Method for evaluating the effective reconstruction volume of multi-scale artificial suture

Abstract

The present invention provides a method for evaluating the effective transformation volume of multi-scale artificial fractures, comprising: step 1, calculating the fracture conductivity according to parameters such as proppant type, sand concentration, proppant density and crushing rate; step 2, establishing a multi-medium seepage mathematical model, performing numerical solution, and obtaining a flow field for tight reservoir fracturing development considering the starting pressure gradient; step 3, calculating the normal inflow velocity of the fluid in the fracture; step 4, establishing a method for identifying the effective length of a single fracture; step 5, calculating the effective transformation volume coefficient of multi-stage fracturing; step 6, obtaining the effective transformation volume of the fracture network on the basis of obtaining the effective transformation volume coefficient. The method for evaluating the effective transformation volume of multi-scale artificial fractures can obtain the relationship between different proppant particle sizes, sand ratios, fracture complexity and other parameters and the effective transformation volume, and then optimize these parameters to guide efficient development on site.

Description

Technical Field

[0001] The invention relates to the research field of fracturing technology, and in particular to a method for evaluating the effective transformation volume of multi-scale artificial fractures. Background Art

[0002] In the history of hydraulic fracturing, the development of fracturing engineering technology has promoted reservoir development technology, such as vertical well stratified fracturing and horizontal well staged fracturing technology. Once the well pattern spacing and reservoir geological plan of the block are determined, the length of the fracturing cracks in the block is also determined, that is, the fixed length fracturing technology is adopted. However, during the fracturing construction process, due to the certain seepage capacity of the formation, the fracturing fluid will be lost into the formation. After the construction is completed, part of the liquid is discharged, and the remaining liquid will remain in the formation and cracks, forming a water phase closure area in the fracture invasion zone, thereby reducing the relative permeability of the fluid in the invasion zone, which greatly hinders the flow of crude oil into the fracture. Field data show that due to the existence of artificial fractures and natural fractures, the fractures around the wellbore are multi-scale relationships, and the relationship between fractures of different scales, fracture conductivity, sand concentration, and effective transformation volume is still unclear.

[0003] In the Chinese patent application with application number: CN201510752304.8, a prediction method for complex network fractures in tight sandstone reservoirs is involved. The prediction method steps are as follows: establish a structural geological model and a fracture development model, test the magnitude and direction of ancient and current ground stresses, complete rock mechanics parameter experiments, test rock mechanics parameters and fracture stress sensitivity, establish a multi-level composite fracture criterion for fractured rocks, conduct rock deformation physical tests to obtain peak strength, establish a uniaxial state stress-strain and fracture body density relationship model, establish a triaxial state stress-strain and fracture body density and occurrence relationship model, establish a uniaxial state stress-strain and fracture body density relationship model, calculate and simulate fracture parameters under current conditions, and verify the reliability of the quantitative prediction results of fractures. However, the patent only gives a description of quantitative fractures, and does not give a relationship between the changes in the conductivity within the fractures.

[0004] In the Chinese patent application with application number: CN201510867900.0, a method for evaluating the spatial effectiveness of complex network fractures in tight sandstone reservoirs is involved. The method for evaluating the effectiveness of the network fracture system in tight sandstone reservoirs has the following steps: establishing a discrete network geological model of fractures, statistically analyzing the formation period of fractures, statistically analyzing the source of fracture fillings, statistically analyzing the dominant filling direction and group of fractures, analyzing the main controlling geological factors of fracture filling, establishing the relationship between fracture permeability and current principal stress, and evaluating the spatial effectiveness of the network fracture system. However, the patent uniformly gives a fixed value for the permeability in the fractures, and does not give the changing relationship between the conductivity in the fractures and the concentration of sand.

[0005] In the Chinese patent application with application number: CN201410131260.2, a method of volume fracturing with temporary plugging of natural sweet spots is involved, which belongs to the technical field of increasing oil and gas production. The method includes: obtaining the distribution of reservoir stress profile according to the magnitude and direction of in-situ stress on the preset horizontal section length, the horizontal well orientation, length, reservoir Young's modulus, Poisson's ratio and logging interpretation results; determining the horizontal well segmentation scheme according to the reservoir stress profile distribution, and segmenting the horizontal well segment through the packer; analyzing the possible fracturing positions according to the logging data and the interpretation of the ground stress, and determining the number of fractures in each target section according to the intensity requirements of the fracturing transformation; naturally selecting sweet spots in each target section to open multiple fractures, and forming a complex network of fractures in the same fracture. This patent can determine the number of fractures, but still gives the conductivity in the fracture as a fixed value, and does not give the relationship between the change and the concentration of the sand.

[0006] To this end, we invented a new method to evaluate the effective transformation volume of multi-scale artificial sutures, which solved the above technical problems. Summary of the invention

[0007] The purpose of the present invention is to provide a method for evaluating the effective transformation volume of multi-scale artificial fractures, which can obtain the relationship between different proppant particle sizes, sand ratios, fracture complexity and other parameters and the effective transformation volume.

[0008] The object of the present invention can be achieved by the following technical measures: a method for evaluating the effective transformation volume of multi-scale artificial suturing, the method for evaluating the effective transformation volume of multi-scale artificial suturing comprising:

[0009] Step 1, calculating the fracture conductivity according to the parameters of proppant type, sand concentration, proppant density and crushing rate;

[0010] Step 2, establish a multi-media seepage mathematical model, perform numerical solution, and obtain the flow field of tight reservoir fracturing development considering the starting pressure gradient;

[0011] Step 3, calculating the normal inflow velocity of the fluid into the fracture;

[0012] Step 4, establishing a method for determining the effective length of a single crack;

[0013] Step 5, calculating the effective transformation volume coefficient of multi-stage fracturing;

[0014] Step 6: Based on the effective transformation volume coefficient, the effective transformation volume of the fracture network is obtained.

[0015] The purpose of the present invention can also be achieved by the following technical measures:

[0016] In step 1, the conductivity k at each point in the crack is calculated based on the distribution of sand concentration in the crack. wf :

[0017]

[0018] Where: Kw f is the fracture conductivity, mD·m;

[0019] r is the proppant particle size, m;

[0020] a is the distance between two proppant particles reduced due to compression, m;

[0021] B t is the breakage rate;

[0022] C is the sand concentration, i.e. the proppant particle concentration, kg·m -2 ;

[0023] V 单 is the proppant volume, m 3 ;

[0024] ρ s is the proppant density, kg·m -3 ;

[0025] h1 is the distance that the proppant is embedded in the fracture, m;

[0026] τ is the tortuosity.

[0027] Step 2 includes:

[0028] Step 21: Calculate the proppant volume fraction in the half-length direction of the fracture;

[0029] Step 22: Calculate the permeability in the half-length direction of the fracture;

[0030] Step 23: Establish the fluid motion equation including the starting pressure gradient during the development of tight oil reservoirs;

[0031] Step 24: Substitute the motion equation in step 23 into the continuity equation to obtain the tight reservoir matrix flow control equation;

[0032] Step 25: Establish the fluid motion equation in the fracture;

[0033] Step 26: Substitute the motion equation of the fracture fluid flow into the continuity equation of the discrete fracture fluid flow to obtain its control equation;

[0034] Step 27: Based on the mathematical model of seepage in fractures and matrix, it is assumed that the pressure at the interface between fractures and matrix is ​​equal;

[0035] Step 28: Establish a multi-media seepage mathematical model based on the above steps.

[0036] In step 21, the proppant volume fraction in the fracture half-length direction is calculated; its value is equal to the maximum proppant volume fraction multiplied by the step function value at that position:

[0037]

[0038] Where: d f is the proppant volume fraction in the fracture half-length direction; d fi is the maximum proppant volume fraction; is the normalized step function value at the crack half-length x.

[0039] In step 22, the permeability in the half-length direction of the fracture is calculated using the formula:

[0040]

[0041] Where: φ f is the porosity of the fracture; d p is the proppant diameter, m; S is the sphericity of the proppant; for the pores formed by hydraulic fracturing, λ m ≈25 / 12.

[0042] In step 23, the fluid motion equation containing the starting pressure gradient during the development of tight oil reservoirs is established and expressed in the following form:

[0043]

[0044] Where: u x is the fluid velocity, m·s -1 ;

[0045] K m is the matrix permeability, m 2 ;

[0046] μ is the fluid viscosity, mPa·s;

[0047] p m is the matrix pressure, Pa;

[0048] x is the distance from the crack, m;

[0049] λ x is the starting pressure gradient, MPa·m -1 .

[0050] In step 24, the equation of motion in step 23 is substituted into the continuity equation to obtain the tight reservoir matrix flow control equation:

[0051]

[0052] Where: is the matrix porosity, dimensionless.

[0053] u is the fluid velocity, m·s -1 ;

[0054] ρ is the fluid density, kg·m -3 ;

[0055] t is time, s.

[0056] In step 25, the equation of motion of the fluid in the fracture is expressed as follows:

[0057]

[0058] Where: K f is the fracture permeability, m 2 ;

[0059] P f is the pressure in the fracture zone, Pa;

[0060] μ is the fluid viscosity, mPa·s.

[0061] In step 26, the motion equation of the fracture fluid flow is substituted into the continuity equation of the discrete fracture fluid flow to obtain its control equation:

[0062]

[0063] Where: is the fracture porosity, dimensionless;

[0064] d f is the crack width, m.

[0065] In step 27, based on the mathematical model of fracture and matrix seepage, it is assumed that the pressure at the interface between the fracture and the matrix is ​​equal, as shown in the following formula:

[0066]

[0067] Where: The interface between crack and matrix

[0068] P f is the pressure in the fracture zone, Pa;

[0069] p m is the matrix pressure, Pa.

[0070] In step 3, the normal inflow velocity of the fluid in the fracture is calculated based on the obtained flow field and the flow distribution of the fracture. For artificial fracturing fractures, the normal inflow velocity of the fluid is integrated over the unit fracture length to obtain the fluid flow rate per unit length, as shown in the following formula:

[0071] Q1=∫u n dx

[0072] Where: u n is the normal inflow velocity of the fluid into the fracture, m·s -1 ;

[0073] x is the unit length, m;

[0074] Q1 is the fluid flow rate per unit length, m 3 ·s.

[0075] In step 4, a method for determining the effective length of a single crack is established, and the effective length of a single crack is defined as being equal to the length of the portion of the crack that can contribute to the main industrial flow, as shown in the following formula:

[0076]

[0077] Where: L e is the effective crack length, m;

[0078] L f is the fracture fracturing length, m;

[0079] R is the effective contribution rate of cracks;

[0080] u n is the normal inflow velocity of the fluid into the fracture, m·s -1 .

[0081] In step 5, the calculation method of the effective transformation volume coefficient of multi-stage fracturing is based on the assumption that a certain fracture network has 1 primary main fracture with a length of L1; n secondary branch fractures with a length of L2; and m tertiary derivative fractures with a length of L3. After obtaining the effective lengths of all fractures, the overall effective transformation volume coefficient I of the fracture is obtained by weighted average, as shown in the following formula:

[0082]

[0083] Where: I is the effective transformation volume coefficient;

[0084] L1 is the main fracture fracturing length, m;

[0085] L2 is the fracturing length of secondary branch fractures, m;

[0086] L3 is the third-level derived fracture fracturing length, m;

[0087] L e1 is the effective crack length of the main crack, m;

[0088] L e2 is the effective crack length of the secondary branch crack, m;

[0089] L e3 is the effective crack length of the third-level derivative crack, m;

[0090] n is the number of secondary branch seams, dimensionless;

[0091] m is the number of third-level derived seams, dimensionless;

[0092] a, b, and c are the effective contribution rates of the main crack, secondary branch crack, and tertiary derivative crack, respectively, and are dimensionless.

[0093] In step 6, on the basis of obtaining the effective transformation volume coefficient I, it is also necessary to obtain the effective transformation volume of the fracture network. The calculation size of the effective transformation volume is:

[0094] S eff =S f *I

[0095] Among them, S eff Represents the actual effective reservoir reconstruction area of ​​hydraulic fracturing; S f Represents the reservoir reconstruction area under ideal conditions.

[0096] The method for evaluating the effective transformation volume of multi-scale artificial fractures in the present invention can obtain the relationship between different proppant particle sizes, sand ratios, fracture complexity and other parameters and the effective transformation volume, and then optimize these parameters to guide efficient development on site. The method for evaluating the effective transformation volume of multi-scale artificial fractures can obtain the relationship between different proppant particle sizes, sand ratios, fracture complexity and other parameters and the effective transformation volume, and realizes rapid and accurate evaluation of the fracturing scale through the effective fracture length identification method, which has guiding significance for the efficient development of tight oil reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0097] Figure 1 A flowchart of a specific embodiment of the method for evaluating the effective reconstruction volume of multi-scale artificial sutures of the present invention;

[0098] Figure 2 A flow field (pressure field) distribution diagram is obtained by numerical solution in a specific embodiment of the present invention;

[0099] Figure 3 It is a schematic diagram of the normal inflow velocity of the fluid into the fracture in a specific embodiment of the present invention. DETAILED DESCRIPTION

[0100] It should be noted that the following detailed descriptions are exemplary and are intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meanings as those commonly understood by those skilled in the art to which the present invention belongs.

[0101] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, it indicates the presence of features, steps, operations and / or combinations thereof.

[0102] like Figure 1 As shown, Figure 1 The present invention is a flow chart of the method for evaluating the effective transformation volume of multi-scale artificial sutures.

[0103] Step 1: Calculate the conductivity k at each location in the crack based on the distribution of sand concentration in the crack wf :

[0104]

[0105] Step 2: Calculate the proppant volume fraction in the half-length direction of the fracture. Its value is equal to the maximum proppant volume fraction multiplied by the step function value at that position:

[0106]

[0107] Where: d f is the proppant volume fraction in the fracture half-length direction; d fi is the maximum proppant volume fraction; is the normalized step function value at the crack half-length x.

[0108] Step 3: Calculate the permeability of the fracture half-length direction:

[0109]

[0110] Where: φ f is the porosity of the fracture; d p is the proppant diameter, m; S is the sphericity of the proppant; for the pores formed by hydraulic fracturing, λ m ≈25 / 12.

[0111] Step 4: Establish the fluid motion equation with the starting pressure gradient during the development of tight oil reservoirs, which can be expressed as follows:

[0112]

[0113] Step 5: Substituting the equation of motion in step 4 into the continuity equation, we can obtain the governing equation for matrix flow in tight reservoirs:

[0114]

[0115] Step 6: The equation of motion of the fluid in the fracture can be expressed as follows:

[0116]

[0117] Step 7: Substituting the motion equation of fracture fluid flow into the continuity equation of discrete fracture fluid flow, its control equation can be obtained:

[0118]

[0119] Step 8: Based on the mathematical model of fracture and matrix seepage, it is assumed that the pressure at the interface between the fracture and the matrix is ​​equal, as shown in the following formula:

[0120]

[0121] Step 9: Based on the mathematical model established in the above steps, perform numerical solution to obtain the flow field of tight reservoir fracturing development considering the starting pressure gradient.

[0122] Step 10: Calculate the normal inflow velocity of the fluid in the fracture: Based on the obtained flow field and the flow distribution of the fracture, for artificial fracturing fractures, the normal inflow velocity of the fluid is integrated over the unit fracture length to obtain the fluid flow rate per unit length, as shown in the following formula:

[0123] Q1=∫u n dx

[0124] Step 11: Establish a method for determining the effective length of a single crack: Due to factors such as uneven sanding of cracks, the flow contributions of each part of the crack are not equal, so there is an effective crack length. The effective length of a single crack is defined as the length of the part of the crack that can contribute to the main industrial flow, as shown in the following formula:

[0125]

[0126] Step 12: Calculate the effective transformation volume coefficient of multi-stage fracturing. The calculation method is based on the assumption that a certain fracture network has 1 primary main fracture with a length of L1; n secondary branch fractures with a length of L2; and m tertiary derivative fractures with a length of L3. After obtaining the effective lengths of all fractures, the overall effective transformation volume coefficient I of the fracture can be obtained by weighted average, as shown in the following formula:

[0127]

[0128] Step 13: On the basis of obtaining the effective transformation volume coefficient, it is also necessary to obtain the effective transformation volume of the fracture network. The calculation size of the effective transformation volume is:

[0129] S eff =S f *I

[0130] Among them, S eff Represents the actual effective reservoir reconstruction area of ​​hydraulic fracturing; S f Represents the reservoir reconstruction area under ideal conditions.

[0131] Through the transformation volume coefficient calculation method, we obtain the relationship between different proppant particle size, sand ratio, fracture complexity and other parameters and the effective transformation volume, and then optimize these parameters to guide efficient on-site development.

[0132] In the specific embodiment of the application of the present invention, the present invention is utilized. Taking the Shengli Oilfield Yi 171-Slant 2VF well as an example, the present invention is further explained.

[0133] The well depth of Yi 171-Xie 2VF is 3940m, the fracturing section is 3599.4m~3668.5m, the span is 102.7m, and the oil layer thickness is 19.1m. According to the logging interpretation of the fracturing layer, the average porosity is 0.106, the average permeability is 5.45mD, and the average density of the ground crude oil is 0.835-0.8448g / cm 3 , with an average viscosity of 3.8 to 7.07 mPa·s. In the 5th layer of fracturing, 20 / 40 mesh ceramsite proppant was used, and the sand concentration was 10 kg / m 2 The closing pressure is 10-90 MPa, and the supporting half-slit length is 172m-195m. The initial design mining method is natural energy mining. After about 300 days of self-spraying, the long-barrel pump is used for artificial lifting.

[0134] First, the following formula is used to calculate the proppant type, sand concentration, proppant density, and crushing rate:

[0135]

[0136] The fracture conductivity is calculated to be 18 to 27 D·cm.

[0137] Secondly, the Yi171-Xie2VF well was brought into the established multi-media seepage mathematical model to simulate the development of natural energy. The boundary condition of the fracturing well was set to constant pressure production, and the pressure field distribution diagram was obtained ( Figure 2 ).

[0138] Next, the normal inflow velocity of the fluid into the fracture is calculated according to the following formula: Figure 3 shown.

[0139] Q1=∫u n dx

[0140] Finally, the effective length of the hydraulic fracture when the commercial flow ratio R% is 85% is determined, that is, the fracture part whose production contribution accounts for 85% of the total production, and its effective length is 114m.

[0141] By the following formula:

[0142]

[0143] The effective transformation volume coefficient I is calculated, and the actual effective transformation area of ​​the reservoir by hydraulic fracturing can be obtained through the reservoir transformation area under ideal conditions.

[0144] S eff =S f *I

[0145] Through the calculation method of the transformation volume coefficient, the relationship between different proppant particle size, sand ratio, fracture complexity and other parameters and the effective transformation volume can be obtained. The effective fracture length identification method can also achieve a rapid and accurate assessment of the fracturing scale, which has guiding significance for the efficient development of tight oil reservoirs.

[0146] Through this method, the relationship between different proppant particle size, sand ratio, fracture complexity and other parameters and the effective transformation volume can be obtained, and then these fracturing parameters can be optimized, leading to efficient on-site development of dense oil reservoirs.

[0147] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art can still modify the technical solutions recorded in the aforementioned embodiments or replace some of the technical features therein with equivalents. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

[0148] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A method for evaluating the effective reconstruction volume of multi-scale artificial sutures, characterized in that: The method for evaluating the effective reconstruction volume of multi-scale artificial sutures includes: Step 1, calculating the fracture conductivity according to the parameters of proppant type, sand concentration, proppant density and crushing rate; Step 2, establish a multi-media seepage mathematical model, perform numerical solution, and obtain the flow field of tight reservoir fracturing development considering the starting pressure gradient; Step 3, calculating the normal inflow velocity of the fluid into the fracture; Step 4, establishing a method for determining the effective length of a single crack; Step 5, calculating the effective transformation volume coefficient of multi-stage fracturing; Step 6, based on the effective transformation volume coefficient, obtaining the effective transformation volume of the fracture network; In step 1, the conductivity k at each point in the crack is calculated based on the distribution of sand concentration in the crack. wf : Where: Kw f is the fracture conductivity, mD·m; r is the proppant particle size, m; a is the distance between two proppant particles reduced due to compression, m; B t is the breakage rate; C is the sand concentration, i.e. the proppant particle concentration, kg·m -2 ; V 单 is the proppant volume, m 3 ; ρ s is the proppant density, kg·m -3 ; h1 is the distance that the proppant is embedded in the fracture, m; τ is the tortuosity; In step 5, the calculation method of the effective transformation volume coefficient of multi-stage fracturing is based on the assumption that a certain fracture network has 1 primary main fracture with a length of L1; n secondary branch fractures with a length of L2; and m tertiary derivative fractures with a length of L3. After obtaining the effective lengths of all fractures, the overall effective transformation volume coefficient I of the fracture is obtained by weighted average, as shown in the following formula: Where: I is the effective transformation volume coefficient; L1 is the main fracture fracturing length, m; L2 is the fracturing length of secondary branch fractures, m; L3 is the third-level derived fracture fracturing length, m; L e1 is the effective crack length of the main crack, m; L e2 is the effective crack length of the secondary branch crack, m; L e3 is the effective crack length of the third-level derivative crack, m; n is the number of secondary branch seams, dimensionless; m is the number of third-level derived seams, dimensionless; a, b, and c are the effective contribution rates of the main crack, secondary branch crack, and tertiary derivative crack, respectively, and are dimensionless; In step 6, on the basis of obtaining the effective transformation volume coefficient I, it is also necessary to obtain the effective transformation volume of the fracture network. The calculation size of the effective transformation volume is: S eff =S f *I Among them, S eff Represents the actual effective reservoir reconstruction area of ​​hydraulic fracturing; S f Represents the reservoir reconstruction area under ideal conditions.

2. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 1, characterized in that: Step 2 includes: Step 21: Calculate the proppant volume fraction in the half-length direction of the fracture; Step 22: Calculate the permeability in the half-length direction of the fracture; Step 23: Establish the fluid motion equation including the starting pressure gradient during the development of tight oil reservoirs; Step 24: Substitute the motion equation in step 23 into the continuity equation to obtain the tight reservoir matrix flow control equation; Step 25: Establish the fluid motion equation in the fracture; Step 26: Substitute the motion equation of the fracture fluid flow into the continuity equation of the discrete fracture fluid flow to obtain its control equation; Step 27: Based on the mathematical model of seepage in fractures and matrix, it is assumed that the pressure at the interface between fractures and matrix is ​​equal; Step 28: Establish a multi-media seepage mathematical model based on the above steps.

3. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 2, characterized in that: In step 21, the proppant volume fraction in the fracture half-length direction is calculated; Its value is equal to the maximum proppant volume fraction multiplied by the step function value at that location: Where: d f is the proppant volume fraction in the fracture half-length direction; d fi is the maximum proppant volume fraction; is the normalized step function value at the crack half-length x.

4. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 3, characterized in that: In step 22, the permeability in the half-length direction of the fracture is calculated using the formula: Where: φ f is the porosity of the fracture; d p is the proppant diameter, m; S is the sphericity of the proppant; for the pores formed by hydraulic fracturing, λ m ≈25 / 12.

5. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 4, characterized in that: In step 23, the fluid motion equation containing the starting pressure gradient during the development of tight oil reservoirs is established and expressed in the following form: Where: u x is the fluid velocity, m·s -1 ; K m is the matrix permeability, m 2 ; μ is the fluid viscosity, mPa·s; p m is the matrix pressure, Pa; x is the distance from the crack, m; λ x is the starting pressure gradient, MPa·m -1 .

6. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 5, characterized in that: In step 24, the equation of motion in step 23 is substituted into the continuity equation to obtain the tight reservoir matrix flow control equation: Where: is the matrix porosity, dimensionless; u is the fluid velocity, m·s -1 ; ρ is the fluid density, kg·m -3 ; t is time, s.

7. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 6, characterized in that: In step 25, the equation of motion of the fluid in the fracture is expressed as follows: Where: K f is the fracture permeability, m 2 ; P f is the pressure in the fracture zone, Pa; μ is the fluid viscosity, mPa·s.

8. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 7, characterized in that: In step 26, the motion equation of the fracture fluid flow is substituted into the continuity equation of the discrete fracture fluid flow to obtain its control equation: Where: is the fracture porosity, dimensionless; d f is the crack width, m.

9. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 8, characterized in that: In step 27, based on the mathematical model of fracture and matrix seepage, it is assumed that the pressure at the interface between the fracture and the matrix is ​​equal, as shown in the following formula: Where: The interface between crack and matrix P f is the pressure in the fracture zone, Pa; p m is the matrix pressure, Pa.

10. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 1, characterized in that: In step 3, the normal inflow velocity of the fluid in the fracture is calculated based on the obtained flow field and the flow distribution of the fracture. For artificial fracturing fractures, the normal inflow velocity of the fluid is integrated over the unit fracture length to obtain the fluid flow rate per unit length, as shown in the following formula: Q1=∫u n dx Where: u n is the normal inflow velocity of the fluid into the fracture, m·s -1 ; x is the unit length, m; Q1 is the fluid flow rate per unit length, m 3 ·s.

11. The method for evaluating the effective reconstruction volume of multi-scale artificial suture according to claim 1, characterized in that: In step 4, a method for determining the effective length of a single crack is established, and the effective length of a single crack is defined as being equal to the length of the portion of the crack that can contribute to the main industrial flow, as shown in the following formula: Where: L e is the effective crack length, m; L f is the fracture fracturing length, m; R is the effective contribution rate of cracks; u n is the normal inflow velocity of the fluid into the fracture, m·s -1 .

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