Shale gas well production prediction method, system, storage medium and electronic device

Abstract

The present invention discloses a shale gas well production prediction method, system, storage medium and electronic device, and relates to the field of oil and gas exploration technology. The method predicts the production of each section of the fracture by segmenting the fractures of the shale gas well, and constructing a production prediction model for the early non-steady-state flow stage and a production decline model for the late quasi-steady-state flow stage of each section. The prediction method can well solve the problems that the existing shale gas well production capacity evaluation method is difficult to apply in the early stage of gas well production, difficult to consider complex fracture morphology and lacks pertinence. Starting from the early and late production decline laws of shale gas wells, the production decline mode of the early and late stages of the gas well is determined by combining the shale gas seepage mechanism, production data characteristic line analysis technology, and high-pressure physical property analysis technology. After that, the complex fracture morphology is considered to correct the late production decline mode of the gas well. On this basis, the gas well production decline analysis is carried out, and the production capacity of complex fracture network gas wells can be quickly and accurately predicted.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas exploration, and in particular relates to a shale gas well production prediction method, system, storage medium and electronic equipment. Background Art

[0002] my country has abundant shale gas resources and huge potential for exploration and development, which is an important aspect of the 13th Five-Year Plan for the development of natural gas. Accurately predicting the production capacity of shale gas fracturing horizontal wells (especially in the early stages of gas field development) is a prerequisite for evaluating the development potential of gas fields and determining reasonable development technology policies.

[0003] Shale reservoirs are dense porous media with ultra-low porosity and ultra-low permeability. They have obvious multi-scale effects and diverse gas storage modes. Gas production is affected by multiple mechanisms. The seepage law of reservoir fluids is complex during production, and production capacity prediction is difficult. In addition, the complexity of well types and completion methods has also greatly increased the difficulty of shale gas well production capacity prediction. Shale gas reservoirs require horizontal well staged fracturing technology to achieve economic and effective development. However, some current fracture monitoring technologies (microseismic monitoring, radioactive or chemical indicator monitoring) and post-fracturing evaluation results have confirmed that the fracture systems produced during the gas well fracturing process are mostly non-uniform (such as unequal lengths, different spacings, and partially invalid) fracture systems. Since the coverage of the fracture system in shale gas reservoirs plays a decisive role in the gas well production capacity, the irregular fracture system has increased the difficulty of shale gas well production capacity prediction.

[0004] Therefore, the urgent problem to be solved in shale gas well productivity prediction is to develop a process-based method to accurately analyze the law of gas well production changes, while taking into account the complexity of reservoir fluid flow characteristics and the heterogeneity of fracture morphology caused by well completion as much as possible. Summary of the invention

[0005] Based on the above technical problems, the present invention proposes a shale gas well production prediction method, system, storage medium and electronic device.

[0006] In a first aspect, an embodiment of the present invention provides a shale gas well production prediction method, comprising:

[0007] Determine the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures;

[0008] Determine the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions;

[0009] Determine a pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure, and determine an interference time of an interference section corresponding to each interference distance according to the pseudo-time correction coefficient;

[0010] Based on the interference time, determining a decrease rate of the interference segment corresponding to each interference time at the beginning of the late quasi-steady-state flow stage;

[0011] Accumulating the interference segment lengths with the same interference distance to obtain the accumulated interference segment length corresponding to each interference distance, and determining the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well, and based on the ratio, determining the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage;

[0012] Determining a decline index of each interference section when the shale gas well is in a late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well;

[0013] Based on the disturbance time, decline rate, initial production and decline index of each disturbance section, a production decline model of the late quasi-steady-state flow stage corresponding to each disturbance section was constructed using a hyperbolic decline model.

[0014] The production decline model of the late quasi-steady-state flow stage corresponding to each interference section is used to predict the production of the late quasi-steady-state flow stage of each interference section of the shale gas well.

[0015] Optionally, the production decline model in the late quasi-steady-state flow stage is:

[0016]

[0017] Among them, q late (j) is the production of the jth interference section in the late quasi-steady-state flow stage, b psd is a decreasing exponential, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, D c (j) is the decreasing rate of the jth interference segment, T c (j) is the interference time corresponding to the jth interference segment, and t is time.

[0018] Optionally, the method further comprises:

[0019] determining a production decline model for an early non-steady-state flow phase of the shale gas well;

[0020] Based on the ratio of each accumulated interference section length to the total length of the fractures of the shale gas well, the production decline model of the early non-steady-state flow stage is used to construct a production prediction model of the early non-steady-state flow stage corresponding to each interference section; wherein the production prediction model of the early non-steady-state flow stage corresponding to each interference section is used to predict the production of each interference section of the shale gas well when it is in the early non-steady-state flow stage.

[0021] Optionally, the production decline model in the early non-steady-state flow stage is:

[0022]

[0023] Among them, q ear is the production of the shale gas well in the early non-steady flow stage, t is time, a and b are constants; a and b are the 1 / q and 1 / q plotted according to the production dynamic data of the shale gas well. The slope and intercept are obtained by scatter fitting the relationship curve; where q is the daily output.

[0024] Optionally, the production prediction model for the early non-steady-state flow stage corresponding to each interference section is:

[0025]

[0026] Among them, q ear (j) is the production of the jth interference section in the early non-steady flow stage, R a (j) is the ratio of the jth cumulative interference section length to the total length of the fracture of the shale gas well.

[0027] Optionally, the method further comprises:

[0028] Based on the late quasi-steady-state flow stage production decline model corresponding to each disturbance section and the early non-steady-state flow stage production prediction model, combined with the disturbance time corresponding to each disturbance section, the full-stage production decline model corresponding to each disturbance section is constructed;

[0029] The full-stage production decline models of each interference section are superimposed to obtain the total production prediction model of the shale gas well.

[0030] Optionally, the full-stage production decline model is:

[0031]

[0032] Among them, q(j) is the full-stage output of the jth interference stage;

[0033] The total output prediction model is:

[0034]

[0035] Among them, q a is the daily production of the shale gas well, and n is the number of interference sections.

[0036] Optionally, the determining of the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions includes:

[0037] S10, constructing an average formation pressure iteration equation based on the geological parameters and fluid physical property parameters of the shale gas well; wherein the average formation pressure iteration equation is:

[0038]

[0039] Where p is the average formation pressure, p i is the original formation pressure, z i is the gas compression factor in the original state, c ti is the comprehensive compressibility coefficient under the original formation pressure, μ i is the gas viscosity in the original state, m(p i ) is the pseudo pressure corresponding to the original formation pressure, p wf is the bottom hole flowing pressure, m(p wf ) is the pseudo pressure corresponding to the bottom hole flowing pressure, (c t λ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c is the average value of the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage;

[0040]

[0041]

[0042] Among them, c f is the rock compression coefficient, c w is the compressibility coefficient of water, S gi is the gas saturation in the original state, z is the gas compression factor, S wi is the water saturation in the original state, φ is the porosity, ρ is the rock density, and p L is the Langmuir pressure, V L is the Langmuir volume, z sc is the gas compressibility factor under standard conditions, p sc is the atmospheric pressure under standard conditions, T sc is the temperature under standard conditions, T is the temperature;

[0043] S20, establishing an interpolation table based on the geological parameters and fluid physical parameters of the shale gas well; wherein the elements in the interpolation table include different formation pressures p and their corresponding The value of

[0044] S30, taking the original formation pressure of the shale gas well as the initial value of the average formation pressure in the average formation pressure iteration equation, and finding the value corresponding to the initial value of the average formation pressure from the interpolation table The value of

[0045] S40, based on the initial value of the average formation pressure, calculating the value of the right-hand side term of the average formation pressure iteration equation;

[0046] S50, based on the average formation pressure initial value corresponding to The value of and the value of the right-hand side term of the average formation pressure iteration equation are used to calculate the residual of the average iteration equation using the residual calculation formula; wherein the residual calculation formula is:

[0047]

[0048] Among them, rsd(i) is the residual, is the initial value of the average formation pressure corresponding to The value of is the value of the right side term of the average formation pressure iteration equation;

[0049] S60, when the residual is greater than a preset threshold, taking the formation pressure corresponding to the value of the right-hand side term of the average formation pressure iteration equation in the interpolation table as a new average formation pressure initial value, and returning to step S30 to perform iterative calculation based on the new average formation pressure initial value;

[0050] S70, when the residual is less than or equal to the preset threshold, the initial value of the average formation pressure is used as the average formation pressure of the shale gas well, and iteration is stopped.

[0051] Optionally, determining a pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure includes:

[0052] According to the average formation pressure, a pseudo-time correction coefficient corresponding to the average formation pressure is calculated using a first preset calculation formula; wherein the first preset calculation formula is:

[0053]

[0054] Among them, f cp_c is the pseudo-time correction coefficient, c tis the comprehensive compression coefficient corresponding to the average formation pressure, μ is the gas viscosity corresponding to the average formation pressure, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c It is the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage.

[0055] Optionally, determining the interference time of the interference segment corresponding to each interference distance according to the pseudo time correction coefficient includes:

[0056] According to the pseudo-time correction coefficient, the interference time of the interference segment corresponding to each interference distance is calculated using a second preset calculation formula; wherein the second preset calculation formula is:

[0057]

[0058] Among them, T c (j) is the interference time corresponding to the jth interference segment, φ is the porosity, μ is the gas viscosity, c t is the comprehensive compression coefficient, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, k is the permeability, and f cp_c is the pseudo-time correction coefficient, and y(j) is the interference distance corresponding to the jth interference segment.

[0059] Optionally, determining, based on the interference time, a decrease rate of an interference segment corresponding to each interference time at the beginning of the late quasi-steady-state flow stage comprises:

[0060] Based on the interference time, the decrease rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage is calculated using a third preset calculation formula; wherein the third preset calculation formula is:

[0061]

[0062] Among them, D c (j) is the decreasing rate corresponding to the jth interference time, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

[0063] Optionally, determining the ratio of each of the accumulated interference segment lengths to the total length of the fractures in the shale gas well includes:

[0064] According to the accumulated interference section length, the ratio of each accumulated interference section length to the total length of the fracture of the shale gas well is calculated using a fourth preset calculation formula; wherein the fourth preset calculation formula is:

[0065]

[0066] Among them, R a (j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, L cum (j) is the length of the jth accumulated interference segment, n f is the total number of cracks, x f (i) is the crack half-length corresponding to the i-th crack.

[0067] Optionally, determining the initial production of the shale gas well corresponding to each of the accumulated interference section lengths at the beginning of the late quasi-steady-state flow stage based on the ratio includes:

[0068] Based on the ratio, the initial production of the shale gas well at the beginning of the late quasi-steady-state flow stage corresponding to each of the cumulative interference section lengths is calculated using a fifth preset calculation formula; wherein the fifth preset calculation formula is:

[0069]

[0070] Among them, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, R a (j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

[0071] Optionally, determining the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well includes:

[0072] Dividing the pressure interval formed by the average formation pressure and the bottom hole flow pressure of the shale gas well into several sections according to a preset pressure section length to obtain a plurality of pressure points;

[0073] Determine the viscosity and compressibility corresponding to each pressure point to obtain the product of the viscosity and compressibility corresponding to each pressure point;

[0074] For each pressure point, the pseudo pressure corresponding to the pressure point is obtained using the sixth preset calculation formula; wherein the sixth preset calculation formula is:

[0075]

[0076] Among them, m(p j ) is the pseudo pressure corresponding to the jth pressure point, p j is the formation pressure at the jth pressure point, p is the average formation pressure, z is the gas compression factor, μ is the gas viscosity corresponding to the average formation pressure, and p sc is the atmospheric pressure under standard conditions;

[0077] The product of the viscosity and the compressibility coefficient corresponding to each pressure point is used as the ordinate, and the pseudo-pressure corresponding to each pressure point is used as the abscissa, and a relationship curve is drawn in a double logarithmic coordinate system;

[0078] Determine the slope of any pressure point on the relationship curve using a three-point method;

[0079] Based on the pseudo-pressure corresponding to the pressure point and the pseudo-pressure corresponding to the bottom hole flow pressure of the shale gas well, the dimensionless pseudo-pressure difference of the pressure point is calculated using the seventh preset calculation formula; wherein the seventh preset calculation formula is:

[0080]

[0081] Among them, γ j is the dimensionless pseudo-pressure difference at the jth pressure point, m(p j ) is the pseudo pressure corresponding to the jth pressure point, m(p wf ) is the pseudo-pressure of the bottom hole flowing pressure;

[0082] In the pseudo pressure range The product of the slope of the pressure point and the dimensionless pseudo-pressure difference is trapezoidally integrated to obtain the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference; wherein the calculation formula of the trapezoidal integral is:

[0083]

[0084] Among them, b int is the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference, n p is the number of sections of the pressure interval formed by the average formation pressure and the bottom hole flowing pressure of the shale gas well, β j is the product of the slope corresponding to the jth pressure point and the dimensionless pseudo-pressure difference;

[0085] Based on the slope of the pressure point and the integral of the product of the dimensionless pseudo-pressure difference, the decreasing index corresponding to each interference segment is calculated using the eighth preset calculation formula; wherein the eighth preset calculation formula is:

[0086]

[0087] Among them, b psd is a decreasing index.

[0088] In a second aspect, an embodiment of the present invention provides a shale gas well production prediction system, comprising:

[0089] An interference section determination module is used to determine the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures;

[0090] An average formation pressure determination module, used to determine the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions;

[0091] An interference time calculation module is used to determine the pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure, and determine the interference time of the interference section corresponding to each interference distance according to the pseudo-time correction coefficient; a decline rate determination module is used to determine the decline rate of the interference section corresponding to each interference time at the beginning of the late pseudo-steady-state flow stage based on the interference time;

[0092] An accumulation module, used for accumulating the interference segment lengths with the same interference distance to obtain the accumulated interference segment length corresponding to each interference distance, and determining the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well, and based on the ratio, determining the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage;

[0093] A decline index determination module, used to determine the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well;

[0094] A model building module is used to build a late quasi-steady-state flow stage production decline model corresponding to each interference section based on the interference time, decline rate, initial production and decline index corresponding to each interference section using a hyperbolic decline model;

[0095] The production prediction module is used to predict the production of the late quasi-steady-state flow stage of each interference section of the shale gas well by using the late quasi-steady-state flow stage production decline model corresponding to each interference section.

[0096] In a third aspect, an embodiment of the present invention provides a storage medium having program code stored thereon, and when the program code is executed by a processor, a shale gas well production prediction method as described in any one of the above embodiments is implemented.

[0097] In a fourth aspect, an embodiment of the present invention provides an electronic device, comprising a memory and a processor, wherein the memory stores program code that can be executed on the processor, and when the program code is executed by the processor, a shale gas well production prediction method as described in any one of the above embodiments is implemented.

[0098] A shale gas well production prediction method, system, storage medium and electronic device provided in an embodiment of the present invention predicts the production of each section of the fractures by segmenting the fractures of the shale gas well and constructing a production prediction model for the early non-steady-state flow stage and a production decline model for the late quasi-steady-state flow stage for each section. This prediction method can well solve the problems that the existing shale gas well production capacity evaluation methods are difficult to apply in the early stage of gas well production, difficult to consider complex fracture morphology and lack of pertinence. Starting from the early and late production decline laws of shale gas wells, the production decline patterns of the early and late stages of gas wells are determined by combining the shale gas seepage mechanism, production data characteristic line analysis technology, and high-pressure physical property analysis technology. After that, the complex fracture morphology is considered to correct the late production decline pattern of the gas well. On this basis, the gas well production decline analysis is carried out, and the production capacity of complex fracture network gas wells can be quickly and accurately predicted. BRIEF DESCRIPTION OF THE DRAWINGS

[0099] The scope of the present disclosure may be better understood by reading the following detailed description of exemplary embodiments in conjunction with the accompanying drawings. The drawings included are:

[0100] Figure 1 A schematic diagram showing a flow chart of a shale gas well production prediction method proposed in the first embodiment of the present invention;

[0101] Figure 2 A schematic diagram showing the crack distribution pattern;

[0102] Figure 3 A schematic diagram of an interference sequence diagram is shown;

[0103] Figure 4 A schematic diagram of the relationship curve is shown;

[0104] Figure 5 A schematic diagram showing production dynamic data;

[0105] Figure 6 Shows Scatter plot of ;

[0106] Figure 7 A schematic diagram showing the value of the product of viscosity and compressibility coefficient and pseudo-pressure at each pressure point;

[0107] Figure 8 A schematic diagram showing the three-point method for obtaining the slope is shown;

[0108] Fig. 9 Schematic diagrams showing slope, dimensionless pseudo-pressure difference, and slope and dimensionless pseudo-pressure difference;

[0109] Fig.10 A schematic diagram of trapezoidal integration is shown;

[0110] Fig.11 A comparison chart of the output value predicted by the total output prediction model and the actual scatter points is shown;

[0111] Fig.12 The graph shows the change curves of daily output and cumulative output over time. DETAILED DESCRIPTION

[0112] In order to make the objectives, technical solutions and advantages of the present invention clearer, the implementation method of the present invention will be described in detail below in conjunction with the accompanying drawings and embodiments, so that the implementation process of how the present invention applies technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly.

[0113] In the following description, many specific details are set forth to facilitate a full understanding of the present invention. However, the present invention may also be implemented in other ways different from those described herein. Therefore, the protection scope of the present invention is not limited to the specific embodiments disclosed below.

[0114] Embodiment 1

[0115] According to an embodiment of the present invention, a shale gas well production prediction method is provided. Figure 1 FIG. 1 is a flow chart of a shale gas well production prediction method proposed in the first embodiment of the present invention. Figure 1 As shown, the shale gas well production prediction method may include:

[0116] In step 11, the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections are determined; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures.

[0117] Here, the fracture distribution pattern of shale gas wells, i.e., the fracture length distribution map, is drawn through the microseismic monitoring data on site. Among them, the microseismic monitoring data can be interpreted to obtain the length of each fracture; if there is no microseismic monitoring data, the length of each fracture can be interpreted based on the fracturing construction parameters; if the fracture segment length value cannot be obtained, only the ratio between the lengths of each fracture can be determined.

[0118] Figure 2 A schematic diagram of the crack distribution pattern is shown in Figure 2 As shown in the figure, the fracture distribution pattern of shale gas wells is mapped through on-site microseismic monitoring data.

[0119] After drawing the fracture length distribution map of the shale gas well, the fracture interference sequence map is drawn in combination with the graphical method. The fracture interference sequence map contains two parts of information: fracture interference distance and interference section length. The steps for drawing the fracture interference sequence map are:

[0120] S111, determine the jth (j=1:n f ) crack and the rth (r=1:n f ) length of the interference section of two cracks, where the interference section is the crack section between two cracks that is not blocked by other cracks.

[0121] S112, if the length of the interference segment is greater than 0, the distance between the two cracks is calculated, and the distance is the crack interference distance.

[0122] S113, delineate a rectangular outer boundary for the entire fractured horizontal well, wherein the center of the rectangle is located at the center of the horizontal wellbore, wherein the side length of the rectangle along the fracture direction is the maximum fracture length, and the side length of the rectangle along the horizontal wellbore direction is the horizontal well length.

[0123] S114, determine the jth (j=1:n f ) is the interference length between a crack and two rectangular outer boundaries (the outer boundaries parallel to the crack direction).

[0124] S115, calculating the interference distance between the jth (j=1:nf) crack and two rectangular outer boundaries (outer boundaries parallel to the crack direction), but the solution result of step S121 needs to be multiplied by 2.

[0125] S116, classifying the interference distances according to different values ​​to obtain a plurality of different interference distances.

[0126] S117, each interference distance corresponds to one or more interference lengths greater than 0, and a rectangular frame is drawn with the two as side lengths, and the rectangular frame represents the effective discharge area of ​​the interference length segment.

[0127] S118, the drawn rectangular frames are classified, and the rectangular frames with the same interference distance are displayed with the same background color. The rectangular frames with the same background color indicate that the corresponding crack segments have the same interference time, and finally a crack interference sequence diagram is formed.

[0128] Figure 3 A schematic diagram of the interference sequence diagram is shown, Figure 3 As shown, in Figure 3 9 interference distances and corresponding interference segments are shown in FIG.

[0129] In step 12, the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions is determined.

[0130] In an optional embodiment, in step 12, determining the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions includes:

[0131] S10, constructing an average formation pressure iteration equation based on the geological parameters and fluid physical property parameters of the shale gas well; wherein the average formation pressure iteration equation is:

[0132]

[0133] Where p is the average formation pressure, p i is the original formation pressure, z i is the gas compression factor in the original state, ct i is the comprehensive compressibility coefficient under the original formation pressure, μ i is the gas viscosity in the original state, m(p i ) is the pseudo pressure corresponding to the original formation pressure, p wf is the bottom hole flowing pressure, m(p wf ) is the pseudo pressure corresponding to the bottom hole flowing pressure, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c is the average value of the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage;

[0134]

[0135]

[0136] Among them, c f is the rock compression coefficient, c w is the compressibility coefficient of water, S gi is the gas saturation in the original state, z is the gas compression factor, S wi is the water saturation in the original state, φ is the porosity, p is the rock density, and p L is the Langmuir pressure, V L is the Langmuir volume, z sc is the gas compressibility factor under standard conditions, p sc is the atmospheric pressure under standard conditions, T sc is the temperature under standard conditions, T is the temperature;

[0137] S20, establishing an interpolation table based on the geological parameters and fluid physical parameters of the shale gas well; wherein the elements in the interpolation table include different formation pressures p and their corresponding The value of

[0138] S30, taking the original formation pressure of the shale gas well as the initial value of the average formation pressure in the average formation pressure iteration equation, and finding the value corresponding to the initial value of the average formation pressure from the interpolation table The value of

[0139] S40, based on the initial value of the average formation pressure, calculating the value of the right-hand side term of the average formation pressure iteration equation;

[0140] S50, based on the average formation pressure initial value corresponding to The value of and the value of the right-hand side term of the average formation pressure iteration equation are used to calculate the residual of the average iteration equation using the residual calculation formula; wherein the residual calculation formula is:

[0141]

[0142] Among them, rsd(i) is the residual, is the initial value of the average formation pressure corresponding to The value of is the value of the right side term of the average formation pressure iteration equation;

[0143] S60, when the residual is greater than a preset threshold, taking the formation pressure corresponding to the value of the right-hand side term of the average formation pressure iteration equation in the interpolation table as a new average formation pressure initial value, and returning to step S30 to perform iterative calculation based on the new average formation pressure initial value;

[0144] S70, when the residual is less than or equal to the preset threshold, the initial value of the average formation pressure is used as the average formation pressure of the shale gas well, and iteration is stopped.

[0145] In step 13, a pseudo-time correction coefficient corresponding to the average formation pressure is determined according to the average formation pressure, and an interference time of an interference segment corresponding to each interference distance is determined according to the pseudo-time correction coefficient.

[0146] In an optional implementation, in step 13, determining a pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure includes:

[0147] According to the average formation pressure, a pseudo-time correction coefficient corresponding to the average formation pressure is calculated using a first preset calculation formula; wherein the first preset calculation formula is:

[0148]

[0149] Among them, f cp_c is the pseudo-time correction coefficient, c t is the comprehensive compression coefficient corresponding to the average formation pressure, μ is the gas viscosity corresponding to the average formation pressure, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c It is the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage.

[0150] In an optional implementation, in step 13, determining the interference time of the interference segment corresponding to each interference distance according to the pseudo-time correction coefficient includes:

[0151] According to the pseudo-time correction coefficient, the interference time of the interference segment corresponding to each interference distance is calculated using a second preset calculation formula; wherein the second preset calculation formula is:

[0152]

[0153] Among them, T c (j) is the interference time corresponding to the jth interference segment, φ is the porosity, μ is the gas viscosity, c t is the comprehensive compression coefficient, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, k is the permeability, and f cp_ c is the pseudo-time correction coefficient, and y(j) is the interference distance corresponding to the jth interference segment.

[0154] In step 14, based on the interference time, the decrease rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage is determined.

[0155] In an optional embodiment, in step 14, based on the interference time, determining the decrease rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage includes:

[0156] Based on the interference time, the decrease rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage is calculated using a third preset calculation formula; wherein the third preset calculation formula is:

[0157]

[0158] Among them, D c (j) is the decreasing rate corresponding to the jth interference time, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

[0159] In step 15, the interference segment lengths with the same interference distance are accumulated to obtain the accumulated interference segment length corresponding to each interference distance, and the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well is determined. Based on the ratio, the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage is determined.

[0160] Here, the lengths of interference segments with the same interference distance are accumulated to obtain a plurality of interference segment lengths, and each interference segment length corresponds to an interference distance.

[0161] In an optional embodiment, in step 15, determining the ratio of each of the accumulated interference segment lengths to the total length of the fractures of the shale gas well includes:

[0162] According to the accumulated interference section length, the ratio of each accumulated interference section length to the total length of the fracture of the shale gas well is calculated using a fourth preset calculation formula; wherein the fourth preset calculation formula is:

[0163]

[0164] Among them, R a (j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, L cum (j) is the length of the jth accumulated interference segment, n f is the total number of cracks, x f (i) is the crack half-length corresponding to the i-th crack.

[0165] In an optional embodiment, in step 19, based on the ratio, determining the initial production of the shale gas well corresponding to each of the accumulated interference section lengths at the beginning of the late quasi-steady-state flow stage comprises:

[0166] Based on the ratio, the initial production of the shale gas well at the beginning of the late quasi-steady-state flow stage corresponding to each of the cumulative interference section lengths is calculated using a fifth preset calculation formula; wherein the fifth preset calculation formula is:

[0167]

[0168] Among them, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, R a(j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

[0169] In step 16, the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage is determined according to the average formation pressure and the bottom hole flowing pressure set for the shale gas well.

[0170] In an optional embodiment, in step 16, determining the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flowing pressure set for the shale gas well includes:

[0171] Dividing the pressure interval formed by the average formation pressure and the bottom hole flow pressure of the shale gas well into several sections according to a preset pressure section length to obtain a plurality of pressure points;

[0172] Determine the viscosity and compressibility corresponding to each pressure point to obtain the product of the viscosity and compressibility corresponding to each pressure point;

[0173] For each pressure point, the pseudo pressure corresponding to the pressure point is obtained using the sixth preset calculation formula; wherein the sixth preset calculation formula is:

[0174]

[0175] Among them, m(p j ) is the pseudo pressure corresponding to the jth pressure point, p j is the formation pressure at the jth pressure point, p is the average formation pressure, z is the gas compression factor, μ is the gas viscosity corresponding to the average formation pressure, and p sc is the atmospheric pressure under standard conditions; where p sc The value of is 0.1.

[0176] The product of the viscosity and the compressibility coefficient corresponding to each pressure point is used as the ordinate, and the pseudo-pressure corresponding to each pressure point is used as the abscissa, and a relationship curve is drawn in a double logarithmic coordinate system;

[0177] Determine the slope of any pressure point on the relationship curve using a three-point method;

[0178] Based on the pseudo-pressure corresponding to the pressure point and the pseudo-pressure corresponding to the bottom hole flow pressure of the shale gas well, the dimensionless pseudo-pressure difference of the pressure point is calculated using the seventh preset calculation formula; wherein the seventh preset calculation formula is:

[0179]

[0180] Among them, γj is the dimensionless pseudo-pressure difference at the jth pressure point, m(p j ) is the pseudo pressure corresponding to the jth pressure point, m(p wf ) is the pseudo-pressure of the bottom hole flowing pressure;

[0181] In the pseudo pressure range The product of the slope of the pressure point and the dimensionless pseudo-pressure difference is trapezoidally integrated to obtain the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference; wherein the calculation formula of the trapezoidal integral is:

[0182]

[0183] Among them, b int is the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference, n p is the number of sections of the pressure interval formed by the average formation pressure and the bottom hole flowing pressure of the shale gas well, β j is the product of the slope corresponding to the jth pressure point and the dimensionless pseudo-pressure difference;

[0184] Based on the slope of the pressure point and the integral of the product of the dimensionless pseudo-pressure difference, the decreasing index corresponding to each interference segment is calculated using the eighth preset calculation formula; wherein the eighth preset calculation formula is:

[0185]

[0186] Among them, b psd is a decreasing index.

[0187] Here, the specific process of obtaining the decreasing index is as follows:

[0188] S161, based on the collected shale gas well working system, determine the bottom hole flow pressure p set for the gas well wf ,;

[0189] S162, based on the average formation pressure p c , clearly define the pressure range.

[0190] Among them, the pressure range is: (p c , p wf ).

[0191] S163, dividing the pressure interval formed by the average formation pressure and the bottom hole flow pressure of the shale gas well into several sections according to a preset pressure section length, so as to obtain a plurality of pressure points.

[0192] For example, the pressure interval is divided into n parts with a pressure section length of Δp = 0.1 MPa. p segment, we get n p Pressure points, n p =(pc -p wf ) / Δp+1, where the jth pressure point is: p j =P wf +(j-1)×Δp j=1,2,3…n p

[0193] S164, for each pressure point, calculate the corresponding viscosity and compressibility coefficient to obtain the viscosity u corresponding to each pressure point j and compression coefficient c tj The product of (uc t ) j .

[0194] S165, for each pressure point, using a sixth preset calculation formula to obtain a pseudo pressure corresponding to the pressure point; wherein the sixth preset calculation formula is:

[0195]

[0196] S166, plotting a relationship curve with the product of the viscosity and the compressibility coefficient corresponding to each pressure point as the abscissa and the pseudo-pressure corresponding to each pressure point as the ordinate.

[0197] Among them, if a relationship curve is drawn in a double logarithmic coordinate, the ordinate is the pseudo-pressure corresponding to each pressure point, and the abscissa is the product of the viscosity and the compressibility coefficient corresponding to each pressure point. Figure 4 A schematic diagram of a relationship curve is shown. Figure 4 shown.

[0198] S167, using a three-point method to determine the slope of any pressure point on the relationship curve.

[0199] Here, m(p j ), (uc t ) j Take the logarithm respectively and get log[m(p j )]、log[(uc t ) j ], to simplify the calculation, define two variables:

[0200] x j =log[m(p j )]

[0201] f(x j )=log[(uc t ) j ]

[0202] If j = 1, the derivative formula is:

[0203]

[0204] If j = n p , the derivative formula is:

[0205]

[0206] For other pressure points, the derivative formula is:

[0207]

[0208] Get the slope at any pressure point and take the absolute value. Then the slope α j =|f′(x j )|.

[0209] S168, based on the pseudo-pressure corresponding to the pressure point and the pseudo-pressure corresponding to the bottom hole flowing pressure of the shale gas well, calculate the dimensionless pseudo-pressure difference of the pressure point using a seventh preset calculation formula; wherein the seventh preset calculation formula is:

[0210]

[0211] Among them, γ j is the dimensionless pseudo-pressure difference at the jth pressure point, m(p j ) is the pseudo pressure corresponding to the jth pressure point, m(p wf ) is the pseudo-pressure of the bottom hole flowing pressure;

[0212] S169, in the pseudo-pressure range The product of the slope of the pressure point and the dimensionless pseudo-pressure difference is trapezoidally integrated to obtain the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference; wherein the calculation formula of the trapezoidal integral is:

[0213]

[0214] Among them, b int is the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference, n p is the number of sections of the pressure interval formed by the average formation pressure and the bottom hole flowing pressure of the shale gas well, β j is the product of the slope corresponding to the jth pressure point and the dimensionless pseudo-pressure difference;

[0215] S1691, based on the slope of the pressure point and the integral of the product of the dimensionless pseudo-pressure difference, the decreasing index is calculated using an eighth preset calculation formula; wherein the eighth preset calculation formula is:

[0216]

[0217] Among them, b psdis a decreasing index.

[0218] Here, the decline index is the decline index in the hyperbolic decline model, which is a commonly used decline model in the late quasi-steady-state flow stage of shale gas wells.

[0219] In step 17, based on the interference time, the decline rate, the initial production and the decline index, in combination with a hyperbolic decline model, a production decline model of the late quasi-steady-state flow stage corresponding to each interference section is constructed.

[0220] Among them, the production decline model in the late quasi-steady-state flow stage is:

[0221]

[0222] Among them, q late (j) is the production of the jth interference section in the late quasi-steady-state flow stage, b psd is a decreasing exponential, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, D c (j) is the decreasing rate of the jth interference segment, T c (j) is the interference time corresponding to the jth interference segment, and t is time.

[0223] Here, time t is the cumulative gas production time of the shale gas well, in days, T c (j) refers to the time when the disturbance segment evolves to the late quasi-steady-state flow stage, such as T c (j) = 7, then on the 7th day, the interference section enters the late quasi-steady-state flow stage.

[0224] In step 18, the production decline model for the late quasi-steady-state flow stage is used to predict the production of the shale gas well in the late quasi-steady-state flow stage.

[0225] Here, each fracture section of the shale gas well includes one or more interference sections. By determining the production decline model of the late quasi-steady-state flow stage of each interference section, the production of the late quasi-steady-state flow stage of the shale gas well can be predicted.

[0226] In an optional embodiment, the method further comprises:

[0227] determining a production decline model for an early non-steady-state flow phase of the shale gas well;

[0228] Based on the ratio of each accumulated interference section length to the total length of the fractures of the shale gas well, combined with the production decline model of the early non-steady-state flow stage, an early non-steady-state flow stage production prediction model corresponding to each interference section is constructed; wherein the early non-steady-state flow stage production prediction model corresponding to each interference section is used to predict the production of each interference section of the shale gas well when it is in the early non-steady-state flow stage.

[0229] Here, the late quasi-steady-state flow stage production decline model predicts the production of the late quasi-steady-state flow stage of the shale gas well, while the production prediction of the early non-steady-state flow stage of the shale gas well can be carried out by constructing an early non-steady-state flow stage production prediction model corresponding to each interference section.

[0230] The production decline model in the early non-steady-state flow stage is:

[0231]

[0232] Among them, q ear is the production of the shale gas well in the early non-steady flow stage, t is time, a and b are constants; a and b are the 1 / q and 1 / q plotted according to the production dynamic data of the shale gas well. The slope and intercept are obtained by scatter fitting the relationship curve; where q is the daily output.

[0233] Here, in the early production of horizontal wells with multiple fractures, there is no interference between the fractures. At this time, the production capacity change law of the entire gas well is consistent with the production change law of the gas well under the condition of a single fracture. When the early prediction model is established, the desorption of adsorbed gas in the formation during the production of shale gas wells is considered. Combined with the Langmuir isothermal adsorption model, the effect of adsorbed gas desorption on gas well production is characterized by correcting the gas compression coefficient. The production decline model in the early non-steady-state flow stage is:

[0234]

[0235] in, q is the gas well production, 10 4 m 3 / d, t: time, d; T: temperature, K; h: gas reservoir thickness, m; μ: gas viscosity, cp; m(p): pseudo pressure corresponding to pressure p, MPa 2 / cp;x f : fracture half-length, m; k: permeability, mD; z: gas compressibility factor, dimensionless.

[0236] Corrected compression coefficient: c t =c g +c ads;in: c t : Corrected gas compressibility coefficient, MPa -1 ;c g : Gas compressibility coefficient, MPa -1 ;c ads : Additional gas compressibility factor generated by desorption of adsorbed gas, MPa -1 ; ρ: rock density, g / cm 3 ; φ: porosity, decimal; p L : Rankine pressure, MPa; V L Langmuir volume, m 3 / m 3 ; p: pressure, MPa.

[0237] According to this model, The relationship curve is a straight line segment passing through the origin in the rectangular coordinate system. For multi-fracture horizontal wells, this linear relationship still holds before the occurrence of interfracture interference. Considering the wellbore and fracture contamination, The straight line segment may deviate from the origin, and based on this, the production decline pattern of the entire fractured horizontal well in the early non-steady linear flow stage is defined as:

[0238]

[0239] Then, calculate the inverse of the collected yield 1 / q and plot it in a rectangular coordinate system Scatter plot, find the early straight line segment, and obtain the slope a and intercept b of the straight line segment by scatter point fitting, and obtain the production decline model in the early non-steady-state flow stage:

[0240]

[0241] Among them, the early non-steady-state flow stage production prediction model corresponding to each interference section is:

[0242]

[0243] Among them, q ear (j) is the production of the jth interference section in the early non-steady flow stage, R a (j) is the ratio of the cumulative interference section length to the total length of the fracture of the shale gas well.

[0244] In an optional embodiment, the method further comprises:

[0245] Based on the late quasi-steady-state flow stage production decline model corresponding to each interference section and the early non-steady-state flow stage production prediction model, combined with the interference time of the interference section, a full-stage production decline model for each interference section is constructed;

[0246] The full-stage production decline models of each interference section are superimposed to obtain the total production prediction model of the shale gas well.

[0247] Among them, the full-stage production decline model is:

[0248]

[0249] Among them, q(j) is the full-stage output of the jth interference stage;

[0250] The total output prediction model is:

[0251]

[0252] Among them, q a is the daily production of the shale gas well, and n is the number of interference sections.

[0253] In this embodiment, the prediction method can well solve the problems that the existing shale gas well production capacity evaluation methods are difficult to apply in the early stage of gas well production, difficult to consider complex fracture morphology, and not targeted. Starting from the early and late production decline rules of shale gas wells, the production decline mode of the early and late stages of the gas well is determined by combining the shale gas seepage mechanism, production data characteristic line analysis technology, and high-pressure physical property analysis technology. After that, the complex fracture morphology is considered to correct the late production decline mode of the gas well. On this basis, the gas well production decline analysis is carried out, and the production capacity of complex fracture network gas wells can be quickly and accurately predicted.

[0254] Embodiment 2

[0255] In this embodiment, an actual shale gas production well is taken as an example to illustrate in detail the shale gas well production prediction method proposed in the present invention.

[0256] S210, establish a production decline model for the early non-steady-state flow stage of a shale gas well.

[0257] Here, the production decline pattern of the entire fractured horizontal well in the early unsteady flow stage is established as:

[0258]

[0259] Then, the production dynamic data of the gas well is obtained, which includes the daily production of the gas well. Figure 5 A schematic diagram showing production dynamic data is shown, such as Figure 5 As shown in Figure 1, the production dynamic data includes daily gas production and bottom hole pressure data. Scatter plot, Figure 6 Shows A scatter plot of Figure 6As shown, the early straight line segment is found, and the slope of the straight line segment is 0.0115 using the scatter point fitting method. The straight line approximately passes through the far point of the coordinate axis, and the intercept is approximately 0. Based on this, the production prediction model for the early non-steady-state flow stage is obtained as follows:

[0260]

[0261] S220, determining the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions.

[0262] Here, the solution process of the average formation pressure is as follows:

[0263] Based on the geological parameters and fluid physical parameters of the shale gas well, an average formation pressure iteration equation is constructed; wherein the average formation pressure iteration equation is:

[0264]

[0265] The average formation pressure is obtained by iteratively calculating the average formation pressure iterative equation using an iterative algorithm.

[0266] The geological parameters and fluid physical property parameters of the shale gas well are shown in Table 1, and the bottom hole pressure is set to 7.5 MPa.

[0267] Table 1

[0268]

[0269] Based on the geological parameters and fluid physical parameters of the shale gas well, the relationship between p and Interpolation table of .

[0270] The interpolation table is shown in Table 2:

[0271] Table 2

[0272]

[0273]

[0274]

[0275] The residual of the average formation pressure iteration equation is set to 0.1 MPa and the next iteration is performed.

[0276] First iteration: Take the original formation pressure of 66 MPa as the initial value of the average formation pressure; based on the given basic parameters and z ** The calculation formula is used to calculate the initial value of the average formation pressure corresponding to is 48.959MPa; based on the current average formation pressure, original formation pressure, and bottom hole flow pressure, the right side of the average formation pressure iteration equation is calculated It is 43.449MPa; the residual of the iterative equation for calculating the average formation pressure is 5.510MPa, which is much larger than the given error limit and therefore does not meet the conditions.

[0277] Second iteration: Look up in the table of differences between p and p / z** When the value is 43.449MPa, the corresponding pressure p is 51.25MPa, which is used as the new initial value of the average formation pressure. Similarly, the corresponding z** is calculated to obtain the corresponding initial value of the average formation pressure. is 43.453MPa; based on the current average formation pressure, original formation pressure, and bottom hole flow pressure, the right side of the average formation pressure iteration equation is calculated is 42.735MPa; the residual of the iterative equation for calculating the average formation pressure is 0.718MPa, which is still greater than the given error limit and therefore does not meet the conditions.

[0278] Third iteration: Look up in the table of differences between p and p / z** When the value is 42.735MPa, the corresponding pressure p is 49.550MPa. Taking this value as the new initial value of the average formation pressure, the value of z** is calculated, and the corresponding initial value of the average formation pressure is calculated. is 42.737MPa; based on the current average formation pressure, original formation pressure, and bottom hole flow pressure, the right side of the average formation pressure iteration equation is calculated is 42.625MPa; the residual of the iterative equation for calculating the average formation pressure is 0.112MPa, which is still slightly larger than the given error limit and therefore does not meet the conditions.

[0279] Fourth iteration: Look up in the table of differences between p and p / z** When the value is 42.625MPa, the corresponding pressure p is 49.250MPa, which is used as the new initial value of the average formation pressure. Similarly, the corresponding z** is calculated to obtain the corresponding initial value of the average formation pressure. is 42.609MPa; based on the current average formation pressure, original formation pressure, and bottom hole flow pressure, the right side of the average formation pressure iteration equation is calculated It is 42.605MPa; the residual of the iterative equation for calculating the average formation pressure is 0.004MPa, which is less than the given error limit. Therefore, the conditions are met and the iteration ends.

[0280] The average formation pressure is: 49.250MPa, and the pseudo-time correction coefficient is: 0.8743.

[0281] S230, determining a production decline model for a shale gas well in a late quasi-steady-state flow stage under uniform fracturing conditions.

[0282] Here, the bottom hole pressure of the shale gas well during production is set to 7.5 MPa, and the specific steps of S230 are as follows:

[0283] According to the obtained average formation pressure, the pressure range is determined to be (7.5, 49.3);

[0284] Set the pressure section length Δp = 0.1 MPa, divide the pressure range into 419 sections, and the jth pressure point is: p j =7.5+(j-1)×0.1

[0285] For each pressure point p(j), calculate the corresponding viscosity u j and the compression coefficient c tj , and we get the product of the two (uc t ) j , calculate p for each pressure point j The corresponding pseudo pressure m(p j ). Figure 7 A schematic diagram showing the value of the product of viscosity and compressibility coefficient and pseudo-pressure at each pressure point is shown, as Figure 7 As shown, Figure 7 The middle dotted line indicates the value of the product of viscosity and compressibility at each pressure point. Figure 7 The solid line in the middle represents the corresponding relationship between pressure and pseudo-pressure.

[0286] The calculation results show that there are 419 one-to-one corresponding data pairs, namely [m(p j ), (uc t ) j ].

[0287] Then plot m(p) in logarithmic coordinates based on the data pairs. j )~(uc t ) j Relationship curve to obtain the slope corresponding to each pressure point.

[0288] Figure 8 The schematic diagram of the three-point method for obtaining the slope is shown in FIG. Figure 8 Shown by the solid line.

[0289] In m(p j )~(uc t ) j On the relationship curve, select Figure 8 The three typical points shown in the figure illustrate the process of solving the slope:

[0290] For the first point, three data pairs are needed to solve the slope: [x1, f(x1)], [x2, f(x2)], [x3, f(x3)]. The three data pairs obtained are: (3.569, -2.658), (3.624, -2.684), (3.676, -2.709), and the slope of the first point is -0.468.

[0291] For the 210th point, when solving the slope at this point, the data pairs needed are (4.644, -3.212), (4.657, -3.220) and (4.670, -3.229), and the slope of the 210th point is -0.646.

[0292] For the 419th point, when solving the slope, the data pairs needed are (5.013, -3.477), (5.019, -3.483) and (5.026, -3.488). The slope of the 419th point is -0.807. The slopes of the remaining points can be solved in a similar way.

[0293] Based on the pseudo-pressure corresponding to the pressure point and the pseudo-pressure corresponding to the bottom hole flow pressure of the shale gas well, the dimensionless pseudo-pressure difference of the pressure point is calculated using the seventh preset calculation formula; wherein the seventh preset calculation formula is:

[0294]

[0295] Among them, γ j is the dimensionless pseudo-pressure difference at the jth pressure point, m(p j ) is the pseudo pressure corresponding to the jth pressure point, m(p wf ) is the pseudo-pressure of the bottom hole flowing pressure;

[0296] Fig. 9 Schematic diagrams of slope, dimensionless pseudo-pressure difference, and slope and dimensionless pseudo-pressure difference are shown, as shown in Fig. 9 As shown, α is the slope, γ is, β is the dimensionless pseudo-pressure difference, and the product of the slope and the dimensionless pseudo-pressure difference.

[0297] Then, in the pseudo-pressure interval The product of the slope of the pressure point and the dimensionless pseudo-pressure difference is trapezoidally integrated to obtain the area of ​​the polygon, Fig.10 A schematic diagram of trapezoidal integration is shown, such as Fig.10 As shown, the area enclosed by the curve is b int The final result is b int =60702.18.

[0298] Finally, the decline index b of the production decline model in the late quasi-steady-state flow stage is solved based on the eighth preset calculation formula psd The other parameters in the model have been described in detail in the above embodiments and will not be described again here.

[0299] S240, the production decline model in the late quasi-steady-state flow stage is modified.

[0300] Here, since the production capacity is a non-uniform fracture system during the fracturing process, it is necessary to consider its impact on the gas well production decline law and modify the production decline model in the late quasi-steady-state flow stage. The amount of sand added in the fracturing construction parameters determines the length ratio of each fracture, and draws the fracture morphology distribution diagram according to the ratio, such as Figure 2 Among them, the length ratio of each crack is shown in Table 3.

[0301] Table 3

[0302] Crack number 1 2 3 4 5 6 Length ratio 57 43 51 58 58 58 Crack number 7 8 9 10 11 12 Length ratio 58 53 44 35 16 16 Crack number 13 14 15 16 17 18 Length ratio 40 40 40 40 40 25 Crack number 19 20 21 22 23 Length ratio 40 48 39 44 32

[0303] The purpose of drawing the interference sequence diagram is to determine the interference distance and interference section of the fractures. There are 23 fractures in the shale gas well. Taking the 8th fracture as an example, the method of obtaining the interference distance and interference section length in the process of drawing the interference sequence diagram is explained.

[0304] 1) It is determined that the interference length of the 8th crack with the 1st to 6th, 10th to 19th, and 21st to 23rd cracks is 0; the interference length with the 7th crack is 53m, and the corresponding interference distance is 66.1m; the interference length with the 9th crack is 44m, and the interference distance is 66.1m; the interference length with the 20th crack is 4m, and the interference distance is 793.2m.

[0305] 2) Define a rectangular outer boundary for the entire horizontal well. The center of the rectangle is located at the center of the horizontal well. The rectangle is 1520m long and 58m wide. Figure 3 The dashed line in the middle gives the outer boundary of the enclosed rectangle.

[0306] 3) Use the method in step 1) to determine the interference distance between the 8th crack and the two rectangular outer boundaries (parallel to the crack direction). The interference length between the 8th crack and the left rectangular outer boundary is 0, and the interference length between the 8th crack and the right rectangular outer boundary is 5m. When solving the interference distance, it is necessary to multiply the result of step 1) by 2, which is 2049.1m.

[0307] 4) Similar to step 3), the interference length and interference distance of the remaining cracks can be determined.

[0308] 5) Classify the interference distances according to different values, and obtain num=9 different interference distances, which are numbered in ascending order, as shown in Table 4:

[0309] Table 4

[0310]

[0311] 6) Draw a rectangular box with the interference distance and interference length as the side length, and the rectangular box represents the effective discharge area of ​​the interference length segment.

[0312] 7) Classify the drawn rectangular boxes, and display the rectangular boxes with the same interference distance with the same background color to finally form an interference order diagram, such as Figure 3 As shown, there are 9 kinds of interference distances, so the rectangular frame has 9 different background colors.

[0313] 8) Based on the interference sequence diagram, the cumulative interference section length, the ratio of the cumulative interference section length to the total length of the fractures of the shale gas well, and the interference time, decline rate, and initial production of the interference section corresponding to each interference distance are calculated.

[0314] The interference time and decreasing rate of the interference segment corresponding to each interference distance are shown in Table 5.

[0315] Table 5

[0316]

[0317] The interference lengths corresponding to the same interference distance are accumulated to obtain 9 accumulated interference lengths Lcum, and the ratio of each accumulated interference length to the total length of the crack is calculated. The calculation results are shown in Table 6.

[0318] Table 6

[0319]

[0320] The production at the beginning of the late quasi-steady-state flow stage corresponding to each cumulative interference length is calculated, as shown in Table 7.

[0321] Table 7

[0322]

[0323] Taking the first cumulative interference length as an example, the production decline model of the late quasi-steady-state flow stage is established as follows:

[0324]

[0325] Taking the first cumulative interference length as an example, the full-stage production decline model is constructed as follows:

[0326]

[0327] The production decline models corresponding to the remaining cumulative interference length segments can be established with reference to the first cumulative interference length.

[0328] 9) The production of each fracture section is superimposed to obtain the production of the entire horizontal well:

[0329]

[0330] Fig.11 The comparison chart of the output value predicted by the total output prediction model and the actual scatter points is shown as follows: Fig.11 As shown, the output predicted by the total output forecasting model meets the actual demand.

[0331] Fig.12 The curves showing the daily output and cumulative output changing with time are shown in Figure 2. Fig.12 As shown, the predicted results show that the cumulative gas production of this shale gas well is 118 million cubic meters.

[0332] Embodiment 3

[0333] According to an embodiment of the present invention, a shale gas well production prediction system is also provided, comprising:

[0334] An interference section determination module is used to determine the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures;

[0335] An average formation pressure determination module, used to determine the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions;

[0336] An interference time calculation module is used to determine the pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure, and determine the interference time of the interference section corresponding to each interference distance according to the pseudo-time correction coefficient; a decline rate determination module is used to determine the decline rate of the interference section corresponding to each interference time at the beginning of the late pseudo-steady-state flow stage based on the interference time;

[0337] An accumulation module, used for accumulating the interference segment lengths with the same interference distance to obtain the accumulated interference segment length corresponding to each interference distance, and determining the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well, and based on the ratio, determining the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage;

[0338] A decline index determination module, used to determine the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well;

[0339] A model building module is used to build a late quasi-steady-state flow stage production decline model corresponding to each interference section based on the interference time, decline rate, initial production and decline index corresponding to each interference section using a hyperbolic decline model;

[0340] The production prediction module is used to predict the production of the late quasi-steady-state flow stage of each interference section of the shale gas well by using the late quasi-steady-state flow stage production decline model corresponding to each interference section.

[0341] Embodiment 4

[0342] According to an embodiment of the present invention, a storage medium is further provided, on which a program code is stored. When the program code is executed by a processor, the shale gas well production prediction method as described in any one of the above embodiments is implemented.

[0343] Embodiment 5

[0344] According to an embodiment of the present invention, there is also provided an electronic device, which includes a memory and a processor, wherein the memory stores a program code that can be run on the processor, and when the program code is executed by the processor, the shale gas well production prediction method as described in any one of the above embodiments is implemented.

[0345] The technical scheme of the present invention is described in detail above in combination with the accompanying drawings. Considering the problems in the related art that the production decline prediction method of shale gas fracturing horizontal wells is difficult to apply in the early stage of gas well production, difficult to consider complex fracture morphology, and lack of pertinence. The present invention provides a shale gas well production prediction method, system, storage medium, and electronic device. In order to solve the problems that the production decline prediction method of shale gas fracturing horizontal wells is difficult to apply in the early stage of gas well production, difficult to consider complex fracture morphology, and lack of pertinence, the present invention establishes a set of shale gas non-uniform fracturing horizontal well production capacity prediction process. When predicting the production capacity of a non-uniformly fractured horizontal well, the present invention first determines the production decline pattern of the gas well in the early flow stage, and uses the production data characteristic line analysis technology under the guidance of the pattern to determine the production prediction model of the early non-steady-state flow stage; then, by introducing high-pressure physical property analysis technology, the production decline pattern of the gas well in the late quasi-steady-state stage under uniform fracturing conditions is determined; then, a graphical method is introduced to characterize the influence of non-uniform fracturing on the production change law of the gas well in the late stage, and the complex fractures are segmented by drawing an interference sequence diagram, and the production decline model of each fracture segment is established and then superimposed to obtain the production capacity prediction model of the entire fractured horizontal well, which solves the problem that the conventional decline analysis method is difficult to consider the complex fracture morphology. Finally, a set of practical and feasible shale gas non-uniformly fractured horizontal well production capacity prediction methods are formed.

[0346] In the several embodiments provided in this application, it should be understood that the disclosed devices and methods can be implemented in other ways. For example, the device embodiments described above are only schematic, for example, the division of units is only a logical function division, and there may be other division methods in actual implementation, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed.

[0347] The units described as separate components may or may not be physically separated, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed on multiple network units. Some or all of the units may be selected according to actual needs to achieve the purpose of the embodiments of the present invention.

[0348] In addition, each functional unit in each embodiment of the present invention may be integrated into one processing unit, or each unit may exist physically separately, or two or more units may be integrated into one unit. The above-mentioned integrated unit may be implemented in the form of hardware or in the form of software functional units.

[0349] If the integrated unit is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the present invention is essentially or the part that contributes to the prior art, or all or part of the technical solution can be embodied in the form of a software product. The computer software product is stored in a storage medium, including several instructions for enabling an electronic device (which can be a personal computer, server, or network device, etc.) to perform all or part of the steps of the methods of each embodiment of the present invention. The aforementioned storage medium includes: U disk, mobile hard disk, read-only memory (ROM, Read-Only Memory), random access memory (RAM, Random Access Memory), disk or optical disk and other media that can store program codes.

[0350] Although the embodiments disclosed in the present invention are as above, the contents described are only embodiments adopted for facilitating the understanding of the present invention and are not intended to limit the present invention. Any technician in the technical field to which the present invention belongs can make any modifications and changes in the form and details of the implementation without departing from the spirit and scope disclosed in the present invention, but the protection scope of the present invention shall still be subject to the scope defined in the attached claims.

Claims

1. A shale gas well production prediction method, characterized in that: include: Determine the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures; Determine the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions; Determine a pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure, and determine an interference time of an interference section corresponding to each interference distance according to the pseudo-time correction coefficient; Based on the interference time, determining a decrease rate of the interference segment corresponding to each interference time at the beginning of the late quasi-steady-state flow stage; Accumulating the interference segment lengths with the same interference distance to obtain the accumulated interference segment length corresponding to each interference distance, and determining the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well, and based on the ratio, determining the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage; Determining a decline index of each interference section when the shale gas well is in a late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well; Based on the disturbance time, decline rate, initial production and decline index of each disturbance section, a production decline model of the late quasi-steady-state flow stage corresponding to each disturbance section was constructed using a hyperbolic decline model. The production of the late quasi-steady-state flow stage of each interference section of the shale gas well is predicted respectively by using the late quasi-steady-state flow stage production decline model corresponding to each interference section; The production decline model in the late quasi-steady-state flow stage is: Among them, q late (j) is the production of the jth interference section in the late quasi-steady-state flow stage, b psd is a decreasing exponential, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, D c (j) is the decreasing rate of the jth interference segment, T c (j) is the interference time corresponding to the jth interference segment, and t is time; The method further comprises: determining a production decline model for an early non-steady-state flow phase of the shale gas well; Based on the ratio of each of the accumulated interference section lengths to the total length of the fractures of the shale gas well, the production decline model of the early non-steady-state flow stage is used to construct a production prediction model of the early non-steady-state flow stage corresponding to each interference section; wherein the production prediction model of the early non-steady-state flow stage corresponding to each interference section is used to predict the production of each interference section of the shale gas well when it is in the early non-steady-state flow stage; The production decline model in the early non-steady-state flow stage is: Among them, q ear is the production of the shale gas well in the early non-steady flow stage, t is time, a and b are constants; a and b are the 1 / q and 1 / q plotted according to the production dynamic data of the shale gas well. The slope and intercept are obtained by scatter fitting the relationship curve; where q is the daily output; When a horizontal well with multiple fractures is producing in the early stage and no interference occurs between the fractures, the production decline model in the early non-steady flow stage is: in, q sc is the gas well production, t is time; T is temperature; h is the gas reservoir thickness; μ is the gas viscosity, m(p) is the pseudo-pressure corresponding to pressure p, x f : Fracture half-length, k is permeability, z is gas compression factor, dimensionless, and the modified compression factor is c t =c g +c ads ;in: ct is the corrected gas compressibility coefficient, cg is the gas compressibility coefficient, cads is the additional gas compressibility coefficient generated by the desorption of adsorbed gas, ρ is the rock density, φ is the porosity; pL is the Langmuir pressure, VL is the Langmuir volume, and p is the pressure.

2. The shale gas well production prediction method according to claim 1, characterized in that: The production prediction model for the early non-steady-state flow stage corresponding to each interference section is: Among them, q ear (j) is the production of the jth interference section in the early non-steady flow stage, R a (j) is the ratio of the jth cumulative interference section length to the total length of the fracture of the shale gas well.

3. The shale gas well production prediction method according to claim 2, characterized in that: The method further comprises: Based on the late quasi-steady-state flow stage production decline model corresponding to each disturbance section and the early non-steady-state flow stage production prediction model, combined with the disturbance time corresponding to each disturbance section, the full-stage production decline model corresponding to each disturbance section is constructed; The full-stage production decline models of each interference section are superimposed to obtain the total production prediction model of the shale gas well.

4. The shale gas well production prediction method according to claim 3, characterized in that: The full-stage production decline model is: Among them, q(j) is the full-stage output of the jth interference stage; The total output prediction model is: Among them, q a is the daily production of the shale gas well, and n is the number of interference sections.

5. The shale gas well production prediction method according to claim 1, characterized in that: The determination of the average formation pressure when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage under uniform fracturing conditions includes: S10, constructing an average formation pressure iteration equation based on the geological parameters and fluid physical property parameters of the shale gas well; wherein the average formation pressure iteration equation is: Where p is the average formation pressure, p i is the original formation pressure, z i is the gas compression factor in the original state, c ti is the comprehensive compressibility coefficient under the original formation pressure, μ i is the gas viscosity in the original state, m(p i ) is the pseudo pressure corresponding to the original formation pressure, p wf is the bottom hole flowing pressure, m(p wf ) is the pseudo pressure corresponding to the bottom hole flowing pressure, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c is the average value of the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage; Among them, c f is the rock compression coefficient, c w is the compressibility coefficient of water, S gi is the gas saturation in the original state, z is the gas compression factor, S wi is the water saturation in the original state, φ is the porosity, ρ is the rock density, and p L is the Langmuir pressure, V L is the Langmuir volume, z sc is the gas compressibility factor under standard conditions, p sc is the atmospheric pressure under standard conditions, T sc is the temperature under standard conditions, T is the temperature; S20, establishing an interpolation table based on the geological parameters and fluid physical parameters of the shale gas well; wherein the elements in the interpolation table include different formation pressures p and their corresponding The value of S30, taking the original formation pressure of the shale gas well as the initial value of the average formation pressure in the average formation pressure iteration equation, and finding the value corresponding to the initial value of the average formation pressure from the interpolation table The value of S40, based on the initial value of the average formation pressure, calculating the value of the right-hand side term of the average formation pressure iteration equation; S50, based on the initial value of the average formation pressure corresponding to The value of and the value of the right-hand side term of the average formation pressure iteration equation are used to calculate the residual of the average iteration equation using the residual calculation formula; wherein the residual calculation formula is: Among them, rsd(i) is the residual, is the initial value of the average formation pressure corresponding to The value of is the value of the right side term of the average formation pressure iteration equation; S60, when the residual is greater than a preset threshold, taking the formation pressure corresponding to the value of the right-hand side term of the average formation pressure iteration equation in the interpolation table as a new average formation pressure initial value, and returning to step S30 to perform iterative calculation based on the new average formation pressure initial value; S70, when the residual is less than or equal to the preset threshold, the initial value of the average formation pressure is used as the average formation pressure of the shale gas well, and iteration is stopped.

6. The shale gas well production prediction method according to claim 1, characterized in that: Determining the pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure includes: According to the average formation pressure, a pseudo-time correction coefficient corresponding to the average formation pressure is calculated using a first preset calculation formula; wherein the first preset calculation formula is: Among them, f cp-c is the pseudo-time correction coefficient, c t is the comprehensive compression coefficient corresponding to the average formation pressure, μ is the gas viscosity corresponding to the average formation pressure, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, (c t μ) c It is the product of the comprehensive compressibility coefficient and the gas viscosity when the shale gas well evolves from the early non-steady-state flow stage to the late quasi-steady-state flow stage.

7. The shale gas well production prediction method according to claim 1, characterized in that: Determining the interference time of the interference segment corresponding to each interference distance according to the pseudo-time correction coefficient includes: According to the pseudo-time correction coefficient, the interference time of the interference segment corresponding to each interference distance is calculated using a second preset calculation formula; wherein the second preset calculation formula is: Among them, T c (j) is the interference time corresponding to the jth interference segment, φ is the porosity, μ is the gas viscosity, c t is the comprehensive compression coefficient, (c t μ) i is the product of the comprehensive compressibility coefficient of the shale gas well in its original state and the gas viscosity, k is the permeability, and f cp-c is the pseudo-time correction coefficient, and y(j) is the interference distance corresponding to the jth interference segment.

8. The shale gas well production prediction method according to claim 1, characterized in that: The determining, based on the interference time, a decreasing rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage comprises: Based on the interference time, the decrease rate of the interference section corresponding to each interference time at the beginning of the late quasi-steady-state flow stage is calculated using a third preset calculation formula; wherein the third preset calculation formula is: Among them, D c (j) is the decreasing rate corresponding to the jth interference time, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

9. The shale gas well production prediction method according to claim 1, characterized in that: Determining the ratio of each of the accumulated interference section lengths to the total length of the fractures in the shale gas well includes: According to the accumulated interference section length, the ratio of each accumulated interference section length to the total length of the fracture of the shale gas well is calculated using a fourth preset calculation formula; wherein the fourth preset calculation formula is: Among them, R a (j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, L cum (j) is the length of the jth accumulated interference segment, n f is the total number of cracks, x f (i) is the crack half-length corresponding to the i-th crack.

10. The shale gas well production prediction method according to claim 1, characterized in that: Determining the initial production of the shale gas well corresponding to each of the accumulated interference section lengths at the beginning of the late quasi-steady-state flow stage based on the ratio includes: Based on the ratio, the initial production of the shale gas well at the beginning of the late quasi-steady-state flow stage corresponding to each of the cumulative interference section lengths is calculated using a fifth preset calculation formula; wherein the fifth preset calculation formula is: Among them, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, R a (j) is the ratio of the length of the jth cumulative interference section to the total length of the crack, T c (j) is the interference time corresponding to the jth interference segment, and a and b are constants.

11. The shale gas well production prediction method according to claim 1, characterized in that: The step of determining the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well comprises: Dividing the pressure interval formed by the average formation pressure and the bottom hole flow pressure of the shale gas well into several sections according to a preset pressure section length to obtain a plurality of pressure points; Determine the viscosity and compressibility corresponding to each pressure point to obtain the product of the viscosity and compressibility corresponding to each pressure point; For each pressure point, the pseudo pressure corresponding to the pressure point is obtained using the sixth preset calculation formula; wherein the sixth preset calculation formula is: Among them, m(p j ) is the pseudo pressure corresponding to the jth pressure point, p j is the formation pressure at the jth pressure point, p is the average formation pressure, z is the gas compression factor, μ is the gas viscosity corresponding to the average formation pressure, and p sc is the atmospheric pressure under standard conditions; The product of the viscosity and the compressibility coefficient corresponding to each pressure point is used as the ordinate, and the pseudo-pressure corresponding to each pressure point is used as the abscissa, and a relationship curve is drawn in a double logarithmic coordinate system; Determine the slope of any pressure point on the relationship curve using a three-point method; Based on the pseudo-pressure corresponding to the pressure point and the pseudo-pressure corresponding to the bottom hole flow pressure of the shale gas well, the dimensionless pseudo-pressure difference of the pressure point is calculated using the seventh preset calculation formula; wherein the seventh preset calculation formula is: Among them, γ j is the dimensionless pseudo-pressure difference at the jth pressure point, m(p j ) is the pseudo pressure corresponding to the jth pressure point, m(p wf ) is the pseudo-pressure of the bottom hole flowing pressure; In the pseudo pressure range The product of the slope of the pressure point and the dimensionless pseudo-pressure difference is trapezoidally integrated to obtain the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference; wherein the calculation formula of the trapezoidal integral is: Among them, b int is the integral of the product of the slope of the pressure point and the dimensionless pseudo-pressure difference, n p is the number of sections of the pressure interval formed by the average formation pressure and the bottom hole flowing pressure of the shale gas well, β j is the product of the slope corresponding to the jth pressure point and the dimensionless pseudo-pressure difference; Based on the slope of the pressure point and the integral of the product of the dimensionless pseudo-pressure difference, the decreasing index corresponding to each interference segment is calculated using the eighth preset calculation formula; wherein the eighth preset calculation formula is: Among them, b psd is a decreasing index.

12. A shale gas well production prediction system, characterized in that: include: An interference section determination module is used to determine the interference section length of each fracture in the fracture distribution pattern of the shale gas well and the interference distance between adjacent interference sections; wherein the interference section is a fracture section between two fractures that is not blocked by other fractures; An average formation pressure determination module, used to determine the average formation pressure when the shale gas well evolves from an early non-steady-state flow stage to a late quasi-steady-state flow stage under uniform fracturing conditions; An interference time calculation module is used to determine the pseudo-time correction coefficient corresponding to the average formation pressure according to the average formation pressure, and determine the interference time of the interference section corresponding to each interference distance according to the pseudo-time correction coefficient; a decline rate determination module is used to determine the decline rate of the interference section corresponding to each interference time at the beginning of the late pseudo-steady-state flow stage based on the interference time; An accumulation module, used for accumulating the interference segment lengths with the same interference distance to obtain the accumulated interference segment length corresponding to each interference distance, and determining the ratio of each accumulated interference segment length to the total length of the fracture of the shale gas well, and based on the ratio, determining the initial production of the shale gas well corresponding to each accumulated interference segment length at the beginning of the late quasi-steady-state flow stage; A decline index determination module, used to determine the decline index of each interference section when the shale gas well is in the late quasi-steady-state flow stage according to the average formation pressure and the bottom hole flow pressure set for the shale gas well; A model building module is used to build a late quasi-steady-state flow stage production decline model corresponding to each interference section based on the interference time, decline rate, initial production and decline index corresponding to each interference section using a hyperbolic decline model; A production prediction module, for predicting the production of the late quasi-steady-state flow stage of each interference section of the shale gas well by using the production decline model of the late quasi-steady-state flow stage corresponding to each interference section; The production decline model in the late quasi-steady-state flow stage is: Among them, q late (j) is the production of the jth interference section in the late quasi-steady-state flow stage, b psd is a decreasing exponential, q c (j) is the initial output corresponding to the length of the jth cumulative interference segment, D c (j) is the decreasing rate of the jth interference segment, T c (j) is the interference time corresponding to the jth interference segment, and t is time; The model building module is also used to: determine the production decline model of the early non-steady flow stage of the shale gas well; based on the ratio of each of the accumulated interference section lengths to the total length of the fractures of the shale gas well, use the early non-steady flow stage production decline model to build an early non-steady flow stage production prediction model corresponding to each interference section; wherein the early non-steady flow stage production prediction model corresponding to each interference section is used to predict the production of each interference section of the shale gas well when it is in the early non-steady flow stage; The production decline model in the early non-steady-state flow stage is: Among them, q ear is the production of the shale gas well in the early non-steady flow stage, t is time, a and b are constants; a and b are the 1 / q and 1 / q plotted according to the production dynamic data of the shale gas well. The slope and intercept are obtained by scatter fitting the relationship curve; where q is the daily output; When a horizontal well with multiple fractures is producing in the early stage and no interference occurs between the fractures, the production decline model in the early non-steady flow stage is: in, q sc is the gas well production, t is time; T is temperature; h is the gas reservoir thickness; μ is the gas viscosity, m(p) is the pseudo-pressure corresponding to pressure p, x f : Fracture half-length, k is permeability, z is gas compression factor, dimensionless, and the modified compression factor is c t =c g +c ads ;in: ct is the corrected gas compressibility coefficient, cg is the gas compressibility coefficient, cads is the additional gas compressibility coefficient generated by the desorption of adsorbed gas, ρ is the rock density, φ is the porosity; pL is the Langmuir pressure, VL is the Langmuir volume, and p is the pressure.

13. A storage medium having a program code stored thereon, characterized in that: When the program code is executed by a processor, the shale gas well production prediction method according to any one of claims 1 to 11 is implemented.

14. An electronic device, characterized in that: The electronic device includes a memory and a processor. The memory stores program codes that can be run on the processor. When the program codes are executed by the processor, the shale gas well production prediction method according to any one of claims 1 to 11 is implemented.

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