Method and equipment for predicting productivity of fractured fracture-control tight reservoir horizontal well and storage medium

Abstract

The invention discloses a method and equipment for predicting the productivity of a fracture-controlled tight reservoir horizontal well after fracturing and a storage medium. The method comprises the steps that S01, geological parameters and fracture network morphological parameters needed by fracturing construction design are obtained; s02, establishing a tree-shaped multi-scale fracture geometric model to quantitatively characterize the artificial fracture; step S03, determining the flowing state of the pressurized fluid; step S04, establishing a matrix-natural fracture-shaft coupling model based on the linear Darcy flow state of the fluid flowing from the matrix to the natural fracture; and S05, establishing a matrix-multi-scale fracture-wellbore coupling model based on the matrix-natural fracture-wellbore coupling model, substituting the parameters obtained in the step S01 into the model, and simulating the influence of different parameter conditions on the accumulative productivity, the oil production rate and the pressure. According to the method, the multi-scale crack is represented through the tree network morphology, and the productivity model is deduced in combination with the Darcy law, so that the prediction accuracy is improved, and the calculation time is greatly shortened.

Description

Technical Field

[0001] The present invention relates to the field of oil and gas reservoir production enhancement and transformation, and in particular to a method, equipment and storage medium for predicting the production capacity of a horizontal well in a fracture-controlled tight reservoir after fracturing. Background Art

[0002] The matrix porosity and permeability of fracture-controlled tight reservoirs are poor, resulting in generally low natural production capacity. This type of reservoir requires the formation of a complex fracture network through volume fracturing technology to maximize the communication of natural fractures and establish an effective migration channel for the fluid in the reservoir. In this process, the morphology, length and other characteristics of multi-scale fractures are crucial to the prediction of production capacity after horizontal well fracturing. However, the current numerical simulation methods have the problems of long calculation time and difficulty in engineering application when predicting production capacity. In contrast, the analytical model can quickly analyze the main controlling factors affecting production capacity and predict the production capacity after fracturing. However, for the analytical model production capacity prediction method after horizontal well fracturing in fracture-controlled tight reservoirs, the existing technology does not involve how to accurately consider the influence of multi-scale fractures in the analytical model. Summary of the invention

[0003] In view of the deficiencies in the current technology, the present invention proposes a method, equipment and storage medium for predicting the production capacity of horizontal wells in fracture-controlled tight reservoirs after fracturing, which overcomes the deficiencies in the existing technology, realizes the accurate prediction of the production capacity of horizontal wells in fracture-controlled tight reservoirs after fracturing and identifies the main factors affecting the production capacity.

[0004] The present invention proposes a method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing. The method specifically comprises the following steps:

[0005] Step S01: obtaining geological parameters and fracture network morphology parameters required for fracturing construction design;

[0006] Step S02: Establishing a tree-like multi-scale fracture geometry model to quantitatively characterize artificial fractures;

[0007] Step S03: determining the flow state of the fluid after compression;

[0008] Step S04: establishing a matrix-natural fracture-wellbore coupling model based on the linear Darcy flow state of fluid flowing from the matrix to the natural fracture;

[0009] Step S05: A matrix-multiscale fracture-wellbore coupling model is established based on the matrix-natural fracture-wellbore coupling model, and the parameters obtained in step S01 are substituted into the model to simulate the effects of different parameter conditions on the cumulative production capacity, oil production rate and pressure.

[0010] Specifically, the geological parameters acquired in step S01 include: matrix permeability, reservoir thickness, original formation pressure, crude oil volume coefficient, and crude oil viscosity.

[0011] Specifically, the fracture network parameters obtained in step S01 include: natural fracture density, artificial fracture cluster spacing, artificial fracture main fracture length, artificial fracture main fracture width, artificial fracture main fracture height, bottom hole flow pressure, system compressibility, fracture bifurcation order, fracture bifurcation angle, fracture bifurcation number, natural fracture azimuth angle, fracture length ratio, fracture height ratio, fracture width ratio, natural fracture length, natural fracture width, natural fracture height, and horizontal well drainage.

[0012] Specifically, in order to quantitatively characterize the artificial cracks in step S02, the following parameters are used: artificial crack main crack length l0, artificial crack main crack height h0, artificial crack main crack width w0, crack bifurcation angle θ, crack bifurcation order n, crack bifurcation number m, crack length ratio γ, crack height ratio α, crack width ratio β, artificial crack equivalent length L f , natural fracture length x nf , natural fracture height h nf , natural fracture width w nf .

[0013] Where n = 0 represents a single crack, and m = 1 represents no bifurcation of the crack; γ, α, and β are represented as follows:

[0014]

[0015] Specifically, the cross-sectional area of ​​the artificial crack in step S02 is elliptical or rectangular.

[0016] Specifically, in step S03, before analyzing the flow state of the fluid from matrix-natural fracture-secondary fracture-main fracture-wellbore, the flow changes of matrix-multi-scale fracture-wellbore are analyzed first, and the flow state of matrix-natural fracture is first clarified, so the flow state of matrix-natural fracture-secondary fracture-main fracture-wellbore is simplified to the flow state of matrix-natural fracture-wellbore.

[0017] Specifically, the matrix-natural fracture-wellbore coupling model in step S04 includes the production formula provided by the symmetrical natural fracture, which is specifically expressed as

[0018]

[0019] in definition Then the production formula provided by the symmetrical natural fracture is simplified to Q nf =A(P e -P w );

[0020] Where P e is the flow boundary pressure, MPa; Pw is the pressure at the end of the natural fracture, MPa; h nf is the height of natural fracture, m; k m is the matrix permeability, mD; k nf is the natural fracture permeability, mD; x nf is the length of natural fracture, m; w nf is the natural fracture width, m; y e is the vertical distance from the natural fracture surface to the flow boundary, m; μ is the fluid viscosity, mPa·s.

[0021] Specifically, step S05 establishes a matrix-multi-scale fracture-wellbore coupling model based on the matrix-natural fracture-wellbore coupling model, including adding the flow of artificial fractures to the matrix-natural fracture-wellbore model, wherein:

[0022] The flow formula of secondary fracture is expressed as:

[0023]

[0024] Where D is the number of symmetrical natural fractures on the secondary fracture, x i is the distance between the ith natural fracture and the end of the secondary artificial fracture, m;

[0025] The production of a single secondary fracture considering Darcy flow can be expressed as:

[0026]

[0027] Therefore, the yield formula provided by the symmetrical n-level crack is expressed as

[0028]

[0029] definition Therefore, the production formula provided by the symmetrical n-level crack is:

[0030] Q fn =M(P e -P wn )

[0031] Projecting the secondary fractures to the direction of the main fractures, the production formula provided by natural fractures and matrix to n-1 fractures can be expressed as:

[0032]

[0033] Among them, the flow boundary pressure formula at time t considering Darcy flow is:

[0034]

[0035] Where N P(t) is the cumulative oil production at time t, m 3 ; V f is the horizontal well discharge, m 3 ;c t is the compressibility of the system, MPa -1 ;

[0036] where Y n It is expressed as:

[0037]

[0038] Substituting the flow boundary pressure formula at time t into the production formula provided by natural fractures and matrix to n-1 level fractures, we finally get the relationship between oil production rate and time when Darcy flow is considered after the pressure drop propagates to the flow boundary.

[0039] The present invention also provides an electronic device, comprising a memory, a processor, and a program stored in the memory and running on the processor, characterized in that when the processor executes the program, the steps of the above-mentioned method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing are implemented.

[0040] The present invention also provides a computer-readable storage medium, characterized in that the computer-readable storage medium stores instructions, and when the instructions are executed on a terminal device, the terminal device executes the steps of the above-mentioned method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing.

[0041] The beneficial effects of the present invention include at least: the prediction method, device and storage medium proposed in the present invention provide a new idea for the production capacity prediction of fracture-controlled tight reservoirs, characterize multi-scale fractures through tree network morphology, and derive the production capacity model in combination with Darcy's law, which not only improves the accuracy of the prediction, but also greatly shortens the calculation time, and has high engineering application value. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for use in the embodiments are briefly introduced below.

[0043] Figure 1 Schematic diagram of multi-scale fractures after fracturing of low permeability fracture-controlled reservoir;

[0044] Figure 2 (a) Simplified schematic diagram of tree-like multi-scale fractures;

[0045] Figure 2 (b) Schematic diagram of the artificial crack as a rectangular cross section;

[0046] Figure 3 Schematic diagram of the coupled flow profile of matrix-natural fracture-secondary fracture-primary fracture-wellbore;

[0047] Figure 4 Schematic diagram of the coupled flow profile of matrix-natural fracture-artificial fracture. DETAILED DESCRIPTION

[0048] The present invention is further described below in conjunction with the accompanying drawings and embodiments. It should be noted that, in the absence of conflict, the embodiments in this application and the technical features in the embodiments can be combined with each other. It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meanings as those generally understood by those of ordinary skill in the art to which this application belongs. The words "including" or "comprising" and the like used in the disclosure of the present invention mean that the elements or objects appearing before the word cover the elements or objects listed after the word and their equivalents, without excluding other elements or objects.

[0049] like Figure 1 As shown in the figure, after large-scale volume fracturing of the fracture-controlled tight reservoir, a main fracture perpendicular to the horizontal wellbore will be formed, which greatly increases the flow control area and thus increases the oil production. Considering the coupled flow of the matrix and the main fracture, a physical model of multi-stage fracturing of the reservoir horizontal well was established. After fracturing, the flow pattern of the fluid changes from a single linear flow from the matrix to the horizontal wellbore to a bilinear flow from the matrix to the fracture, and then from the fracture to the horizontal wellbore. Therefore, the flow pattern of the reservoir fracturing horizontal well mainly includes three stages, such as Figure 2 Figure 1 shows: (1) linear flow of fluid from the matrix to the fracture; (2) linear flow of fluid from the fracture to the horizontal wellbore; (3) flow of fluid through the horizontal wellbore to the surface.

[0050] The model is derived based on the following assumptions: (1) the reservoir is homogeneous and has uniform thickness, and vertical fluid flow is ignored; (2) the fractures are evenly distributed and the properties of different fractures are the same; (3) the fluid is a single-phase incompressible fluid, and its flow is in thermodynamic equilibrium and isothermal environment, and is not affected by special physical or chemical phenomena; (4) there is no permeability outside the reservoir; (5) the flow from the matrix to the fractures conforms to Darcy flow, while the flow from the fractures to the horizontal wellbore conforms to Darcy flow.

[0051] Step S01, obtaining geological parameters and fracture network morphology parameters required for fracturing construction design.

[0052] Specifically, the geological parameters obtained include: matrix permeability, reservoir thickness, original formation pressure, crude oil volume coefficient, and crude oil viscosity.

[0053] The obtained fracture network parameters include: natural fracture density, artificial fracture cluster spacing, artificial fracture main fracture length, artificial fracture main fracture width, artificial fracture main fracture height, bottom hole flow pressure, system compressibility, fracture bifurcation order, fracture bifurcation angle, number of fracture bifurcations, natural fracture azimuth angle, fracture length ratio, fracture height ratio, fracture width ratio, natural fracture length, natural fracture width, natural fracture height, and horizontal well drainage.

[0054] Step S02 establishes a tree-like multi-scale fracture geometry model to quantitatively characterize artificial fractures.

[0055] Specifically, Figure 2 It is a schematic diagram of an artificial fracture with a rectangular cross section, which simplifies the plane morphology of multi-scale fractures after hydraulic fracturing. In order to quantitatively characterize artificial fractures, the following parameters are used: artificial fracture main fracture length l0, artificial fracture main fracture height h0, artificial fracture main fracture width w0, fracture bifurcation angle θ, fracture bifurcation order n, fracture bifurcation number m, fracture length ratio γ, fracture height ratio α, fracture width ratio β, artificial fracture equivalent length L f , natural fracture length x nf , natural fracture height h nf , natural fracture width w nf . Where n = 0 represents a single crack, and m = 1 represents no bifurcation of the crack; γ, α, and β are represented as follows:

[0056]

[0057] In order to study the flow characteristics in TS cracks, it is assumed that: (1) the fluid in the TS crack is a Newtonian fluid and the flow is laminar; (2) the crack heights at the same level are equal; when the height ratio is 1, the heights of the cracks at all levels are equal; when the height ratio is less than 1, it means that the heights of the cracks at different levels are different, and the crack height decreases with the increase of the bifurcation level; (3) the cross-section of the TS crack is elliptical or rectangular. This embodiment takes the rectangular cross-section as an example for derivation, as shown in FIG. Figure 2 (b) as shown; (4) When the cross section is an ellipse, the cracks at the same level have the same width for the rectangular cross section; (5) The geometric parameters of the secondary horizontal crack are proportional to the geometric parameters of the upper horizontal crack; therefore, the equivalent crack length of the artificial crack can be expressed as:

[0058]

[0059] Step S03 determines the flow state of the fluid after compression.

[0060] Specifically, the flow process of reservoir fluid in a complex fracture network is as follows: Figure 3As shown in Fig. 2, a stable post-pressure production capacity is formed through matrix supply and multi-scale fracture diversion. Before analyzing the flow state of fluid from matrix-natural fracture-secondary fracture-main fracture-wellbore, the flow change of matrix-multi-scale fracture-wellbore is analyzed first. First, the flow state of matrix-natural fracture is clarified, and the flow state of matrix-natural fracture-secondary fracture-main fracture-wellbore is simplified to the flow state of matrix-natural fracture-wellbore, as shown in Fig. Figure 4 As shown, it represents the state where fluid flows from the matrix to the natural fractures and the natural fractures supply the wellbore without fracturing.

[0061] Step S04 establishes a matrix-natural fracture-wellbore coupling model based on the linear Darcy flow state of fluid flowing from the matrix to the natural fracture.

[0062] Specifically, Figure 4 As shown, it is assumed that the horizontal wellbore is along the y-axis and the natural fracture extends along the x-axis. Figure 3 The figure shows the two-dimensional flow profile of the fluid in a single natural fracture wing along the matrix-natural fracture-wellbore. The fluid flowing from the matrix to the natural fracture also conforms to the linear Darcy flow. Therefore, the flow velocity at any point is:

[0063]

[0064] In the formula, v y (x) is the flow velocity along the y-axis at any point of the natural fracture, m / d; y e is the vertical distance from the natural fracture surface to the flow boundary, m; P e is the flow boundary pressure, MPa; P nf (x) is the pressure at any point along the x-axis in the natural fracture, MPa.

[0065] Therefore, the flow rate along the x-axis at any point in the natural fracture is, and the coefficient 2 represents the two walls of the natural fracture:

[0066]

[0067] In the formula, Q nf (x) is the flow velocity at any point along the x-axis in the fracture, m 3 / d;h nf is the fracture height, m. Therefore, the flow velocity at any point along the x-axis in the fracture is:

[0068]

[0069] In the formula, v nf (x) is the flow velocity at any point along the x-axis in the natural fracture, m / d; w nf is the fracture width, m. The flow of fluid from natural fractures to the wellbore conforms to the linear Darcy flow, which can be expressed as:

[0070]

[0071] In the formula, k nf is the natural fracture permeability, mD. It can be obtained that:

[0072]

[0073] Calculate the derivative of formula (7):

[0074]

[0075] set up P d =P e -P nf (x), then formula (8) is transformed into:

[0076]

[0077] make Then the left side of equation (9) can be transformed into:

[0078]

[0079] Therefore, transform equation (10) into:

[0080]

[0081] The variable separation integral of formula (11) can be transformed into:

[0082]

[0083] When P nf (x) = P e When , the pressure drop from the matrix to the natural fracture along the y-axis direction is zero, which can be expressed as:

[0084]

[0085] Substituting equation (13) into equation (11), we get c1=0, that is:

[0086]

[0087] The variable separation integral of formula (14) can be transformed into:

[0088]

[0089] At the end of the natural fracture, P nf (x) = P w , which can be expressed as:

[0090]

[0091] Substituting formula (16) into formula (15), c2 can be calculated as:

[0092]

[0093] Substituting formula (17) into formula (15), we can obtain:

[0094]

[0095]

[0096] Substituting equation (19) into equation (4), the single-crack single-wing production considering Darcy flow can be expressed as:

[0097]

[0098] Therefore, the production provided by the symmetrical natural fracture can be expressed as, in this case, a coefficient of 2 is multiplied to represent two single-wing natural fractures:

[0099]

[0100] It can be seen that once the length, width, height, permeability, matrix permeability range, and fluid viscosity of the natural fracture are determined, under Darcy flow conditions, the production of the matrix supplied to the symmetrical natural fracture is proportional to the pressure difference between the reservoir and the wellbore. To facilitate subsequent calculations, define Formula (21) can be expressed as:

[0101] Q nf =A(P e -P w ) (twenty two)

[0102] Step S05 establishes a matrix-multiscale fracture-wellbore coupling model based on the matrix-natural fracture-wellbore coupling model, substitutes the parameters obtained in step S01 into the model, and simulates the influence of different parameter conditions on the cumulative production capacity, oil production rate and pressure.

[0103] Specifically, on the basis of the matrix-natural fracture-wellbore model, the flow of artificial fractures is added, and the model is derived assuming that the number of artificial fractures n = 2, as shown in Figure 3 As shown, the flow rate of the secondary fracture can be expressed as:

[0104]

[0105] D is the number of symmetrical natural fractures on the secondary fracture, x i is the distance between the ith natural fracture and the end of the second artificial fracture. Assuming that all natural fractures are perpendicular to the artificial fractures and are evenly distributed, we can get:

[0106]

[0107] Similarly, the flow velocity along the x-axis direction of the secondary fracture can be obtained:

[0108]

[0109] The fluid in the secondary fracture also satisfies the Darcy flow:

[0110]

[0111] set up P d =P e -P w2 (x), then formula (26) is transformed into:

[0112]

[0113] By taking the derivative of formula (27), we can get:

[0114]

[0115] Similarly, we can get:

[0116]

[0117] Using Taylor expansion for formula (29) we can get:

[0118]

[0119] The variable separation integral of formula (30) can be transformed into:

[0120]

[0121] When P w2 (x) = P e When , the pressure drop from the matrix to the natural fracture along the y-axis direction is zero, which can be expressed as:

[0122]

[0123] Substituting equation (32) into equation (31), we get c1=0, that is:

[0124]

[0125] The variable separation integral of formula (33) can be transformed into:

[0126]

[0127] At the end of the artificial crack, P w2 (x) = P w2 , which can be expressed as:

[0128]

[0129] Substituting formula (35) into formula (34), c2 can be calculated as:

[0130]

[0131] Substituting formula (36) into formula (34), we can obtain:

[0132]

[0133]

[0134] Substituting equation (38) into equation (23), the single-level fracture production considering Darcy flow can be expressed as:

[0135]

[0136] Therefore, the production provided by symmetrical n-level fractures can be expressed as, in this case, a coefficient m is multiplied to represent m secondary fractures:

[0137]

[0138] It can be seen that the production of level n fractures is proportional to the pressure difference, and is also closely related to the length, width, permeability, and number of natural fractures. To facilitate subsequent calculations, the following definition is given: So formula (41) can be expressed as:

[0139] Q fn =M(P e -P wn ) (41)

[0140] Projecting the secondary fractures to the direction of the main fractures, the production provided by natural fractures and matrix to the n-1 fractures can be expressed as:

[0141]

[0142] Therefore, the flow rate at the crack bifurcation should be equal, i is greater than or equal to 1, and the equation can be obtained:

[0143] Q f(n-i) (l n-i )=mQ f(n-i+1) (0) (43)

[0144] Simplifying formula (43), we can get:

[0145]

[0146] Therefore, given the bottom borehole pressure and reservoir pressure, the pressure P at the bifurcation point can be calculated: wn , P wn-i, and then study the influence of factors such as fracture conductivity at different scales on production capacity.

[0147] The average pressure in the crack can be expressed as:

[0148]

[0149] According to the material balance theory, the cumulative oil production of fractured horizontal wells can be expressed as:

[0150]

[0151] Where N P (t) is the cumulative oil production at time t, m 3 ; V f is the horizontal well discharge, m 3 ;P m (t) is the average formation pressure at time t, MPa; C t is the compressibility of the system, MPa -1 .

[0152] The fluid follows linear flow in the matrix, and the pressure distribution expression in the matrix is:

[0153]

[0154] Where P m (x, y, t) is the formation pressure of the matrix (x, y) at time t, MPa. e (t) is the flow boundary pressure at time t, MPa. f (x, t) is the average pressure of the crack at time t, MPa.

[0155] The average formation pressure at time t is:

[0156]

[0157] The average formation pressure considering Darcy flow (matrix-natural fracture-wellbore flow) at time t is obtained by integration:

[0158]

[0159] The flow boundary pressure at time t considering Darcy flow can be obtained:

[0160]

[0161] Substituting equation (50) into equation (39) respectively, we can obtain the relationship between oil production rate and time when considering Darcy flow after the pressure drop propagates to the flow boundary.

[0162] Substituting equations (44) and (49) into equation (50), the average formation pressure considering Darcy flow (natural fracture-wellbore flow) at time t is obtained by integration:

[0163]

[0164] Substituting equation (47) into equation (48), we can obtain the flow boundary pressure at time t considering Darcy flow:

[0165]

[0166] Substituting equation (52) into equation (42), we can obtain the relationship between oil production rate and time when considering Darcy flow after the pressure drop propagates to the flow boundary. n It is expressed as:

[0167]

[0168] The meanings of the parameter symbols involved in the present invention are shown in Table 1.

[0169] Table 1

[0170]

[0171] The specific embodiments described above further illustrate the purpose, technical solutions and beneficial effects of the present application. It should be understood that the above description is only a specific embodiment of the present application and is not intended to limit the scope of protection of the present application. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present application should be included in the scope of protection of the present application.

Claims

1. A method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing, characterized in that: The following steps are involved: Step S01: obtaining geological parameters and fracture network morphology parameters required for fracturing construction design; Step S02: Establishing a tree-like multi-scale fracture geometry model to quantitatively characterize artificial fractures; Step S03: determining the flow state of the fluid after compression; Step S04: establishing a matrix-natural fracture-wellbore coupling model based on the linear Darcy flow state of fluid flowing from the matrix to the natural fracture; Step S05: A matrix-multiscale fracture-wellbore coupling model is established based on the matrix-natural fracture-wellbore coupling model, and the parameters obtained in step S01 are substituted into the model to simulate the effects of different parameter conditions on the cumulative production capacity, oil production rate and pressure.

2. The method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 1, characterized in that: The geological parameters obtained in step S01 include: matrix permeability, reservoir thickness, original formation pressure, crude oil volume coefficient, and crude oil viscosity.

3. The method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 2, characterized in that: The fracture network parameters obtained in step S01 include: natural fracture density, artificial fracture cluster spacing, artificial fracture main fracture length, artificial fracture main fracture width, artificial fracture main fracture height, bottom hole flow pressure, system compressibility, fracture bifurcation order, fracture bifurcation angle, fracture bifurcation number, natural fracture azimuth angle, fracture length ratio, fracture height ratio, fracture width ratio, natural fracture length, natural fracture width, natural fracture height, and horizontal well drainage.

4. The method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 3, characterized in that: In order to quantitatively characterize the artificial cracks in step S02, the following parameters are used: artificial crack main crack length l0, artificial crack main crack height h0, artificial crack main crack width w0, crack bifurcation angle θ, crack bifurcation order n, crack bifurcation number m, crack length ratio γ, crack height ratio α, crack width ratio β, artificial crack equivalent length L f , natural fracture length x nf , natural fracture height h nf , natural fracture width w nf , where n=0 represents a single crack, and m=1 represents no bifurcation of the crack; γ, α, and β are represented as follows:

5. The method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 4, characterized in that: The cross-sectional area of ​​the artificial crack in step S02 is elliptical or rectangular.

6. A method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 5, characterized in that: In the step S03, before analyzing the flow state of the fluid from matrix-natural fracture-secondary fracture-main fracture-wellbore, the flow change of matrix-multi-scale fracture-wellbore is analyzed first, and the flow state of matrix-natural fracture is first clarified, so the flow state of matrix-natural fracture-secondary fracture-main fracture-wellbore is simplified to the flow state of matrix-natural fracture-wellbore.

7. A method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 6, characterized in that: The matrix-natural fracture-wellbore coupling model in step S04 includes the production formula provided by the symmetrical natural fracture, which is specifically expressed as: in definition Then the production formula provided by the symmetrical natural fracture is simplified to Q nf =A(P e -P w ); Where P e is the flow boundary pressure, MPa; P w is the pressure at the end of the natural fracture, MPa; h nf is the height of natural fracture, m; k m is the matrix permeability, mD; k nf is the natural fracture permeability, mD; x nf is the length of natural fracture, m; w nf is the natural fracture width, m; y e is the vertical distance from the natural fracture surface to the flow boundary, m; μ is the fluid viscosity, mPa·s.

8. The method for predicting the productivity of horizontal wells in fracture-controlled tight reservoirs after fracturing according to claim 7, characterized in that: The step S05 establishes a matrix-multi-scale fracture-wellbore coupling model based on the matrix-natural fracture-wellbore coupling model, including adding the flow of artificial fractures to the matrix-natural fracture-wellbore model, wherein: The flow formula of secondary fracture is expressed as: Where D is the number of symmetrical natural fractures on the secondary fracture, x i is the distance between the ith natural fracture and the end of the secondary artificial fracture, m; The production of a single secondary fracture considering Darcy flow can be expressed as: Therefore, the yield formula provided by the symmetrical n-level crack is expressed as definition Therefore, the production formula provided by the symmetrical n-level crack is: Q fn =M(P e -P wn ) Projecting the secondary fractures to the direction of the main fractures, the production formula provided by natural fractures and matrix to n-1 fractures can be expressed as: Among them, the flow boundary pressure formula at time t considering Darcy flow is: Where N P (t) is the cumulative oil production at time t, m 3 ; V f is the horizontal well discharge, m 3 ;c t is the compressibility of the system, MPa -1 ; where Y n It is expressed as: Substituting the flow boundary pressure formula at time t into the production formula provided by natural fractures and matrix to n-1 level fractures, we finally get the relationship between oil production rate and time when Darcy flow is considered after the pressure drop propagates to the flow boundary.

9. An electronic device comprising a memory, a processor, and a program stored in the memory and running on the processor, characterized in that: When the processor executes the program, the steps of a method for predicting the productivity of a horizontal well in a fracture-controlled tight reservoir after fracturing are implemented as described in any one of claims 1 to 8.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores instructions, and when the instructions are executed on a terminal device, the terminal device executes the steps of a method for predicting the post-fracturing productivity of a horizontal well in a fracture-controlled tight reservoir as described in any one of claims 1 to 8.

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