Inversion method for fracture parameters and expansion form of horizontal fracture after fracturing

Abstract

The invention relates to the technical field of oil and gas field development, in particular to a post-fracturing horizontal fracture parameter and extension form inversion method. A post-fracturing horizontal fracture parameter and expansion form inversion method comprises the following steps: (a) establishing a horizontal fracture equivalent seepage model, and deducing a productivity equation; (b) inverting the horizontal fracture area by fitting the initial yield; (c) inverting the permeability of the horizontal seam by fitting the cumulative yield of the first year, and establishing a fitting target equation of the cumulative yield Q accumulation of the first year and the permeability Kf of the horizontal seam; (d) quantitatively evaluating the expansion form of the horizontal seam; and (e) calculating the single-well crack transformation area and the crack permeability, and determining the crack form direction. The method has the beneficial effects that the horizontal fracture parameter and extension form inversion after fracturing is realized based on the yield data, the precision of the inversion result is relatively high, the problem that the artificial fracture is depicted under the condition that only production dynamic data exists is solved, the influence of the fracture on the production well yield can be quickly analyzed, the next measure plan is put forward, and the development efficiency is improved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method for inverting horizontal fracture parameters and propagation morphology. Background Technology

[0002] With the continuous development of oil and gas resources, the reserves of conventional oil and gas reservoirs are gradually decreasing, while unconventional oil and gas reservoirs such as low-permeability and ultra-low-permeability reservoirs have become important development targets. These reservoirs have very low permeability, making oil and gas flow difficult. Therefore, reservoir fracturing technology is needed to create artificial fractures to increase reservoir permeability, thereby increasing oil and gas production and improving recovery rates. Thus, accurately understanding the parameters and trends of fracturing fractures is crucial for evaluating fracturing-induced production enhancement and subsequent energy replenishment. However, in actual production, the number of wells monitoring fracturing fractures in a region is small, and the cost is high. To achieve economical development and save costs, fracturing fractures are not monitored in most areas.

[0003] The main methods for inverting fracture parameters in oil and gas reservoirs currently include: 1. Horizontal fracture inversion methods based on modern well testing theory; 2. Horizontal fracture inversion methods based on variable production and pressure theory; 3. Inversion methods based on fracturing fluid flowback data; 4. Inter-well microseismic technology; and 5. Multi-fracture parameter inversion methods based on g-function curve analysis. While there are many inversion methods available, each has different applicable conditions. Well testing methods require shut-in testing to recover pressure data, which affects normal well production. Inter-well microseismic technology can obtain information on fracture geometry, complexity, and spatial location, but it is difficult to quantitatively evaluate seepage parameters such as fracture permeability and pore volume. Variable production and pressure methods require pressure monitoring data; if pressure data is lacking in the field, inversion data cannot be performed. Therefore, each method has limitations, and more economical and efficient methods are needed to describe fracture characteristics to better guide actual development work and improve development efficiency and benefits. Summary of the Invention

[0004] To address the aforementioned problems, this invention provides a method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing, the details of which are as follows: A method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing includes the following steps: (a) Establish an equivalent seepage model for horizontal joints and derive the production capacity equation; Based on seepage mechanics theory, horizontal fractures are equivalent to virtual wells. Combining radial flow outside the virtual well reservoir and linear flow inside the virtual well, a productivity equation considering elliptical steady-state seepage is established, the expression of which is: (1) In the formula, Q For production, K For matrix permeability, h For the effective thickness of the reservoir, pe The formation pressure at the outer boundary is MPa; p w 1. Formation pressure at the horizontal fracture, MPa; a. Major axis of the elliptical drainage zone; b. Minor axis of the horizontal fracture, in meters. μ The viscosity of crude oil is given in mPa·s. B This is the crude oil volume coefficient, in dimensionless form. x f The semi-major axis of the horizontal fracture in hydraulic fracturing, in meters (m). Kz Expressed as vertical permeability, unit: dimensionless; (b) The horizontal crack area was inverted by fitting the initial production; Using well logging interpretation to obtain matrix permeability and reservoir thickness parameters, an initial production rate Q is established. 初始 The objective equation for fitting the horizontal seam area S is: (2) The coefficients in the fitted curve are calibrated based on the actual initial output to obtain the horizontal seam area through inversion. The initial output is fitted with the horizontal crack area, and the horizontal crack area is obtained by inversion based on the actual initial output. Based on the characteristics of each stage of the oil well life cycle, the initial production is controlled by matrix permeability, effective reservoir thickness, and horizontal fracture area. Parameters such as matrix permeability and effective reservoir thickness are determined by well logging interpretation. The initial production is fitted with the horizontal fracture area using fitting software. By changing the horizontal fracture area, the change in initial production is determined. The coefficients in the fitting target equation are determined. The coefficients in the fitting curve are calibrated based on the actual initial production to obtain the horizontal fracture area through inversion. In the fitting objective equation, a, b, and c are fitting coefficients. These coefficients determine the specific functional relationship between the initial production and the horizontal fracture area S. Different reservoir geological conditions, fluid properties, and other factors will lead to different values ​​of a, b, and c. For example, if the reservoir matrix permeability is high, under similar conditions, the initial production corresponding to the same horizontal fracture area may be higher, which will be reflected in the changes in the values ​​of a, b, and c.

[0005] (c) By fitting the cumulative production of the first year to invert the horizontal fracture permeability, the cumulative production of the first year Q is established based on the influence of fracture and matrix crossflow. 累计 Permeability of horizontal seams K f The fitting objective equation is: (3) In the formula, Q 累计 For the first year's cumulative production, K fdenoted as the horizontal seam permeability; where A1, B1, and C1 are fitting coefficients. The coefficients in the fitted curve are calibrated based on the actual cumulative production of the production well in the first year, and the permeability of the horizontal fracture is obtained by inversion. (d) Quantitatively evaluate the horizontal fracture propagation morphology, use wavelet transform to analyze multi-well interference, and use the grey relational method to calculate the inter-well connectivity coefficient. By analyzing the similarity between the production output of a production well and the pressure changes of surrounding wells, a quantitative evaluation of the connectivity of a single well in different directions can be achieved, and the horizontal fracture propagation morphology can be determined. (4) This formula is the equation for calculating the resolution coefficient in grey relational analysis, where, Δ is the resolution coefficient, Δ(min) is the minimum value of the comparison sequence, and Δ(max) is the maximum value of the comparison sequence. 0i ( k To compare the values ​​in the sequence, ρ For frequency coefficients, In the formula, r i is the inter-well connectivity coefficient, dimensionless; N represents the number of terms involved in the calculation, dimensionless; k Represents the number of wells, unit: dimensionless; In grey relational analysis, the resolution coefficient is a key parameter used to adjust the resolution of the correlation coefficient. Its core function is to balance the "resolution" and "stability" of the analysis results. Specifically, it can be understood from the following dimensions: Theoretical value range: (0, 1); In practical applications, the default value is usually (0.5), which is an empirical value that balances "resolution" and "stability". (e) Calculate the fracture stimulation area and fracture permeability of a single well, and determine the fracture morphology and direction; The horizontal seam area S obtained from step (b) and the horizontal seam permeability obtained from step (c) are used to invert the data. K f As a single well fracture parameter; based on the inter-well connectivity coefficients calculated in step (d), the direction corresponding to the maximum connectivity coefficient is determined as the expansion direction of the fracture major axis, and the ratio of the major axis to the minor axis of the ellipse is determined according to the ratio of the connectivity coefficients in each direction; combined with the horizontal fracture area S, the major axis and semi-axis of the fracture are calculated according to the ellipse area formula to complete the quantitative evaluation of the fracture scale parameters.

[0006] Assuming the crack is elliptical, its area formula can be further derived by combining the relationship between production volume and crack area: (5) In the formula: S This refers to the area of ​​fracture repair in a single well.

[0007] In step (2), fitting two curves is to calculate the actual crack area and crack permeability. Based on the theoretical formula, multiple sets of actual data are imported and then fitted. The fitting rate reaches more than 90%, and the final fitted curve is determined. Then, the curve data is substituted into the formula to calculate the correlation coefficient.

[0008] Among them, steps (d) and (e) complement each other. Step (d) qualitatively determines the approximate direction from the correlation coefficient, while step (e) mainly quantitatively determines the crack morphology and direction.

[0009] Preferably, step (1) includes: based on the seepage mechanics theory, assuming that the reservoir is homogeneous and of equal thickness, ignoring the effects of gravity and capillary force, the horizontal fractures conduct infinitely and have closed boundaries, and considering the reservoir boundary as a closed boundary, establishing an equivalent seepage model for the horizontal fractures; The model treats horizontal fractures as virtual wells, with linear flow inside and radial flow in the outer reservoir. The productivity equation is derived through nodal pressure continuity. Preferably, the establishment of the productivity equation for elliptical steady-state seepage in step (a) needs to satisfy the conditions for elliptical steady-state seepage in the formation and the governing equation for elliptical steady-state seepage in the formation: (6) In the formula, p Formation pressure, unit: MPa; ξ Let x be the x-coordinate of the ellipse, m; η The ordinate of the ellipse is in meters (m). Its boundary condition is that the pressure inside the fracture is constant and equal to the bottom-hole flowing pressure.

[0010] Formula (5) simplifies and derives the pressure distribution formula: (7) In the formula, q out For reservoir fluid production outside the virtual well, m 3 / d;μ is the crude oil viscosity, mPa·s; B The crude oil volume coefficient, unit: dimensionless; K The average permeability of the reservoir is 10 －3 μm 2 ; h The reservoir thickness is in meters (m). ξ The x-coordinate of the ellipse; ξ w These are the elliptical coordinates of the virtual well, in meters (m). Considering an isotropic, elliptical, isobaric formation with an infinitely conductive elliptical horizontal fracture, elliptical steady-state flow occurs in the formation. Neglecting the pressure loss of fluid seepage in the horizontal fracture, the formation steady-state flow control equation (6) is obtained: This is further simplified to the pressure distribution formula (7): Since the horizontal fracture is infinitely conductive, the pressure inside the fracture drops to zero, equal to the bottom hole pressure p. w Using horizontal fractures as nodes, a production capacity equation is established by connecting the reservoir production capacity equation outside the virtual well with the linear production capacity equation inside the virtual well: (8) Preferably, in step (b), it is necessary to collect the production dynamic data of each well in the target area, and then fit the initial production of depletion development with the horizontal fracture area according to formula (2).

[0011] When calculating the actual crack area and crack permeability, according to formula (2), multiple sets of actual data are imported and then fitted. The fitting rate reaches more than 90%, and the final fitting curve is determined. Then, the curve data is substituted into formula (2) to calculate the correlation coefficient.

[0012] Preferably, in step (3), the cumulative production in the first year is fitted with the horizontal fracture permeability, and the horizontal fracture permeability is obtained by inversion based on the actual production in the first year. The cumulative production in the first year is controlled by the matrix permeability, the effective thickness of the reservoir, and the horizontal fracture permeability.

[0013] Based on the characteristics of each stage of the oil well lifecycle, after reaching the maximum swept volume, fractures and matrix channeling have a significant impact on production. The cumulative production in the first year is controlled by matrix permeability, effective reservoir thickness, and horizontal fracture permeability. Parameters such as matrix permeability and effective reservoir thickness are determined by well logging interpretation. The cumulative production in the first year is then fitted to the horizontal fracture permeability using fitting software. By changing the horizontal fracture permeability, the change in the cumulative production in the first year is determined, and the coefficients in the fitting objective equation are determined. The coefficients in the fitted curve are calibrated based on the actual cumulative production in the first year of the producing well, and the horizontal fracture permeability is obtained through inversion.

[0014] Preferably, in step (4), a similarity analysis is performed between the production output of the production well and the surrounding wells based on the principle of similarity.

[0015] When two oil wells are depleted during development, there will be a superposition of pressure drops between the two wells. That is, the pressure drop of one well will affect the pressure drop of the disturbed well. The pressure change patterns of the two wellheads are similar, but there is a certain time delay.

[0016] Wavelet transform technology was used to extract the multi-well interference problem into a two-well interference problem. Based on the similarity principle, the production rate of the producing well was analyzed against that of surrounding wells. The grey relational analysis method was used to calculate the interference coefficient between the two wells, obtaining the connectivity coefficient of a single well in different directions. The connectivity of a single well in different directions was quantitatively evaluated based on the fracture area. Based on the calculation results, the horizontal fracture propagation morphology was determined.

[0017] Preferably, the wavelet transform analysis method for multi-well interference used in step (4) is as follows: (1) Data acquisition: Collect relevant data from multiple wells, including at least the data series of pressure and flow rate changes over time; (2) Wavelet transform processing: The collected well data are subjected to wavelet transform. Wavelet transform can convert the time domain signal to the time-scale domain. By selecting appropriate wavelet basis functions, the local features of the signal can be analyzed at different scales. (3) Feature analysis.

[0018] The data acquisition section first requires collecting relevant data from multiple wells, such as time-varying data sequences of pressure and flow rate. This data includes information about interference between wells.

[0019] The wavelet transform process is as follows: The collected well data were subjected to wavelet transform, which converts time-domain signals to the time-scale domain. There is an indirect correspondence between scale and frequency; smaller scales correspond to higher frequency signals, while larger scales correspond to lower frequency signals. By selecting appropriate wavelet basis functions, local features of the signal, such as abrupt changes and trend changes, can be accurately decomposed and extracted at different scales. For interference signals of different frequencies, low-frequency interference may correspond to changes over a longer time scale, while high-frequency interference corresponds to changes over a shorter time scale. Wavelet transform can separate these interference components with different frequency characteristics, laying the foundation for subsequent data correlation analysis or feature recognition.

[0020] Feature analysis: Observing the coefficient distribution after wavelet transform, the magnitude and distribution characteristics of coefficients of different frequency components can reflect the characteristics of the interference signal. For example, frequency components with larger coefficients may correspond to the main interference source frequencies. Furthermore, by analyzing the correlation between wavelet transform results from different wells, the degree and direction of interference between wells can be determined; for example, if the coefficient change trends of two wells are similar at certain frequency components, it indicates a strong correlation between them in the interference corresponding to those frequencies.

[0021] Furthermore, it also includes a method for inverting horizontal fracture parameters and propagation morphology after fracturing, which specifically includes: (1) Collect production dynamic data of the target well group and draw the initial production-horizontal fracture area fitting curve and the cumulative production-fracture permeability fitting curve; (2) Select typical well groups to calculate the connectivity coefficients in each direction and generate a distribution map of fracture propagation morphology; (3) A three-dimensional fracture network model is established by combining the fracture area, permeability parameters and connectivity coefficient matrix obtained by inversion.

[0022] The advantages of this invention are as follows: Based on seepage mechanics theory, an equivalent seepage model of horizontal fractures is established. Based on this, a production capacity equation is derived. Combining the characteristics of each stage of the oil well lifecycle, the initial production rate is fitted with the horizontal fracture area, and the cumulative production rate in the first year is fitted with the horizontal fracture permeability. The horizontal fracture area and permeability are obtained by inversion from actual production data. A wavelet transform signal processing algorithm is used to extract the multi-well interference problem into a two-well interference problem. A grey relational analysis method is used to perform similarity analysis between the production well's output and surrounding wells, calculating the inter-well interference coefficient. This enables quantitative evaluation of the connectivity of a single well in different directions and clarifies the horizontal fracture extension morphology. This invention achieves the inversion of horizontal fracture parameters and extension morphology after fracturing based on production data. The inversion results have high accuracy, solving the problem of characterizing artificial fractures when only dynamic production data is available. It allows for rapid analysis of the impact of fractures on production well output, proposing next steps and improving development efficiency. Attached Figure Description

[0023] Figure 1 This is a flowchart of the present invention; Figure 2 Schematic diagram of equivalent seepage model for horizontal joint; Figure 3 Diagram of the production well lifecycle; Figure 4 This is a schematic diagram of the pressure distribution caused by interference between wells; Figure 5 This is the first fitting curve for Example 1; Figure 6 This is the second fitting curve for Example 1; Figure 7 The cumulative production of the production well in the first year of Example 1 was fitted with the permeability of the horizontal fracture to obtain the fitting curve; Figure 8 The fracture connectivity coefficient of each well in the target area in Example 1; Figure 9 The fracture propagation morphology of each well in the target area in Example 1 is shown. Detailed Implementation

[0024] Example 1 The specific implementation of the method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to the present invention includes: (1) Collect production dynamic data of the target well group and draw the initial production-horizontal fracture area fitting curve and the cumulative production-fracture permeability fitting curve; (2) Select typical well groups to calculate the connectivity coefficients in each direction and generate a distribution map of fracture propagation morphology; (3) A three-dimensional fracture network model is established by combining the fracture area, permeability parameters and connectivity coefficient matrix obtained by inversion.

[0025] Example 2 Taking a certain oilfield as an example, this paper details the specific procedures for obtaining the parameters and propagation morphology of horizontal fractures after hydraulic fracturing using this method.

[0026] 1. Collect production dynamic data of each well in the target area: Fit the initial production rate and the horizontal fracture area according to formula (2) to obtain the fitting curve as shown in the figure. Figure 5 As shown, the equation of the fitted curve is:

[0027] The initial output and the horizontal seam area were fitted according to formula (2), and the fitted curve is shown below. Figure 6 As shown, the equation of its fitted curve is:

[0028] The horizontal seam area is obtained by inversion based on the actual initial production; 2. Based on formula (3), the cumulative production of the production well in the first year is fitted to the horizontal fracture permeability, and the fitted curve is as follows: Figure 7 As shown, the equation of its fitted curve is:

[0029] The area of ​​the horizontal seam can be obtained by inverting the actual cumulative output of the first year; 3. Select typical well groups, use actual well group production data, and utilize connectivity coefficients. The connectivity coefficient of a single well in different directions was calculated, and the horizontal fracture propagation morphology was obtained based on the calculation results. The fracture connectivity coefficients of each well in the target area are shown in the figure. Figure 8 The fracture propagation morphology of each well in the target area is shown in the figure. Figure 9 The specific results are shown in Table 1, which shows the calculated crack area and the lengths of the major and minor axes: Table 1: .

Claims

1. A method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing, characterized in that, Includes the following steps: (a) Establish an equivalent seepage model for horizontal joints and derive the production capacity equation; Based on seepage mechanics theory, horizontal fractures are equivalent to virtual wells. Combining radial flow outside the virtual well reservoir and linear flow inside the virtual well, a productivity equation considering elliptical steady-state seepage is established, the expression of which is: （1） In the formula, Q For production, K For matrix permeability, h For the effective thickness of the reservoir, p e The formation pressure at the outer boundary is MPa; p w 1. Formation pressure at the horizontal fracture, MPa; a. Major axis of the elliptical drainage zone; b. Minor axis of the horizontal fracture, in meters. μ The viscosity of crude oil is given in mPa·s. B This is the crude oil volume coefficient, in dimensionless form. x f The semi-major axis of the horizontal fracture in hydraulic fracturing, in meters (m). Kz Expressed as vertical permeability, unit: dimensionless; (b) The horizontal crack area was inverted by fitting the initial production; Using well logging interpretation to obtain matrix permeability and reservoir thickness parameters, an initial production rate Q is established. 初始 Area of ​​horizontal seam S The fitting objective equation is: （2） The coefficients in the fitted curve are calibrated based on the actual initial production to obtain the horizontal seam area through inversion. S ; (c) By fitting the cumulative production of the first year to invert the horizontal fracture permeability, the cumulative production of the first year Q is established based on the influence of fracture and matrix crossflow. 累计 With horizontal seam permeability K f The fitting objective equation is: （3） In the formula, Q 累计 This represents the cumulative production for the first year. K f Let A be the horizontal seam permeability; where A1, B1, and C1 are fitting coefficients. The coefficients in the fitted curve are calibrated based on the actual cumulative production of the production well in the first year, and the horizontal fracture permeability is obtained by inversion. (d) Quantitatively evaluate the horizontal fracture propagation morphology, use wavelet transform to analyze multi-well interference, and use the grey relational method to calculate the inter-well connectivity coefficient. By analyzing the similarity between the production output of a production well and the pressure changes of surrounding wells, a quantitative evaluation of the connectivity of a single well in different directions is achieved. Furthermore, the resolution coefficient calculation equation in grey relational analysis is used to determine the horizontal fracture propagation morphology. （4） In the formula, Δ is the resolution coefficient, Δ(min) is the minimum value of the comparison sequence, and Δ(max) is the maximum value of the comparison sequence. 0i ( k To compare the values ​​in the sequence, ρ For frequency coefficients, In the formula, r i is the inter-well connectivity coefficient, dimensionless; N represents the number of terms involved in the calculation, dimensionless; k Represents the number of wells, unit: dimensionless; (e) Calculate the fracture stimulation area and fracture permeability of a single well, and determine the fracture morphology and direction; The horizontal fracture area S obtained from step (b) and the horizontal fracture permeability Kf obtained from step (c) are used as fracture parameters for a single well. Based on the inter-well connectivity coefficients calculated in step (d), the direction corresponding to the maximum connectivity coefficient is determined as the expansion direction of the fracture's major axis. The ratio of the major axis to the minor axis of the ellipse is determined according to the ratio of the connectivity coefficients in each direction. Combined with the horizontal fracture area S, the major axis and semi-major axis of the fracture are calculated according to the ellipse area formula, thus completing the quantitative evaluation of the fracture scale parameters. Assuming the crack is elliptical, its area formula can be further derived by combining the relationship between production volume and crack area: （5） In the formula: S is the fracture modification area of ​​a single well.

2. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: Step (a) includes: based on the theory of seepage mechanics, assuming that the reservoir is homogeneous and of equal thickness, ignoring the effects of gravity and capillary force, the horizontal fractures are infinitely conductive and have closed boundaries, and considering the reservoir boundary as a closed boundary, establishing an equivalent seepage model for the horizontal fractures; the model regards the horizontal fractures as virtual wells, with linear flow inside and radial flow outside the reservoir, and derives the production capacity equation through the continuity of nodal pressure.

3. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: The productivity equation for elliptical steady-state seepage in step (a) must satisfy the conditions for elliptical steady-state seepage in the formation and the governing equation for elliptical steady-state seepage in the formation: （6） In the formula, p Formation pressure, unit: MPa; ξ Let x be the x-coordinate of the ellipse, m; η The ordinate of the ellipse is in meters (m). Its boundary condition is that the pressure inside the fracture is constant and equal to the bottom-hole flowing pressure; Formula (5) simplifies and derives the pressure distribution formula: （7） In the formula, q out For reservoir fluid production outside the virtual well, m 3 / d;μ is the crude oil viscosity, mPa·s; B The crude oil volume coefficient, unit: dimensionless; K The average permeability of the reservoir is 10 －3 μm 2 ; h The reservoir thickness is in meters (m). ξ The x-coordinate of the ellipse; ξ w It is the x-coordinate of the ellipse of the virtual well, in meters.

4. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: In step (b), it is necessary to collect production dynamic data of each well in the target area, and then fit the initial production of depletion development with the horizontal fracture area according to formula (2). Finally, fit the initial production with the horizontal fracture area according to formula (2).

5. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: In step (c), the cumulative production in the first year is fitted with the horizontal fracture permeability, and the horizontal fracture permeability is obtained by inversion based on the actual production in the first year. The cumulative production in the first year is controlled by the matrix permeability, the effective thickness of the reservoir, and the horizontal fracture permeability.

6. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: In step (d), a similarity analysis is performed between the production output of the production well and the surrounding wells based on the principle of similarity.

7. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to claim 1, characterized in that: The wavelet transform analysis method used in step (d) to analyze multi-well interference is as follows: (1) Data acquisition: Collect relevant data from multiple wells, including at least the data series of pressure and flow rate changes over time; (2) Wavelet transform processing: The collected well data are subjected to wavelet transform. Wavelet transform can convert the time domain signal to the time-scale domain. By selecting appropriate wavelet basis functions, the local features of the signal can be analyzed at different scales. (3) Feature analysis.

8. The method for inverting horizontal fracture parameters and propagation morphology after hydraulic fracturing according to any one of claims 1-7, characterized in that: The specific implementation includes: (1) Collect production dynamic data of the target well group and draw the initial production-horizontal fracture area fitting curve and the cumulative production-fracture permeability fitting curve; (2) Select typical well groups to calculate the connectivity coefficients in each direction and generate a distribution map of fracture propagation morphology; (3) A three-dimensional fracture network model is established by combining the fracture area, permeability parameters and connectivity coefficient matrix obtained by inversion.

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