to examine the flow rate.

[0039]

[0040] In the formula, Q is the flow rate, cm3 / s; ΔP is the driving pressure difference, 0.1 MPa; D is the fracture diameter, cm; A is the cross-sectional area, cm 2 ; μ is the fluid viscosity, Pa·s; L is the fracture length, cm.

[0041] The flow rate calculated using Darcy's formula is as follows:

[0042]

[0043] When the fracture width is taken as 0.2 cm, the equivalent permeability corresponding to the natural fracture calculated based on formula (6) and formula (7) is k = D 2 / 32 = 125×10 3 μm 2 ; Let the porosity of the natural fracture be ε max = 0.999 (ε 0 = 0.05, k 0 = 0.32), substituting into formula (5) to obtain the permeability K:

[0044]

[0045] k and K are of the same order of magnitude. That is, from the perspective of flow resistance, it is reasonable to equivalent the natural fracture with a width of 0.2 cm to the matrix with a porosity of 0.999. For natural fractures with a width exceeding 0.2 cm, since the permeability of the natural fracture is already quite high compared to the matrix, at this time, the fracture width is not a factor restricting the fracture conductivity (the product of permeability and fracture width), so the natural fracture can be equivalent to a fracture with a width of 0.2 cm for treatment.

[0046] Preferably, in S3.2, in the parameter support provided by the pore-scale model for the Darcy-scale model including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient, due to the sedimentary compaction effect of the formation, the pore structure is different in the horizontal and vertical directions. The diffusion tensor includes the horizontal diffusion tensor D eX and the vertical diffusion tensor D eT ; The diffusion tensor is related to the molecular diffusion coefficient Dm, pore structure, flow velocity, etc. Among them, the Péclet number is a dimensionless number representing the ratio of convection to diffusion.

[0047]

[0048] The diffusion tensor is divided into the horizontal diffusion tensor D eX and the vertical diffusion tensor D eT The formula for which is:

[0049] D eX = (α os + λx·Pe P )Dm (10)

[0050] D eT = (α os + λ T ·Pe P )Dm (11)

[0051] In the formula, α os is a constant related to the pore structure, taking α os = 0.5; λx = 0.5 is obtained from the core diffusion experiment, λ T = 0.1; Dm is the molecular diffusion coefficient; Pe p is the Péclet number.

[0052] Preferably, in S3.2, the pore-scale model provides parameter support including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient for the Darcy-scale model. Among them,

[0053] The calculation method of the mass transfer coefficient k c is as follows:

[0054]

[0055] In the formula, Sh ∞ is the asymptotic Sherwood number; Re p is the pore-scale Reynolds number, Sc is the Schmidt number,

[0056] The advantages of the present invention over the prior art are as follows: The method for evaluating the accuracy of acid fracturing numerical simulation for finding fractures and cavities is used to evaluate the acid fracturing numerical simulation results for finding fractures and cavities in carbonate reservoirs. By comparing the theoretical stable liquid supply time with the actual stable liquid supply time, the accuracy of acid fracturing numerical simulation for finding fractures and cavities is improved from qualitative to quantitative, thereby improving the accuracy of judging the acid fracturing numerical simulation results for finding fractures and cavities. At the same time, the method for evaluating the accuracy of acid fracturing numerical simulation for finding fractures and cavities of the present invention, based on the existing actual production and construction conditions, assigns the condition data of actual production at a specified production rate to the three-dimensional stress field geological model of fractures and cavities that can perform acid fracturing numerical simulation, and conducts acid fracturing numerical simulation calculation for finding fractures and cavities, greatly reducing the cost and having great application prospects. The three-dimensional stress field geological model of fractures and cavities that can perform acid fracturing numerical simulation constructs a fracture-cavity type carbonate rock geological model that can perform acidification numerical simulation by assigning a dual-scale mathematical model of porous media that can describe the scale from centimeter to micron to the geological model containing random natural fractures and cavities, simulates the process of acid solution activating natural fractures and communicating with cavities, calculates the extension direction and number of acid-etched fractures, as well as the orientation and number of acid solution communicating with cavities along the fractures, facilitating the judgment of the ability of acid-etched fractures to communicate with potential reservoirs around the well, and providing a basis for on-site construction design BRIEF DESCRIPTION OF THE DRAWINGS

[0057] Figure 1 is a flow chart of the method for evaluating the accuracy of acid fracturing numerical simulation for finding fractures and cavities of the present invention;

[0058] Figure 2 is a schematic diagram of the fracture-cavity communication situation simulated by the method for evaluating the accuracy of acid fracturing numerical simulation for finding fractures and cavities of the present invention;

[0059] Figure 3 is a schematic diagram of stable liquid supply after actual acid fracturing construction in the method for evaluating the accuracy of acid fracturing numerical simulation for finding fractures and cavities of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0060] For the convenience of understanding the present invention, the present invention will be described in more detail below in conjunction with specific embodiments and comparative examples.

[0061] S1. In the finite element processing software, establish a three-dimensional geological model of the target fracture-cavity type carbonate rock oil reservoir;

[0062] S2. According to the collected in-situ stress field data of the target fracture-cavity type carbonate rock oil and gas reservoir, establish a three-dimensional stress field distribution model of the target fracture-cavity type carbonate rock oil and gas reservoir based on the three-dimensional geological model in the finite element processing software;

[0063] S3. In the three-dimensional stress field distribution model, mark the positions of the solution caves and oil / gas wells in the reservoir of the target fractured-vuggy carbonate rock oil / gas reservoir to form a three-dimensional stress field distribution model containing natural fractures and solution caves, and assign a multi-scale mathematical model including a Darcy-scale model and a pore-scale model to the three-dimensional stress field distribution model containing natural fractures and solution caves to form a fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation; determine the fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation according to well logging data, etc., as Figure 2 shown. The reservoir of the target oil / gas reservoir is a carbonate fractured-vuggy oil reservoir with a size of 200 m × 200 m, and there are 6 solution caves and multiple natural fractures developed in this block. The radii of each solution cave are as follows: Solution Cave 1 (7.3 m), Solution Cave 2 (4.1 m), Solution Cave 3 (6.9 m), Solution Cave 4 (3.2 m), Solution Cave 5 (3.1 m), Solution Cave 6 (6.5 m).

[0064] S4. Calculate or obtain the actual stable liquid supply time at a specified production rate; the actual stable liquid supply time at the specified production rate refers to the time when the production is carried out at the specified production rate under the actual production construction conditions identical to those of the acid fracturing numerical simulation calculation conditions and the specified production rate is kept constant. According to the existing data obtained under the actual construction conditions identical to those of the acid fracturing numerical simulation calculation conditions, it is determined that when the specified production rate is 30 m 3 / d, the actual stable liquid supply time is as Figure 2 shown, which is 93 d;

[0065] S5. In the fractured-vug three-dimensional stress field geological model capable of acid fracturing numerical simulation as Figure 2 shown, according to the appropriate acid fracturing technology of following the fracture to find the cave, conduct acid fracturing numerical simulation calculation under the conditions identical to the production construction conditions of the actual stable liquid supply time at the specified production rate of 30 m 3 / d in S4. Through the acid fracturing numerical simulation calculation, form a main fracture and open natural fractures, so that the main fracture and the opened natural fractures communicate with the solution caves. Finally, it is determined that the solution caves that can be communicated are Solution Cave 1, Solution Cave 5, and Solution Cave 6;

[0066] Based on the volumes of the communicated Solution Cave 1, Solution Cave 5, and Solution Cave 6, clarify the theoretical stable liquid supply time at the specified production rate of 30 m 3 / d. Since the total volume of Solution Cave 1, Solution Cave 5, and Solution Cave 6 is approximately 2905 m 3 , the theoretical stable liquid supply time = 2905 m 3 / 30 m 3 / d, which is approximately 97 d;

[0067] S6. Judge the accuracy of the acid fracturing numerical simulation results of finding fractures and holes; the relative error between the theoretical stable liquid supply time and the actual stable liquid supply time = (97d - 93d) / 93d ≈ 4.3%. Since the relative error is less than 5%, the acid fracturing numerical simulation results of finding fractures and holes are relatively accurate.

[0068] It should be noted that the above specific embodiments can enable those skilled in the art to understand the present invention more comprehensively, but do not limit the present invention in any way. Therefore, although this specification has described the present invention in detail with reference to the drawings and embodiments, those skilled in the art should understand that the present invention can still be modified or equivalently replaced. In short, all technical solutions and their changes that do not depart from the spirit and scope of the present invention should be covered by the protection scope of this invention patent.

Claims

1. A method for evaluating the accuracy of acid fracturing numerical simulation results by following fractures and finding cavities, characterized in that, it includes the following steps: S1. In finite element processing software, establish a three-dimensional geological model of the reservoir of the target fracture-cavity type oil and gas reservoir; S2. According to the collected in-situ stress field data of the reservoir of the target fracture-cavity type oil and gas reservoir, establish a three-dimensional stress field distribution model of the reservoir of the target fracture-cavity type oil and gas reservoir based on the three-dimensional geological model in the finite element processing software; S3. In the three-dimensional stress field distribution model, mark the positions of the cavities and oil and gas wells in the reservoir of the target fracture-cavity type oil and gas reservoir to form a three-dimensional stress field distribution model containing natural fractures and cavities, and endow the three-dimensional stress field distribution model containing natural fractures and cavities with a multi-scale mathematical model including a Darcy-scale model and a pore-scale model to form a fracture-cavity three-dimensional stress field geological model capable of performing acid fracturing numerical simulation; Endowing the three-dimensional stress field distribution model with a multi-scale mathematical model including a Darcy-scale model and a pore-scale model to form a fracture-cavity three-dimensional stress field geological model capable of performing acid fracturing numerical simulation includes the following steps: S3.1 Establish a Darcy-scale model: The Darcy-scale model is used to describe the model of porous media from centimeter scale to micron scale, and the acid fluid is Darcy flow in the porous media from centimeter scale to micron scale; (1) Acid fluid flow in the matrix The acid fluid is injected into the formation at a certain speed. Under the macroscopic movement and concentration gradient of hydrogen ions in the fluid, the hydrogen ions are mass-transferred from the pore medium fluid to the surface of the carbonate rock to react, thereby changing the porosity and permeability of the formation. The flow of the acid fluid in the matrix formation is controlled by Darcy's law: The fluid pressure distribution is controlled by the continuity equation of incompressible fluid: The concentration distribution of hydrogen ions in the fluid is controlled by the convection-diffusion equation. There are two cases for the convection-diffusion equation. Case 1 is that the acid fluid does not completely dissolve the rock (ε < 1), and case 2 is that the acid fluid completely dissolves the rock (ε = 1); For the convection-diffusion equation in the case where the acid fluid does not completely dissolve the rock (ε < 1), the consumption of hydrogen ions on the rock surface and the change of porosity need to be considered: For the convection-diffusion equation in the case where the acid fluid completely dissolves the rock (ε = 1), the consumption of hydrogen ions on the rock surface and the change of porosity do not need to be considered: In the formula, is the Darcy velocity vector, m / s; k is the formation permeability, m 2 ; μ is the acid solution viscosity, Pa·s; P is the acid solution pressure, Pa; ε is the formation porosity; t is the reaction time, s; C f is the acid solution concentration in the rock pores, mol / m 3 ; $D_e$ is the acid solution diffusion tensor, m 2 / s; $k$ c is the local mass transfer coefficient of the acid solution, m / s; $a$ v is the pore area per unit volume of the rock, m 2 / m 3 ; $C$ s is the acid solution concentration on the rock surface, mol / m 3 ; $\alpha$ is the mass of the rock that can be corroded by per mole of the acid solution, kg / mol; $\rho$ s is the rock density, kg / m 3 ; (2) Acid fluid flow in the fractures The flow of the acid fluid in the natural fractures corresponds to different mechanisms from that in the matrix. The flow in the natural fractures is free flow, and the flow in the matrix is porous media seepage controlled by Darcy's law; S3.2 Establish a pore-scale model to provide parameter support including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient for the Darcy-scale model; S3.

3. Mesh the established three-dimensional stress field distribution model containing natural fractures and cavities, and assign the parameters calculated by the multi-scale mathematical model to the grid cells and nodes of the three-dimensional stress field distribution model containing natural fractures and cavities; Obtain a fracture-cavity three-dimensional stress field geological model capable of performing acidizing numerical simulation after meshing and assigning attribute parameters; S4. Calculate or obtain the actual stable liquid supply time under a specified production rate; S5. In the fractured-vuggy three-dimensional stress field geological model capable of acid fracturing numerical simulation, conduct a fracture-tracing acid fracturing numerical simulation calculation under the same conditions as the production construction conditions of the actual stable liquid supply time at the specified production rate determined in S4, and determine the theoretical stable liquid supply time at the specified production rate. When conducting fracture-tracing acid fracturing numerical simulation calculations under different production construction conditions, after inputting the corresponding values under the actual production construction conditions, the fractured-vuggy three-dimensional stress field geological model capable of acid fracturing numerical simulation forms a main fracture and opens natural fractures, and the main fracture and the opened natural fractures communicate with the karst caves. After the fracture-tracing acid fracturing numerical simulation calculation is completed, finally determine the karst caves that can be communicated. The theoretical stable liquid supply time is the ratio of the total volume of all the karst caves communicated in the acid fracturing numerical simulation calculation to the specified production rate. The actual stable liquid supply time at the specified production rate refers to the time when, under the actual production construction conditions identical to those of the acid fracturing numerical simulation calculation, actual production is carried out at the specified production rate and the specified production rate is kept constant. S6. Judge the accuracy of the fracture-tracing acid fracturing numerical simulation results. If the absolute value of the relative error between the theoretical stable liquid supply time and the actual stable liquid supply time is within 5%, the numerical simulation results are accurate; if the absolute value of this relative error is greater than 5%, the numerical simulation results are inaccurate.

2. The method for evaluating the accuracy of the fracture-tracing acid fracturing numerical simulation results according to claim 1, characterized in that, the relative error between the theoretical stable liquid supply time and the actual stable liquid supply time is the ratio of the absolute value of the difference between the theoretical stable liquid supply time and the actual stable liquid supply time to the actual stable liquid supply time.

3. The method for evaluating the accuracy of the fracture-tracing acid fracturing numerical simulation results according to claim 1, characterized in that, in the parameter support provided by the pore-scale model for the Darcy-scale model in S3.2, including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient, the relationships among permeability, pore radius, specific surface area, and porosity include: The formation permeability, pore radius, and specific surface area are directly related to porosity. The relationships among formation permeability, pore radius, specific surface area, and porosity are described by empirical formulas as follows: where ε (0 < ε < 1), k, r p , a v are porosity, permeability, pore radius, and specific surface area respectively; ε 0 , k 0 , r 0 , a 0 are initial porosity, permeability, pore radius, and specific surface area respectively; β is a constant related to the pore structure, and β = 1 is taken; Use the laminar flow formula in a circular pipe to examine the flow rate; Where Q is the flow rate, cm 3 / s; ΔP is the driving pressure difference, 0.1 MPa; D is the fracture diameter, cm; A is the cross-sectional area, cm 2 ; μ is the fluid viscosity, Pa·s; L is the fracture length, cm; The flow rate calculated using Darcy's formula is as follows: When the seam width is taken as 0.2 cm, the equivalent permeability corresponding to the natural fracture calculated based on Formula (6) and Formula (7) is k = D 2 / 32 = 125×10 3 μm 2 ; Let the porosity ε of the natural fracture max = 0.999 (ε 0 = 0.05, k 0 = 0.32), substitute it into Formula (5) to obtain the permeability K: k and K are of the same order of magnitude. That is, from the perspective of flow resistance, it is reasonable to equivalent a natural fracture with a width of 0.2 cm to a matrix with a porosity of 0.

999. For natural fractures with a width exceeding 0.2 cm, the width is not a factor limiting the fracture conductivity. Therefore, the natural fracture can be treated as a fracture with a width of 0.2 cm.

4. The method for evaluating the accuracy of the fracture-tracing acid fracturing numerical simulation results according to claim 3, characterized in that, In S3.2, the pore-scale model provides parameter support including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient for the Darcy-scale model. Due to the sediment compaction of the formation, the pore structure is different in the horizontal and vertical directions. The diffusion tensor includes the horizontal diffusion tensor D eX and the vertical diffusion tensor D eT ; the diffusion tensor is related to the molecular diffusion coefficient Dm, pore structure, and flow velocity, where the Peclet number is a dimensionless number representing the ratio of convection to diffusion; The diffusion tensor is divided into the horizontal diffusion tensor D eX and the vertical diffusion tensor D eT The formula is as follows: D eX = (α os + λx·Pe P ) Dm(10) D eT = (α os + λ T · Pe P ) Dm (11) where α os is a constant related to the pore structure, and α os is taken as 0.5; from the core diffusion experiment, λx = 0.5, λ T is 0.1; Dm is the molecular diffusion coefficient; Pe p is the Péclet number.

5. The method for evaluating the accuracy of the fracture-tracing acid fracturing numerical simulation results according to claim 1, characterized in that, in the parameter support provided by the pore-scale model for the Darcy-scale model in S3.2, including permeability, pore radius, specific surface area, porosity, diffusion tensor, and mass transfer coefficient, Mass transfer coefficient k c The calculation method is as follows: where Sh ∞ is the asymptotic Sherwood number; Re p is the pore-scale Reynolds number, Sc is the Schmidt number,

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