Method and system for determining size of flowback oil nozzle after shale gas well pressure

Abstract

The invention relates to the technical field of oil and gas field development, and provides a method and device for determining the size of a flowback oil nozzle after shale gas well fracturing. The method comprises the steps that gas well parameters of a target shale gas well are obtained, and the critical sand flow velocity of a proppant, the critical liquid carrying flow of a shaft and the final recoverable reserve of the shale gas well are calculated according to the gas well parameters; the first size range, the second size range and the third size range of the flow-back oil nozzle are calculated according to the critical sand flow speed, the critical liquid carrying flow and the final recoverable reserves, and the first size range comprises the fourth size range before fracture closing and the fifth size range after fracture closing; and determining an optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range. The embodiment of the invention can greatly improve the success rate and the working efficiency.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development, and in particular to a method and system for determining the size of a flowback nozzle after compression in a shale gas well. Background Art

[0002] As an unconventional resource with great potential, shale gas reservoirs are of great significance for ensuring energy security and promoting oil and gas reserves and production. Shale gas wells are developed by means of large-scale hydraulic fracturing of horizontal wells. In the flowback stage after fracturing, how to reasonably select the size of the nozzle becomes a key issue. Shale gas formations have problems such as stress sensitivity, sanding of fracture networks and retrograde condensation. When the nozzle size is too large, it may cause permeability damage, proppant reflux, retrograde condensation pollution, etc., while when the nozzle size is too small, the fracturing fluid may not be effectively returned, the gas appearance time of shale gas wells may be delayed, the wellbore may accumulate liquid, and the production capacity of shale gas wells may be affected. At present, the selection of the flowback nozzle system after fracturing of shale gas wells mainly relies on field experience and judgment, and the error rate of nozzle selection is high and the efficiency is low. Summary of the invention

[0003] In view of this, the embodiments of the present disclosure provide a method and system for determining the size of a shale gas well post-pressure return flow nozzle, so as to solve the problem that the selection of the shale gas well post-pressure return flow nozzle system in the prior art relies on field experience and judgment, and the nozzle selection has a high error rate and low efficiency.

[0004] A first aspect of the embodiments of the present disclosure provides a method for determining the size of a shale gas well post-pressure return flow nozzle, comprising:

[0005] Acquire gas well parameters of the target shale gas well, and calculate the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters;

[0006] Calculating a first size range, a second size range and a third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, respectively, wherein the first size range includes a fourth size range before the fracture closure and a fifth size range after the fracture closure;

[0007] An optimal size range is determined based on the second size range, the third size range, the fourth size range and the fifth size range.

[0008] In some embodiments, the step of calculating the first size range according to the critical sand production velocity comprises:

[0009] According to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback;

[0010] When the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, the critical sand production flow rate before the crack closure corresponding to each set nozzle size is calculated; the nozzle size range corresponding to the hydraulic fracture mouth flow rate during flowback being less than the critical sand production flow rate before the crack closure is taken as the fourth size range;

[0011] When the bottom hole pressure is less than the minimum horizontal principal stress, the critical sand production flow rate under different Reynolds numbers after the crack is closed corresponding to each set nozzle size is calculated, and the nozzle size range corresponding to the hydraulic fracture mouth flow rate during backflow being less than the critical sand production flow rate after the crack is closed is taken as the fifth size range.

[0012] In some embodiments, according to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback includes:

[0013] Obtaining hydraulic fracture height, hydraulic fracture width, wellbore radius, wellhead pressure, external transmission pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters;

[0014] The hydraulic fracture opening flow rate during flowback corresponding to each set nozzle size is calculated according to a preset first calculation formula, wherein the first calculation formula includes:

[0015]

[0016] Among them, v f is the flow velocity of the hydraulic fracture mouth during flowback, ρ l is the density of the fracturing fluid, ξ is the local resistance coefficient, r is the preset multiple different nozzle sizes, R is the wellbore radius, P t is the wellhead pressure, P0 is the external transmission pressure, H w is the height of hydraulic fracture, and ω is the width of hydraulic fracture.

[0017] In some embodiments, when the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the critical sand production velocity before the fracture is closed includes:

[0018] When the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, the Reynolds number is calculated according to a preset second calculation formula, wherein the second calculation formula includes:

[0019]

[0020] Wherein, Re is the Reynolds number, ρ l is the density of fracturing fluid, v f is the flow velocity of the hydraulic fracture mouth during flowback, d sd is the proppant particle size in the gas well parameters, and μ is the viscosity of the fracturing fluid in the gas well parameters;

[0021] Calculate the critical sand production flow rate before fracture closure according to the Reynolds number and a preset third calculation formula, where the third calculation formula includes:

[0022] When Re ≤ 2, the critical sand production flow rate is:

[0023]

[0024] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0025]

[0026] When Re > 500, the critical sand production flow rate is:

[0027]

[0028] where d s is the proppant particle size, μ is the viscosity of the fracturing fluid, v cb is the critical sand production flow rate before fracture closure, g is the acceleration due to gravity, ρ s is the proppant density, ρ l is the density of the fracturing fluid.

[0029] In some embodiments, when the bottom hole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculate the critical sand production flow rate after fracture closure, including:

[0030] Calculate the critical sand production flow rate after fracture closure according to the Reynolds number and a preset fourth calculation formula, where the fourth calculation formula includes:

[0031] When Re ≤ 2, the critical sand production flow rate is:

[0032]

[0033] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0034]

[0035] When Re > 500, the critical sand production flow rate is:

[0036]

[0037] where v ca is the critical sand production flow rate after fracture closure, ε is a preset bonding force coefficient, and δ is a preset film parameter.

[0038] In some embodiments, the step of calculating the second size range according to the critical liquid carrying rate comprises:

[0039] Calculating gas-liquid surface tension according to the gas well parameters;

[0040] Calculating the long axis length of the wellbore droplet and the wellbore droplet axis ratio according to the surface tension;

[0041] Calculating a wellbore droplet drag coefficient according to the wellbore droplet axis ratio;

[0042] Calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet;

[0043] Calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density;

[0044] Calculating the critical liquid carrying flow rate according to the critical liquid carrying flow velocity of the wellbore;

[0045] The nozzle size range corresponding to the wellbore flowback flow being greater than the critical liquid carrying flow rate is determined as the second size range.

[0046] In some embodiments, the step of calculating the gas-liquid surface tension according to the gas well parameters comprises:

[0047] Obtaining the wellbore full-angle change rate, wellbore pressure, wellbore temperature, wellbore radius, shale gas viscosity, shale gas relative density, shale gas density, shale gas deviation coefficient, flowback fracturing fluid salinity, liquid production, wellhead pressure, external transmission pressure, fracturing fluid density, shale gas adiabatic index, and shale gas deviation coefficient corresponding to the critical liquid-carrying flow rate;

[0048] The gas-liquid surface tension is calculated according to a preset fifth calculation formula, wherein the fifth calculation formula includes:

[0049]

[0050] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, T is the wellbore temperature, C s is the mineralization of the flowback fracturing fluid.

[0051] In some embodiments, the step of calculating the long axis length of the wellbore droplet and the axis ratio of the wellbore droplet according to the surface tension comprises:

[0052] The long axis length of the wellbore droplet is calculated according to a preset sixth calculation formula, wherein the sixth calculation formula includes:

[0053]

[0054]

[0055] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, ρ l is the density of the fracturing fluid, g is the acceleration due to gravity, d ec is the long axis length of the wellbore droplet, Q l is the liquid production, μ g is the shale gas viscosity, α is the wellbore droplet axis ratio, and R is the wellbore radius.

[0056] In some embodiments, the step of calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio comprises:

[0057] The wellbore droplet drag coefficient is calculated according to a preset seventh calculation formula, wherein the seventh calculation formula includes:

[0058]

[0059] Among them, C d is the wellbore droplet drag coefficient, and α is the wellbore droplet axial ratio.

[0060] In some embodiments, the step of calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore droplet and the drag coefficient of the wellbore droplet comprises:

[0061] The critical liquid-carrying velocity of the wellbore is calculated according to a preset eighth calculation formula, wherein the eighth calculation formula includes:

[0062]

[0063] Among them, v c is the critical liquid-carrying velocity in the wellbore, R θ is the full angle change rate of the wellbore.

[0064] In some embodiments, the step of calculating the critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore comprises:

[0065] The critical liquid carrying flow rate is calculated according to the preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, wherein the ninth calculation formula includes:

[0066]

[0067] Among them, the Q c is the critical liquid carrying flow rate (standard condition), Z is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, and P is the wellbore pressure.

[0068] In some embodiments, the method of calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density includes:

[0069] The wellbore flowback flow rate is calculated according to the predetermined shale gas adiabatic index and shale gas relative density and the preset tenth calculation formula, wherein the tenth calculation formula includes:

[0070]

[0071] Among them, Q f is the wellbore flow rate (standard condition), κ is the shale gas adiabatic index, γ g is the relative density of shale gas, P t is the wellhead pressure, and P0 is the external transmission pressure.

[0072] In some embodiments, the step of calculating the third size range according to the final recoverable reserves comprises:

[0073] Predict multiple ultimate recoverable reserves of target shale gas wells under different nozzle radius conditions based on the trained numerical simulation model;

[0074] A maximum value is screened out from the multiple ultimately recoverable reserves, and a nozzle size range corresponding to the maximum value is determined as the third size range.

[0075] In some embodiments, the training step of the numerical simulation model includes:

[0076] Obtaining the gas well parameters such as porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of fracturing stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, and pressure and output production dynamic data;

[0077] According to the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation data, a static geological model of the target shale gas well is established by using lithofacies modeling and attribute modeling methods;

[0078] Discretizing the static geological model, and constructing an initial numerical simulation model according to the number of fracturing segments and clusters, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data;

[0079] According to the injection amount of the fracturing fluid, the injection process of the fracturing fluid is simulated in the initial numerical simulation model to obtain the distribution of the formation pressure field and saturation field at the end of the fracturing construction;

[0080] The target numerical simulation model is obtained by performing historical matching based on the pressure and output production dynamic data and training the numerical simulation model.

[0081] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range comprises:

[0082] If the second size range, the third size range and the fourth size range form a first intersection, and the second size range, the third size range and the fifth size range form a second intersection, the first intersection and the second intersection are determined as the optimal size range.

[0083] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0084] If the second size range, the third size range and the fourth size range have no intersection, and the second size range, the third size range and the fifth size range form the second intersection, then the fourth size range and the second intersection are determined as the optimal size range.

[0085] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0086] If the second size range, the third size range and the fourth size range do not intersect, and the second size range, the third size range and the fifth size range do not intersect, the third size range, the fourth size range and the fifth size range are combined to perform another judgment;

[0087] If the third size range and the fourth size range form a third intersection, and the third size range and the fifth size range form a fourth intersection, the third intersection and the fourth intersection are determined as the optimal size range.

[0088] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0089] If the third size range and the fourth size range have no intersection, the third size range and the fifth size range form the fourth intersection, and the fourth size range and the fourth intersection are determined as the optimal size range.

[0090] A second aspect of the embodiments of the present disclosure provides a system for determining the size of a shale gas well post-pressure return nozzle, comprising:

[0091] An acquisition module, used to acquire gas well parameters of a target shale gas well, and calculate the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters;

[0092] a calculation module, for calculating a first size range, a second size range and a third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, respectively, wherein the first size range includes a fourth size range before the fracture closure and a fifth size range after the fracture closure;

[0093] A determination module is used to determine an optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range.

[0094] In some embodiments, the step of calculating the first size range according to the critical sand production velocity comprises:

[0095] According to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback;

[0096] When the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, the critical sand production flow rate before the crack closure corresponding to each set nozzle size is calculated; the nozzle size range corresponding to the hydraulic fracture mouth flow rate during flowback being less than the critical sand production flow rate before the crack closure is taken as the fourth size range;

[0097] When the bottom hole pressure is less than the minimum horizontal principal stress, the critical sand production flow rate under different Reynolds numbers after the crack is closed corresponding to each set nozzle size is calculated, and the nozzle size range corresponding to the hydraulic fracture mouth flow rate during backflow being less than the critical sand production flow rate after the crack is closed is taken as the fifth size range.

[0098] In some embodiments, according to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback includes:

[0099] Obtaining hydraulic fracture height, hydraulic fracture width, wellbore radius, wellhead pressure, external transmission pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters;

[0100] The hydraulic fracture opening flow rate during flowback corresponding to each set nozzle size is calculated according to a preset first calculation formula, wherein the first calculation formula includes:

[0101]

[0102] Among them, v f is the flow velocity of the hydraulic fracture mouth during flowback, ρ l is the density of the fracturing fluid, ξ is the local resistance coefficient, r is the preset multiple different nozzle sizes, R is the wellbore radius, P tis the wellhead pressure, P0 is the export pressure, H w is the height of the hydraulic fracture, and ω is the width of the hydraulic fracture at the fracture mouth.

[0103] In some embodiments, when the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure includes:

[0104] When the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the Reynolds number according to a preset second calculation formula, where the second calculation formula includes:

[0105]

[0106] where Re is the Reynolds number, ρ l is the density of the fracturing fluid, v f is the flow velocity at the fracture mouth of the hydraulic fracture during flowback, d s is the proppant particle size in the gas well parameters, and μ is the viscosity of the fracturing fluid in the gas well parameters;

[0107] Calculating the critical sand production flow rate before fracture closure according to the Reynolds number and a preset third calculation formula, where the third calculation formula includes:

[0108] When Re ≤ 2, the critical sand production flow rate is:

[0109]

[0110] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0111]

[0112] When Re > 500, the critical sand production flow rate is:

[0113]

[0114] where d s is the proppant particle size, μ is the viscosity of the fracturing fluid, v cb is the critical sand production flow rate before fracture closure, g is the acceleration due to gravity, ρ s is the proppant density, ρ l is the density of the fracturing fluid.

[0115] In some embodiments, when the bottom-hole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculating the critical sand production flow rate after fracture closure includes:

[0116] Calculating the critical sand production flow rate after fracture closure according to the Reynolds number and a preset fourth calculation formula, where the fourth calculation formula includes:

[0117] When Re ≤ 2, the critical sand production flow rate is:

[0118]

[0119] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0120]

[0121] When Re > 500, the critical sand production flow rate is:

[0122]

[0123] Among them, v ca is the critical sand production flow rate after fracture closure, ε is the preset adhesion coefficient, and δ is the preset film parameter.

[0124] In some embodiments, the step of calculating the second size range according to the critical liquid-carrying flow rate includes:

[0125] Calculating the gas-liquid surface tension according to the gas well parameters;

[0126] Calculating the major axis length and the axis ratio of the wellbore liquid droplet according to the surface tension;

[0127] Calculating the drag coefficient of the wellbore liquid droplet according to the axis ratio of the wellbore liquid droplet;

[0128] Calculating the critical liquid-carrying flow velocity of the wellbore according to the major axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet;

[0129] Calculating the wellbore backflow rate according to the pre-determined adiabatic index of shale gas and the relative density of shale gas;

[0130] Calculating the critical liquid-carrying flow rate according to the critical liquid-carrying flow velocity of the wellbore;

[0131] Determining the nozzle size range corresponding to the wellbore backflow rate greater than the critical liquid-carrying flow rate as the second size range.

[0132] In some embodiments, the step of calculating the gas-liquid surface tension according to the gas well parameters includes:

[0133] Obtaining the full angle change rate, wellbore pressure, wellbore temperature, wellbore radius, shale gas viscosity, relative density of shale gas, density of shale gas, deviation coefficient of shale gas, salinity of the backflow fracturing fluid, liquid production, wellhead pressure, export pressure, density of fracturing fluid, adiabatic index of shale gas, deviation coefficient of shale gas corresponding to the critical liquid-carrying flow rate;

[0134] Calculating the gas-liquid surface tension according to a preset fifth calculation formula, where the fifth calculation formula includes:

[0135]

[0136] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, T is the wellbore temperature, C s is the mineralization of the flowback fracturing fluid.

[0137] In some embodiments, the step of calculating the long axis length of the wellbore droplet and the axis ratio of the wellbore droplet according to the surface tension comprises:

[0138] The long axis length of the wellbore droplet is calculated according to a preset sixth calculation formula, wherein the sixth calculation formula includes:

[0139]

[0140]

[0141] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, ρ l is the density of the fracturing fluid, g is the acceleration due to gravity, d ec is the long axis length of the wellbore droplet, Q l is the liquid production, μ g is the shale gas viscosity, α is the wellbore droplet axis ratio, and R is the wellbore radius.

[0142] In some embodiments, the step of calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio comprises:

[0143] The wellbore droplet drag coefficient is calculated according to a preset seventh calculation formula, wherein the seventh calculation formula includes:

[0144]

[0145] Among them, C d is the wellbore droplet drag coefficient, and α is the wellbore droplet axial ratio.

[0146] In some embodiments, the step of calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore droplet and the drag coefficient of the wellbore droplet comprises:

[0147] The critical liquid-carrying velocity of the wellbore is calculated according to a preset eighth calculation formula, wherein the eighth calculation formula includes:

[0148]

[0149] Among them, v c is the critical liquid-carrying velocity in the wellbore, R θ is the full angle change rate of the wellbore.

[0150] In some embodiments, the step of calculating the critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore comprises:

[0151] The critical liquid carrying flow rate is calculated according to the preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, wherein the ninth calculation formula includes:

[0152]

[0153] Among them, the Q c is the critical liquid carrying flow rate (standard condition), Z is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, and P is the wellbore pressure.

[0154] In some embodiments, the method of calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density includes:

[0155] The wellbore flowback flow rate is calculated according to the predetermined shale gas adiabatic index and shale gas relative density and the preset tenth calculation formula, wherein the tenth calculation formula includes:

[0156]

[0157] Among them, Q f is the wellbore flow rate (standard condition), κ is the shale gas adiabatic index, γ g is the relative density of shale gas, P t is the wellhead pressure, and P0 is the external transmission pressure.

[0158] In some embodiments, the step of calculating the third size range according to the final recoverable reserves comprises:

[0159] Predict multiple ultimate recoverable reserves of target shale gas wells under different nozzle radius conditions based on the trained numerical simulation model;

[0160] A maximum value is screened out from the multiple ultimately recoverable reserves, and a nozzle size range corresponding to the maximum value is determined as the third size range.

[0161] In some embodiments, the training step of the numerical simulation model includes:

[0162] Obtaining the gas well parameters such as porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of fracturing stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, and pressure and output production dynamic data;

[0163] According to the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation data, a static geological model of the target shale gas well is established by using lithofacies modeling and attribute modeling methods;

[0164] Discretizing the static geological model, and constructing an initial numerical simulation model according to the number of fracturing segments and clusters, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data;

[0165] According to the injection amount of the fracturing fluid, the injection process of the fracturing fluid is simulated in the initial numerical simulation model to obtain the distribution of the formation pressure field and saturation field at the end of the fracturing construction;

[0166] The target numerical simulation model is obtained by performing historical matching based on the pressure and output production dynamic data and training the numerical simulation model.

[0167] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range comprises:

[0168] If the second size range, the third size range and the fourth size range form a first intersection, and the second size range, the third size range and the fifth size range form a second intersection, the first intersection and the second intersection are determined as the optimal size range.

[0169] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0170] If the second size range, the third size range and the fourth size range have no intersection, and the second size range, the third size range and the fifth size range form the second intersection, then the fourth size range and the second intersection are determined as the optimal size range.

[0171] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0172] If the second size range, the third size range and the fourth size range do not intersect, and the second size range, the third size range and the fifth size range do not intersect, the third size range, the fourth size range and the fifth size range are combined to perform another judgment;

[0173] If the third size range and the fourth size range form a third intersection, and the third size range and the fifth size range form a fourth intersection, the third intersection and the fourth intersection are determined as the optimal size range.

[0174] In some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range further includes:

[0175] If the third size range and the fourth size range have no intersection, the third size range and the fifth size range form the fourth intersection, and the fourth size range and the fourth intersection are determined as the optimal size range.

[0176] According to a third aspect of an embodiment of the present disclosure, an electronic device is provided, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the above steps when executing the computer program.

[0177] According to a fourth aspect of the embodiments of the present disclosure, a computer-readable storage medium is provided, which stores a computer program. When the computer program is executed by a processor, the above steps are implemented.

[0178] According to a fifth aspect of the embodiments of the present disclosure, a computer program product is provided. The computer program product includes a computer program or instructions. When the computer program or instructions are executed by a processor, the above steps are implemented.

[0179] By acquiring the gas well parameters of the target shale gas well, and calculating the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore and the final recoverable reserves of the shale gas well according to the gas well parameters; calculating the first size range, the second size range and the third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, respectively, wherein the first size range includes the fourth size range before the fracture closure and the fifth size range after the fracture closure; determining the optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range, the size range of the flowback nozzle can be determined without field experience, thereby greatly improving the success rate and work efficiency. BRIEF DESCRIPTION OF THE DRAWINGS

[0180] In order to more clearly illustrate the technical solutions in the embodiments of the present disclosure, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only the embodiments, and for ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work.

[0181] Figure 1 It is a schematic diagram of an application scenario of the method for determining the size of a shale gas well post-pressure return nozzle provided by an embodiment of the present disclosure;

[0182] Figure 2 It is a flowchart of some embodiments of a method for determining the size of a shale gas well post-pressure return nozzle provided by an embodiment of the present disclosure;

[0183] Figure 3 It is a flowchart of some other embodiments of another method for determining the size of a shale gas well post-pressure return nozzle provided by an embodiment of the present disclosure;

[0184] Figure 4 It is a simplified structural schematic diagram of a system for determining the size of a shale gas well post-pressure return nozzle according to an embodiment of the present disclosure;

[0185] Figure 5 is a schematic diagram of an electronic device provided according to an embodiment of the present disclosure;

[0186] Figure 6a It is a schematic diagram of a comparison between the hydraulic fracture mouth flow rate during flowback and the critical sand production flow rate before the fracture is closed according to an embodiment of the present disclosure;

[0187] Figure 6b It is a schematic diagram of another comparison between the flow rate at the opening of a hydraulic fracture during flowback and the critical sand production flow rate after the fracture is closed according to an embodiment of the present disclosure;

[0188] Figure 7 It is a schematic diagram of the comparison between the wellbore flowback flow rate and the critical liquid carrying flow rate provided according to an embodiment of the present disclosure;

[0189] Figure 8 It is a schematic diagram of a numerical simulation model provided according to an embodiment of the present disclosure. DETAILED DESCRIPTION

[0190] Embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although certain embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be construed as being limited to the embodiments set forth herein. On the contrary, these embodiments are provided to provide a more thorough and complete understanding of the present disclosure. It should be understood that the drawings and embodiments of the present disclosure are only for exemplary purposes and are not intended to limit the scope of protection of the present disclosure.

[0191] It should also be noted that, for ease of description, only the parts related to the present disclosure are shown in the drawings. In the absence of conflict, the embodiments and features in the embodiments of the present disclosure can be combined with each other.

[0192] It should be noted that the concepts such as "first" and "second" mentioned in the present disclosure are only used to distinguish different systems, devices, modules or units, and are not used to limit the order or interdependence of the functions performed by these systems, devices, modules or units.

[0193] It should be noted that the modifications of "one" and "plurality" mentioned in the present disclosure are illustrative rather than restrictive, and those skilled in the art should understand that unless otherwise clearly indicated in the context, it should be understood as "one or more".

[0194] The names of the messages or information exchanged between multiple devices in the embodiments of the present disclosure are only used for illustrative purposes and are not used to limit the scope of these messages or information.

[0195] The present disclosure will be described in detail below with reference to the accompanying drawings and in conjunction with embodiments.

[0196] Embodiment 1:

[0197] Figure 1 It is a schematic diagram of an application scenario of the method for determining the size of the flowback nozzle after pressure reduction in a shale gas well according to the first embodiment of the present disclosure.

[0198] exist Figure 1 In the application scenario, first, the computing device 101 can obtain gas well parameters 102 of the target shale gas well, wherein the critical sand production velocity 103 of the proppant, the critical liquid carrying flow rate 104 of the wellbore and the final recoverable reserves 105 of the shale gas well are calculated 102 according to the gas well parameters;

[0199] The first size range 106, the second size range 107 and the third size range 108 of the flowback nozzle are calculated according to the critical sand production velocity 103, the critical liquid carrying flow rate 104 and the final recoverable reserves 105, wherein the first size range 106 includes a fourth size range 109 before the fracture closure and a fifth size range 110 after the fracture closure;

[0200] An optimal size range 111 is determined according to the second size range 107 , the third size range 108 , the fourth size range 109 and the fifth size range 110 .

[0201] It should be noted that the computing device 101 can be hardware or software. When the computing device is hardware, it can be implemented as a distributed cluster consisting of multiple servers or terminal devices, or as a single server or a single terminal device. When the computing device is embodied as software, it can be installed in the hardware devices listed above. It can be implemented as multiple software or software modules for providing distributed services, or as a single software or software module. No specific limitation is made here.

[0202] It should be understood that Figure 1 The number of computing devices in the embodiment is only illustrative. Any number of computing devices may be provided according to implementation requirements.

[0203] Embodiment 2:

[0204] Continue to refer Figure 2 , shows a process 200 of the second embodiment of the method for determining the size of the shale gas well post-pressure return nozzle according to the present disclosure. The method can be Figure 1 The method for determining the size of the shale gas well post-pressure return oil nozzle comprises the following steps:

[0205] Step 201, obtaining gas well parameters of a target shale gas well, and calculating the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters.

[0206] In some embodiments, the execution body of the method for determining the size of the shale gas well post-pressure return oil nozzle (such as Figure 1 The computing device 101 shown can be connected to the target device by wired connection or wireless connection, and then the gas well parameters of the target shale gas well are obtained, and the critical sand flow rate of the proppant, the critical liquid flow rate of the wellbore and the final recoverable reserves of the shale gas well are calculated according to the gas well parameters. The gas well parameters can refer to various relevant data involved in the operation of the shale gas well. The critical sand flow rate of the proppant, the critical liquid flow rate of the wellbore and the final recoverable reserves of the shale gas well are all commonly used parameters in the field calculated based on the data in the gas well parameters, and will not be repeated here.

[0207] It should be noted that the above-mentioned wireless connection methods may include but are not limited to 3G / 4G / 5G connection, WiFi connection, Bluetooth connection, WiMAX connection, Zigbee connection, UWB (ultra wideband) connection, and other wireless connection methods currently known or developed in the future.

[0208] Step 202, respectively calculate the first size range, the second size range and the third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, wherein the first size range includes the fourth size range before the fracture closure and the fifth size range after the fracture closure. The first size range, the second size range, the third size range, the fourth size range and the fifth size range refer to different ranges of nozzle sizes.

[0209] In some embodiments, the above-mentioned execution entity can calculate the first size range according to the critical sand production flow rate based on the following steps: the first step is to calculate the hydraulic fracture mouth flow rate corresponding to each set nozzle size during backflow according to the gas well parameters and a plurality of preset set nozzle sizes of different sizes; the second step is to calculate the critical sand production flow rate before the fracture closure corresponding to each set nozzle size when the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress; the nozzle size range corresponding to the hydraulic fracture mouth flow rate during backflow being less than the critical sand production flow rate before the fracture closure is taken as the fourth size range; the third step is to calculate the critical sand production flow rate under different Reynolds numbers after the fracture closure corresponding to each set nozzle size when the bottom hole pressure is less than the minimum horizontal principal stress, and the nozzle size range corresponding to the hydraulic fracture mouth flow rate during backflow being less than the critical sand production flow rate after the fracture closure is taken as the fifth size range. It should be pointed out that the nozzle size cannot be set arbitrarily, but is predetermined to be of different sizes; for example, the nozzle size can be one of the following: 2.1, 3.2, 3.6 (mm), etc. When calculating various data, multiple existing nozzle sizes (i.e., set nozzle sizes) are selected and imported into various calculation formulas for calculation, and judgment and calculation are performed accordingly; therefore, the range of the nozzle determined is also based on the existing nozzle sizes, for example, the nozzle size can be (2.1 to 3.2) (mm). However, it should be noted that the above nozzle sizes are only for illustration, and the specific size of the nozzle is set according to the actual situation, and is not limited thereto.

[0210] In some optional implementations of some embodiments, according to the gas well parameters and a plurality of preset nozzle sizes of different sizes, the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback is calculated, such as Figure 6a and Figure 6b As shown, it shows the comparison of the hydraulic fracture mouth flow rate during two kinds of backflow and the critical sand production flow rate before and after the fracture closure, including: obtaining the hydraulic fracture height, hydraulic fracture mouth width, wellbore radius, wellhead pressure, external transmission pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters; calculating the hydraulic fracture mouth flow rate during backflow corresponding to each set oil nozzle size according to a preset first calculation formula, wherein the first calculation formula includes:

[0211]

[0212] Among them, v f is the flow velocity of the hydraulic fracture mouth during flowback, ρ l is the density of the fracturing fluid, ξ is the local resistance coefficient, r is the preset multiple different nozzle sizes, R is the wellbore radius, P t is the wellhead pressure, P0 is the external transmission pressure, Hw is the height of the hydraulic fracture, and ω is the width of the hydraulic fracture mouth.

[0213] In some optional implementation manners of some embodiments, when the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure includes: when the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the Reynolds number according to a preset second calculation formula, where the second calculation formula includes:

[0214]

[0215] where Re is the Reynolds number, ρ l is the density of the fracturing fluid, v f is the flow velocity at the mouth of the hydraulic fracture during flowback, d s is the proppant particle size in the gas well parameters, and μ is the viscosity of the fracturing fluid in the gas well parameters; calculating the critical sand production flow rate before fracture closure according to the Reynolds number and a preset third calculation formula, where the third calculation formula includes:

[0216] When Re ≤ 2, the critical sand production flow rate is:

[0217]

[0218] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0219]

[0220] When Re > 500, the critical sand production flow rate is:

[0221]

[0222] where d s is the proppant particle size, μ is the viscosity of the fracturing fluid, v cb is the critical sand production flow rate before fracture closure, g is the acceleration due to gravity, ρ s is the proppant density, ρ l is the density of the fracturing fluid.

[0223] In some embodiments, when the bottom-hole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculating the critical sand production flow rate after fracture closure includes: calculating the critical sand production flow rate after fracture closure according to the Reynolds number and a preset fourth calculation formula, where the fourth calculation formula includes:

[0224] When Re ≤ 2, the critical sand production flow rate is:

[0225]

[0226] When 2 < Re ≤ 500, the critical sand production flow rate is:

[0227]

[0228] When Re > 500, the critical sand production flow rate is:

[0229]

[0230] Among them, v ca is the critical sand production flow rate after fracture closure, ε is the preset adhesion coefficient, and δ is the preset film parameter in the gas well parameters. Among them, the preset adhesion coefficient and the preset film parameter can be pre - formulated parameters.

[0231] In some alternative implementation manners of some embodiments, the step of calculating the second size range according to the critical liquid - carrying flow rate includes: calculating the gas - liquid surface tension according to the gas well parameters; calculating the major axis length and the axis ratio of the wellbore liquid droplet according to the surface tension; calculating the drag coefficient of the wellbore liquid droplet according to the axis ratio of the wellbore liquid droplet; calculating the critical liquid - carrying flow velocity of the wellbore according to the major axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet; calculating the wellbore back - flow rate according to the pre - determined adiabatic index and relative density of shale gas; calculating the critical liquid - carrying flow rate according to the critical liquid - carrying flow velocity of the wellbore; determining the choke size range corresponding to the wellbore back - flow rate being greater than the critical liquid - carrying flow rate as the second size range.

[0232] In some alternative implementation manners of some embodiments, the step of calculating the gas - liquid surface tension according to the gas well parameters includes:

[0233] Obtaining the full - angle change rate of the wellbore, wellbore pressure, wellbore temperature, wellbore radius, shale gas viscosity, shale gas relative density, shale gas density, shale gas deviation coefficient, salinity of the back - flow fracturing fluid, liquid production rate, wellhead pressure, external transmission pressure, fracturing fluid density, adiabatic index of shale gas, and shale gas deviation coefficient corresponding to the critical liquid - carrying flow rate;

[0234] Calculating the gas - liquid surface tension according to a preset fifth calculation formula, where the fifth calculation formula includes:

[0235]

[0236] Among them, σ is the gas - liquid surface tension, ρ g is the shale gas density, T is the wellbore temperature, and C s is the salinity of the back - flow fracturing fluid.

[0237] In some alternative implementation manners of some embodiments, the calculation steps of calculating the major axis length and the axis ratio of the wellbore liquid droplet according to the surface tension include:

[0238] The long axis length of the wellbore droplet is calculated according to a preset sixth calculation formula, wherein the sixth calculation formula includes:

[0239]

[0240]

[0241] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, ρ l is the density of the fracturing fluid, g is the acceleration due to gravity, d ec is the long axis length of the wellbore droplet, Q l is the liquid production, μ g is the shale gas viscosity, α is the wellbore droplet axis ratio, and R is the wellbore radius.

[0242] In some optional implementations of some embodiments, the step of calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio includes:

[0243] The wellbore droplet drag coefficient is calculated according to a preset seventh calculation formula, wherein the seventh calculation formula includes:

[0244]

[0245] Among them, C d is the wellbore droplet drag coefficient, and α is the wellbore droplet axial ratio.

[0246] In some optional implementations of some embodiments, the step of calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet includes:

[0247] The critical liquid-carrying velocity of the wellbore is calculated according to a preset eighth calculation formula, wherein the eighth calculation formula includes:

[0248]

[0249] Among them, v c is the critical liquid-carrying velocity in the wellbore, R θ is the full angle change rate of the wellbore.

[0250] In some optional implementations of some embodiments, the step of calculating the critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore includes:

[0251] The critical liquid carrying flow rate is calculated according to the preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, as follows: Figure 7 As shown, the ninth calculation formula includes:

[0252]

[0253] Among them, the Q c is the critical liquid carrying flow rate (standard condition), Z is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, and P is the wellbore pressure.

[0254] In some optional implementations of some embodiments, the calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density includes:

[0255] The wellbore flowback flow rate is calculated according to the predetermined shale gas adiabatic index and shale gas relative density and the preset tenth calculation formula, wherein the tenth calculation formula includes:

[0256]

[0257] Among them, Q f is the wellbore flow rate (standard condition), κ is the shale gas adiabatic index, γ g is the relative density of shale gas, P t is the wellhead pressure, and P0 is the external transmission pressure.

[0258] In some optional implementations of some embodiments, the calculation step of calculating the third size range based on the final recoverable reserves includes: predicting multiple final recoverable reserves of the target shale gas well under different nozzle radius conditions based on a trained numerical simulation model; screening out the maximum value from the multiple final recoverable reserves, and determining the nozzle size range corresponding to the maximum value as the third size range.

[0259] It should be noted that the first to tenth calculation formulas mentioned above are all set names of the calculation formulas corresponding to the steps, and the set names can be changed as needed and are not limited to this.

[0260] In some optional implementations of some embodiments, the training step of the numerical simulation model includes: obtaining the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of clusters of fracturing stages, injection volume of fracturing fluid, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, and pressure and output production dynamic data from the gas well parameters; establishing a static geological model of the target shale gas well using lithofacies modeling and attribute modeling methods based on the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation results data; discretizing the static geological model, and constructing an initial numerical simulation model based on the number of clusters of fracturing stages, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data (please refer to Figure 8); according to the injection amount of the fracturing fluid, the injection process of the fracturing fluid is simulated in the initial numerical simulation model to obtain the formation pressure field and saturation field distribution at the end of the fracturing construction; according to the pressure and output production dynamic data, historical fitting is performed to train the numerical simulation model to obtain the target numerical simulation model. The above parameters are commonly used parameters in this field and will not be described in detail here. Historical fitting can refer to data fitting based on historical data to train the target numerical simulation model. The initial numerical simulation model and the target numerical simulation model can refer to the calculation models before / after training for predicting the final recoverable reserves data based on the above parameters, respectively.

[0261] Step 203: determining an optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range.

[0262] In some embodiments, the execution entity may determine the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range based on the following steps:

[0263] In the first step, if the second size range, the third size range and the fourth size range form a first intersection, and the second size range, the third size range and the fifth size range form a second intersection, the first intersection and the second intersection are determined as the optimal size range.

[0264] In the second step, if the second size range, the third size range and the fourth size range have no intersection, and the second size range, the third size range and the fifth size range form the second intersection, then the fourth size range and the second intersection are determined as the optimal size range.

[0265] Step 3: If the second size range, the third size range and the fourth size range do not intersect, and the second size range, the third size range and the fifth size range do not intersect, the third size range, the fourth size range and the fifth size range are combined to make another judgment;

[0266] In the fourth step, if the third size range and the fourth size range form a third intersection, and the third size range and the fifth size range form a fourth intersection, the third intersection and the fourth intersection are determined as the optimal size range.

[0267] In a fifth step, if the third size range and the fourth size range have no intersection, the third size range and the fifth size range form the fourth intersection, and the fourth size range and the fourth intersection are determined as the optimal size range.

[0268] In addition, it should be pointed out that the first size range is relatively large and will normally intersect with the third size range. In special cases, the fourth size range before flowback may not intersect with the third size range, or the fourth size range before flowback may not intersect with the second and third size ranges. In this case, the fourth size range is selected as the nozzle range before flowback.

[0269] The beneficial effects of one of the implementation methods in the above-mentioned embodiments of the present disclosure at least include: obtaining the gas well parameters of the target shale gas well, and calculating the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the final recoverable reserves of the shale gas well according to the gas well parameters; calculating the first size range, the second size range, and the third size range of the return oil nozzle according to the critical sand production velocity, the critical liquid carrying flow rate, and the final recoverable reserves, respectively, wherein the first size range includes the fourth size range before the fracture closure and the fifth size range after the fracture closure; determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range, so that the size range of the return oil nozzle can be determined without field experience, which greatly improves the success rate and work efficiency.

[0270] The present disclosure is further described below through a specific embodiment:

[0271] Taking the shale gas well Y10 in area A as an example, the optimization design of the post-pressure flowback nozzle system was carried out.

[0272] Step 1: Collect the reservoir parameters, fracture parameters, wellbore parameters, fluid parameters and proppant parameters of the shale gas reservoir of Well Y10. Including the minimum horizontal principal stress P c The hydraulic fracture height is 65MPa and H w is 40m, the hydraulic fracture width ω is 0.003m, the wellbore radius R is 0.031m, and the wellhead pressure P t 45~25MPa, bottom hole pressure P wf is 75~55MPa, the external pressure P0 is 0.1MPa, and the fracturing fluid density ρ l 1020kg / m 3 , fracturing fluid viscosity μ is 0.008~0.002Pa·s, proppant density ρ s 2780kg / m 3 , proppant particle size d s It is 0.0004m.

[0273] Step 2: Calculate according to the above method: When the bottom hole pressure P wf Greater than the minimum horizontal principal stress P c When the hydraulic fracture mouth flow velocity v is f Less than the critical sand flow rate v before crack closure cbThe corresponding nozzle size range is used as the appropriate nozzle size range to prevent proppant backflow before the fracture is closed, and is stored in U1 (the first size range). The appropriate nozzle size range to prevent proppant backflow before the fracture is closed in the Y10 well is 2 to 3 mm (the fourth size range). wf Less than the minimum horizontal principal stress P c When the hydraulic fracture mouth flow velocity v is f Less than the critical sand flow rate v after crack closure ca The corresponding nozzle size range is used as the suitable nozzle size range for preventing proppant backflow after fracture closure and is stored in U1. The suitable nozzle size range for preventing proppant backflow after fracture closure in well Y10 is 2-12 mm (the fifth size range).

[0274] Step 3: Collect the wellbore parameters and fluid parameters of the shale gas reservoir of Well Y10, including the wellbore full angle change rate R θ 0.001~5.8° / 30m, wellbore pressure P is 15~27MPa, wellbore temperature T is 296~349K, shale gas viscosity μ g 0.02×10 -3 ~0.03×10 -3 Pa·s, shale gas relative density γ g is 0.68, shale gas density ρ g 169~217kg / m 3 , shale gas deviation coefficient Z is 0.75-0.9, and the mineralization degree of flowback fracturing fluid is C s The liquid output is 45140ppm and Q l 15m 3 / d.

[0275] Step 4: Calculate the wellbore flow rate Q according to the above method: f Greater than the critical liquid carrying flow rate Q c The corresponding nozzle size range is used as the suitable nozzle size range for effective wellbore liquid carrying and is stored in U2 (second size range). The suitable nozzle size range for the wellbore flowback flow rate of Y10 well greater than the critical liquid carrying flow rate is 5-12 mm (second size range).

[0276] Step 5: Collect the reservoir parameters, well parameters, fracture parameters, fluid parameters and production dynamic parameters of the shale gas reservoir of Well Y10, including original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of fracturing stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, pressure and output production dynamic data.

[0277] Step 6: Based on the original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation data, a static geological model of Well Y10 was established using lithofacies modeling and attribute modeling methods, and geological modeling software such as Petrel.

[0278] Step 7: Discretize the static geological model and import it into reservoir numerical simulation software such as Eclipse, and establish a numerical simulation model for the Y10 well based on the number of fracturing segments, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data. Figure 8 shown.

[0279] Step 8: According to the injection volume of the fracturing fluid, the injection process of the fracturing fluid is simulated in the numerical simulation model of the Y10 well to obtain the formation pressure field and saturation field distribution at the end of the fracturing construction.

[0280] Step 9: Perform history fitting of the Y10 well based on the pressure and output production dynamic data to ensure that the history fitting accuracy of the numerical simulation model meets the requirements of field applications.

[0281] Step 10: Use the numerical simulation model to predict the EUR (ultimate recoverable reserves) of the Y10 well under different nozzle radius conditions, and use the nozzle size range corresponding to the maximum EUR value predicted by the numerical simulation as the appropriate nozzle size range that meets the EUR requirement, and store it in U3 (the third size range). As shown in Table 1, the nozzle size range corresponding to the maximum EUR value of the Y10 well is 5-6 mm (the third size range).

[0282] Nozzle size / mm <![CDATA[EUR / 10 8 m 3 ]]> 3～4 0.46186 5～6 0.54339 7～8 0.42548 9～10 0.37134

[0283] Table 1 EUR simulation of well Y10

[0284] Step 11: The intersection of the nozzle size ranges U1, U2, and U3 of the Y10 well is used as the optimal nozzle system for the post-pressure backflow of the shale gas well, and is stored in U4. U4 is a backflow nozzle system that can simultaneously meet the requirements of preventing proppant backflow, effective wellbore liquid carrying, and EUR. The nozzle size range U1 of the Y10 well is: the suitable nozzle size range for preventing proppant backflow before the fracture is closed is 2 to 3 mm, and the suitable nozzle size range for preventing proppant backflow after the fracture is closed is 2 to 12 mm. The nozzle size range U2 of the Y10 well is: the suitable nozzle size range for the wellbore backflow flow rate greater than the critical liquid carrying flow rate is 5 to 12 mm. The nozzle size range U3 of the Y10 well is: the nozzle size range corresponding to the maximum value of EUR is 5 to 6 mm. The intersection of nozzle ranges U1, U2, and U3 is taken as the optimal nozzle system for post-pressure flowback in Well Y10, and U4 is: the optimal nozzle size range before fracture closure is 2 to 3 mm, and the optimal nozzle size range after fracture closure is 5 to 6 mm.

[0285] Embodiment three:

[0286] Continue to refer Figure 3 , shows a process 300 of the third embodiment of the method for determining the size of the shale gas well post-pressure return nozzle according to the present disclosure, which can be Figure 1 The method for determining the size of the shale gas well post-pressure return nozzle comprises:

[0287] Step 301, obtaining gas well parameters of a target shale gas well, and calculating the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters.

[0288] Step 302, according to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculate the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback.

[0289] Step 303, when the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, the critical sand production flow rate before the crack closure corresponding to each set nozzle size is calculated. The nozzle size range corresponding to the hydraulic fracture mouth flow rate during flowback being less than the critical sand production flow rate before the crack closure is taken as the fourth size range.

[0290] Step 304, when the bottom hole pressure is less than the minimum horizontal principal stress, the critical sand production flow rate under different Reynolds numbers after the fracture closure corresponding to each set nozzle size is calculated, and the nozzle size range corresponding to the hydraulic fracture mouth flow rate during flowback is less than the critical sand production flow rate after the fracture closure is taken as the fifth size range.

[0291] Step 305, calculating the gas-liquid surface tension according to the gas well parameters.

[0292] Step 306, calculating the long axis length of the wellbore droplet and the wellbore droplet axis ratio according to the surface tension.

[0293] Step 307, calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio.

[0294] Step 308: Calculate the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet.

[0295] Step 309, calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density.

[0296] Step 310: Calculate the critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore.

[0297] Step 311, determining the nozzle size range corresponding to the wellbore flowback flow rate being greater than the critical liquid carrying flow rate as the second size range.

[0298] Step 312: predict multiple final recoverable reserves of the target shale gas well under different nozzle radius conditions according to the trained numerical simulation model.

[0299] Step 313, screening out a maximum value from a plurality of final recoverable reserves, and determining the nozzle size range corresponding to the maximum value as a third size range.

[0300] Step 314, determining an optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range.

[0301] In some embodiments, the specific implementation of steps 301-314 and the technical effects brought about can be referred to Figure 2 The corresponding steps in the second embodiment are not described again here.

[0302] All the above optional technical solutions can be combined in any way to form optional implementation methods of the present application, and will not be described in detail here.

[0303] Embodiment 4:

[0304] The following are system embodiments of the present disclosure, which can be used to execute the method embodiments of the present disclosure. For details not disclosed in the system embodiments of the present disclosure, please refer to the method embodiments of the present disclosure.

[0305] Further references Figure 4 As an implementation of the above methods in the above figures, the present disclosure provides an embodiment of a system for determining the size of a shale gas well post-pressure return oil nozzle. Figure 2 The above-mentioned embodiment 2 corresponds.

[0306] like Figure 4 As shown, the shale gas well post-pressure return oil nozzle size determination system 400 of this embodiment includes:

[0307] The acquisition module 401 is used to acquire the gas well parameters of the target shale gas well, and calculate the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore and the ultimate recoverable reserves of the shale gas well according to the gas well parameters.

[0308] The calculation module 402 is used to calculate the first size range, the second size range and the third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, wherein the first size range includes the fourth size range before the fracture closure and the fifth size range after the fracture closure.

[0309] The determination module 403 is configured to determine an optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range.

[0310] In some optional implementations of some embodiments, the step of calculating the first size range according to the critical sand production velocity includes:

[0311] According to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback;

[0312] When the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, the critical sand production flow rate before the crack closure corresponding to each set nozzle size is calculated; the nozzle size range corresponding to the hydraulic fracture mouth flow rate during flowback being less than the critical sand production flow rate before the crack closure is taken as the fourth size range;

[0313] When the bottom hole pressure is less than the minimum horizontal principal stress, the critical sand production flow rate under different Reynolds numbers after the crack is closed corresponding to each set nozzle size is calculated, and the nozzle size range corresponding to the hydraulic fracture mouth flow rate during backflow being less than the critical sand production flow rate after the crack is closed is taken as the fifth size range.

[0314] In some optional implementations of some embodiments, according to the gas well parameters and a plurality of preset nozzle sizes of different sizes, calculating the hydraulic fracture orifice flow rate corresponding to each set nozzle size during flowback includes:

[0315] Obtaining hydraulic fracture height, hydraulic fracture width, wellbore radius, wellhead pressure, external transmission pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters;

[0316] The hydraulic fracture opening flow rate during flowback corresponding to each set nozzle size is calculated according to a preset first calculation formula, wherein the first calculation formula includes:

[0317]

[0318] Among them, v f is the flow velocity of the hydraulic fracture mouth during flowback, ρ l is the density of the fracturing fluid, ξ is the local resistance coefficient, r is the preset multiple different nozzle sizes, R is the wellbore radius, P t is the wellhead pressure, P0 is the external transmission pressure, H w is the height of hydraulic fracture, and ω is the width of hydraulic fracture.

[0319] In some optional implementations of some embodiments, when the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the critical sand production velocity before the fracture is closed includes:

[0320] When the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculate the Reynolds number according to a preset second calculation formula, where the second calculation formula includes:

[0321]

[0322] where Re is the Reynolds number, ρ l is the density of the fracturing fluid, v f is the flow velocity at the mouth of the hydraulic fracture during flowback, d s is the proppant particle size in the gas well parameters, and μ is the viscosity of the fracturing fluid in the gas well parameters;

[0323] Calculate the critical sand production flow velocity before fracture closure according to the Reynolds number and a preset third calculation formula, where the third calculation formula includes:

[0324] When Re ≤ 2, the critical sand production flow velocity is:

[0325]

[0326] When 2 < Re ≤ 500, the critical sand production flow velocity is:

[0327]

[0328] When Re > 500, the critical sand production flow velocity is:

[0329]

[0330] where d s is the proppant particle size, μ is the viscosity of the fracturing fluid, v cb is the critical sand production flow velocity before fracture closure, g is the acceleration due to gravity, ρ s is the proppant density, ρ l is the density of the fracturing fluid.

[0331] In some alternative implementation manners of some embodiments, when the bottom-hole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculate the critical sand production flow velocity after fracture closure, including: calculate the critical sand production flow velocity after fracture closure according to the Reynolds number and a preset fourth calculation formula, where the fourth calculation formula includes:

[0332] When Re ≤ 2, the critical sand production flow velocity is:

[0333]

[0334] When 2 < Re ≤ 500, the critical sand production flow velocity is:

[0335]

[0336] When Re>500, the critical sand flow rate is:

[0337]

[0338] Among them, v ca is the critical sand flow rate after crack closure, ε is the preset adhesion coefficient, and δ is the preset film parameter.

[0339] In some optional implementations of some embodiments, the step of calculating the second size range based on the critical liquid carrying flow rate includes: calculating the gas-liquid surface tension based on the gas well parameters; calculating the long axis length of the wellbore droplet and the wellbore droplet axis ratio based on the surface tension; calculating the wellbore droplet drag coefficient based on the wellbore droplet axis ratio; calculating the wellbore critical liquid carrying flow rate based on the long axis length of the wellbore droplet and the wellbore droplet drag coefficient; calculating the wellbore return flow rate based on a predetermined shale gas adiabatic index and shale gas relative density; calculating the critical liquid carrying flow rate based on the wellbore critical liquid carrying flow rate; and determining the nozzle size range corresponding to the wellbore return flow rate being greater than the critical liquid carrying flow rate as the second size range.

[0340] In some optional implementations of some embodiments, the step of calculating the gas-liquid surface tension according to the gas well parameters includes:

[0341] Obtaining the wellbore full-angle change rate, wellbore pressure, wellbore temperature, wellbore radius, shale gas viscosity, shale gas relative density, shale gas density, shale gas deviation coefficient, flowback fracturing fluid salinity, liquid production, wellhead pressure, external transmission pressure, fracturing fluid density, shale gas adiabatic index, and shale gas deviation coefficient corresponding to the critical liquid-carrying flow rate;

[0342] The gas-liquid surface tension is calculated according to a preset fifth calculation formula, wherein the fifth calculation formula includes:

[0343]

[0344] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, T is the wellbore temperature, C s is the mineralization of the flowback fracturing fluid.

[0345] In some optional implementations of some embodiments, the step of calculating the long axis length of the wellbore droplet and the axis ratio of the wellbore droplet according to the surface tension includes:

[0346] The long axis length of the wellbore droplet is calculated according to a preset sixth calculation formula, wherein the sixth calculation formula includes:

[0347]

[0348]

[0349] Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, ρ l is the density of the fracturing fluid, g is the acceleration due to gravity, d ec is the long axis length of the wellbore droplet, Q l is the liquid production, μ g is the shale gas viscosity, α is the wellbore droplet axis ratio, and R is the wellbore radius.

[0350] In some optional implementations of some embodiments, the step of calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio includes:

[0351] The wellbore droplet drag coefficient is calculated according to a preset seventh calculation formula, wherein the seventh calculation formula includes:

[0352]

[0353] Among them, C d is the wellbore droplet drag coefficient, and α is the wellbore droplet axial ratio.

[0354] In some optional implementations of some embodiments, the step of calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore droplet and the drag coefficient of the wellbore droplet includes:

[0355] The critical liquid-carrying velocity of the wellbore is calculated according to a preset eighth calculation formula, wherein the eighth calculation formula includes:

[0356]

[0357] Among them, v c is the critical liquid-carrying velocity in the wellbore, R θ is the full angle change rate of the wellbore.

[0358] In some optional implementations of some embodiments, the step of calculating the critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore includes:

[0359] The critical liquid carrying flow rate is calculated according to the preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, wherein the ninth calculation formula includes:

[0360]

[0361] Among them, the Q c is the critical liquid carrying flow rate (standard condition), Z is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, and P is the wellbore pressure.

[0362] In some optional implementations of some embodiments, the calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density includes:

[0363] The wellbore flowback flow rate is calculated according to the predetermined shale gas adiabatic index and shale gas relative density and the preset tenth calculation formula, wherein the tenth calculation formula includes:

[0364]

[0365] Among them, Q f is the wellbore flow rate (standard condition), κ is the shale gas adiabatic index, γ g is the relative density of shale gas, P t is the wellhead pressure, and P0 is the external transmission pressure.

[0366] In some optional implementations of some embodiments, the step of calculating the third size range according to the final recoverable reserves includes:

[0367] Predict multiple ultimate recoverable reserves of target shale gas wells under different nozzle radius conditions based on the trained numerical simulation model;

[0368] A maximum value is screened out from the multiple ultimately recoverable reserves, and a nozzle size range corresponding to the maximum value is determined as the third size range.

[0369] In some optional implementations of some embodiments, the training step of the numerical simulation model includes:

[0370] Obtaining the gas well parameters such as porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of fracturing stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, and pressure and output production dynamic data;

[0371] According to the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation data, a static geological model of the target shale gas well is established by using lithofacies modeling and attribute modeling methods;

[0372] Discretizing the static geological model, and constructing an initial numerical simulation model according to the number of fracturing segments and clusters, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data;

[0373] According to the injection amount of the fracturing fluid, the injection process of the fracturing fluid is simulated in the initial numerical simulation model to obtain the distribution of the formation pressure field and saturation field at the end of the fracturing construction;

[0374] The target numerical simulation model is obtained by performing historical matching based on the pressure and output production dynamic data and training the numerical simulation model.

[0375] In some optional implementations of some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range includes:

[0376] If the second size range, the third size range and the fourth size range form a first intersection, and the second size range, the third size range and the fifth size range form a second intersection, the first intersection and the second intersection are determined as the optimal size range.

[0377] In some optional implementations of some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range further includes:

[0378] If the second size range, the third size range and the fourth size range have no intersection, and the second size range, the third size range and the fifth size range form the second intersection, then the fourth size range and the second intersection are determined as the optimal size range.

[0379] In some optional implementations of some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range further includes:

[0380] If the second size range, the third size range and the fourth size range do not intersect, and the second size range, the third size range and the fifth size range do not intersect, the third size range, the fourth size range and the fifth size range are combined to perform another judgment;

[0381] If the third size range and the fourth size range form a third intersection, and the third size range and the fifth size range form a fourth intersection, the third intersection and the fourth intersection are determined as the optimal size range.

[0382] In some optional implementations of some embodiments, determining the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range further includes:

[0383] If the third size range and the fourth size range have no intersection, the third size range and the fifth size range form the fourth intersection, and the fourth size range and the fourth intersection are determined as the optimal size range.

[0384] It is understood that the modules described in the system 400 are similar to those described in the reference Figure 2 Therefore, the operations, features and beneficial effects described above for the method are also applicable to the system 400 and the modules included therein, and will not be described in detail here.

[0385] Embodiment five:

[0386] like Figure 5 As shown, the electronic device 500 may include a processing device (e.g., a central processing unit, a graphics processing unit, etc.) 501, which can perform various appropriate actions and processes according to a program stored in a read-only memory (ROM) 502 or a program loaded from a storage device 508 into a random access memory (RAM) 503. In the RAM 503, various programs and data required for the operation of the electronic device 500 are also stored. The processing device 501, the ROM 502, and the RAM 503 are connected to each other via a bus 504. An input / output (I / O) interface 505 is also connected to the bus 504.

[0387] Typically, the following devices may be connected to the I / O interface 505: an input device 506 including, for example, a touch screen, a touch pad, a keyboard, a mouse, a camera, a microphone, an accelerometer, a gyroscope, etc.; an output device 507 including, for example, a liquid crystal display (LCD), a speaker, a vibrator, etc.; a storage device 508 including, for example, a magnetic tape, a hard disk, etc.; and a communication device 509. The communication device 509 may allow the electronic device 500 to communicate with other devices wirelessly or by wire to exchange data. Although Figure 5 The electronic device 500 is shown with various devices, but it should be understood that it is not required to implement or possess all the devices shown. More or fewer devices may be implemented or possessed instead. Figure 5 Each block shown in the figure may represent one device, or may represent multiple devices as required.

[0388] In particular, according to this embodiment, the process described above with reference to the flowchart can be implemented as a computer software program. For example, this embodiment includes a computer program product, which includes a computer program or instructions carried on a computer-readable medium, and the computer program or instructions contain program codes for executing the method shown in the flowchart. In this embodiment, the computer program can be downloaded and installed from the network through the communication device 509, or installed from the storage device 508, or installed from the ROM 502. When the computer program is executed by the processing device 501, it can be executed. Figure 2 The corresponding steps.

[0389] It should be noted that the computer-readable medium in the present embodiment may be a computer-readable signal medium or a computer-readable storage medium or any combination of the two. The computer-readable storage medium may be, for example, but not limited to, an electrical, magnetic, optical, electromagnetic, infrared, or semiconductor system, device or device, or any combination of the above. More specific examples of computer-readable storage media may include, but are not limited to: an electrical connection with one or more wires, a portable computer disk, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or flash memory), an optical fiber, a portable compact disk read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the above. In the present embodiment, the computer-readable storage medium may be any tangible medium containing or storing a program that may be used by or in combination with an instruction execution system, device or device. In the present embodiment, the computer-readable signal medium may include a data signal propagated in a baseband or as part of a carrier wave, which carries a computer-readable program code. This propagated data signal may take a variety of forms, including but not limited to electromagnetic signals, optical signals, or any suitable combination of the above. The computer readable signal medium may also be any computer readable medium other than a computer readable storage medium, which may send, propagate or transmit a program for use by or in conjunction with an instruction execution system, apparatus or device. The program code contained on the computer readable medium may be transmitted using any suitable medium, including but not limited to: wires, optical cables, RF (radio frequency), etc., or any suitable combination of the above.

[0390] In some embodiments, the client and the server may communicate using any currently known or future developed network protocol such as HTTP (HyperText Transfer Protocol), and may be interconnected with any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include a local area network ("LAN"), a wide area network ("WAN"), an internet (e.g., the Internet), and a peer-to-peer network (e.g., an ad hoc peer-to-peer network), as well as any currently known or future developed network.

[0391] The computer-readable medium may be included in the device; or it may exist independently without being installed in the electronic device. The computer-readable medium carries one or more programs. When the one or more programs are executed by the electronic device, the electronic device executes the executable program. Figure 2 The corresponding steps.

[0392] The computer program code for performing the operation of the present embodiment can be written in one or more programming languages ​​or a combination thereof, including object-oriented programming languages, such as Java, Smalltalk, C++, and conventional procedural programming languages, such as "C" language or similar programming languages. The program code can be executed entirely on the user's computer, partially on the user's computer, as an independent software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In the case of a remote computer, the remote computer can be connected to the user's computer through any type of network, including a local area network (LAN) or a wide area network (WAN), or can be connected to an external computer (e.g., using an Internet service provider to connect through the Internet).

[0393] The flow chart and block diagram in the accompanying drawings illustrate the possible architecture, function and operation of the system, method and computer program product according to various embodiments of the present disclosure. In this regard, each square box in the flow chart or block diagram can represent a module, a program segment or a part of a code, and the module, the program segment or a part of the code contains one or more executable instructions for realizing the specified logical function. It should also be noted that in some implementations as replacements, the functions marked in the square box can also occur in a sequence different from that marked in the accompanying drawings. For example, two square boxes represented in succession can actually be executed substantially in parallel, and they can sometimes be executed in the opposite order, depending on the functions involved. It should also be noted that each square box in the block diagram and / or flow chart, and the combination of the square boxes in the block diagram and / or flow chart can be implemented with a dedicated hardware-based system that performs a specified function or operation, or can be implemented with a combination of dedicated hardware and computer instructions.

[0394] The modules described in this embodiment may be implemented by software or hardware. The modules described may also be set in a processor, for example, may be described as:

[0395] Acquisition module, calculation module and determination module. For example, the acquisition module can also be described as a "module for acquiring gas well parameters of a target shale gas well".

[0396] The functions described above herein may be performed at least in part by one or more hardware logic components. For example, without limitation, exemplary types of hardware logic components that may be used include: field programmable gate arrays (FPGAs), application specific integrated circuits (ASICs), application specific standard products (ASSPs), systems on chips (SOCs), complex programmable logic devices (CPLDs), and the like.

[0397] The above descriptions are only some preferred embodiments of the present disclosure and an explanation of the technical principles used. Those skilled in the art should understand that the scope of the invention involved in the embodiments of the present disclosure is not limited to the technical solutions formed by a specific combination of the above-mentioned technical features, but should also cover other technical solutions formed by any combination of the above-mentioned technical features or their equivalent features without departing from the above-mentioned inventive concept. For example, the above-mentioned features are replaced with the technical features with similar functions disclosed in the embodiments of the present disclosure (but not limited to) and the technical solutions formed.

Claims

1. A method for determining the size of a shale gas well post-pressure return oil nozzle, characterized in that: Including: Obtain the gas well parameters of the target shale gas well, and calculate the critical sand production flow rate of the proppant, the critical liquid-carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters; Calculate the first size range, the second size range, and the third size range of the backflow choke respectively according to the critical sand production flow rate, the critical liquid-carrying flow rate, and the ultimate recoverable reserves. Among them, the first size range includes the fourth size range before fracture closure and the fifth size range after fracture closure; Determine the optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range.

2. The method according to claim 1, characterized in that The calculation steps for calculating the first size range according to the critical sand production flow rate include: According to the gas well parameters and a plurality of preset setting choke sizes of different sizes, calculate the hydraulic fracture orifice flow rate corresponding to each setting choke size during backflow; When the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculate the critical sand production flow rate before fracture closure corresponding to each setting choke size; the choke size range corresponding to the hydraulic fracture orifice flow rate during backflow being less than the critical sand production flow rate before fracture closure is used as the fourth size range; When the bottom-hole pressure is less than the minimum horizontal principal stress, calculate the critical sand production flow rate at different Reynolds numbers after fracture closure corresponding to each setting choke size, and the choke size range corresponding to the hydraulic fracture orifice flow rate during backflow being less than the critical sand production flow rate after fracture closure is used as the fifth size range.

3. The method according to claim 2, characterized in that Calculating the hydraulic fracture orifice flow rate corresponding to each setting choke size during backflow according to the gas well parameters and a plurality of preset setting choke sizes of different sizes includes: Obtain the hydraulic fracture height, hydraulic fracture orifice width, wellbore radius, wellhead pressure, export pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters; Calculate the hydraulic fracture orifice flow rate during backflow corresponding to each setting choke size according to a preset first calculation formula, where the first calculation formula includes: Among them, v f is the flow velocity of the hydraulic fracture mouth during flowback, ρ l is the density of the fracturing fluid, ξ is the local resistance coefficient, r is the preset multiple different nozzle sizes, R is the wellbore radius, P t is the wellhead pressure, P0 is the external transmission pressure, H w is the height of hydraulic fracture, and ω is the width of hydraulic fracture.

4. The method according to claim 3, characterized in that When the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure includes: When the bottom-hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculate the Reynolds number according to a preset second calculation formula, where the second calculation formula includes: Wherein, Re is the Reynolds number, ρ l is the density of fracturing fluid, v f is the flow velocity of the hydraulic fracture mouth during flowback, d s is the proppant particle size in the gas well parameters, μ is the fracturing fluid viscosity in the gas well parameters; Calculate the critical sand production flow rate before fracture closure according to the Reynolds number and a preset third calculation formula, where the third calculation formula includes: When Re ≤ 2, the critical sand production flow rate is: When 2 < Re ≤ 500, the critical sand production flow rate is: When Re > 500, the critical sand production flow rate is: Among them, d s is the proppant particle size, μ is the fracturing fluid viscosity, v cb is the critical sand flow rate before the fracture closes, g is the gravitational acceleration, ρ s is the proppant density, ρ l is the density of fracturing fluid.

5. The method according to claim 4, characterized in that When the bottom-hole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculating the critical sand production flow rate after fracture closure includes: Calculate the critical sand production flow rate after fracture closure according to the Reynolds number and a preset fourth calculation formula, where the fourth calculation formula includes: When Re ≤ 2, the critical sand production flow rate is: When 2 < Re ≤ 500, the critical sand production flow rate is: When Re > 500, the critical sand production flow rate is: Among them, v ca is the critical sand flow rate after crack closure, ε is the preset adhesion coefficient, and δ is the preset film parameter.

6. The method according to claim 1, characterized in that The steps for calculating the second size range according to the critical liquid-carrying flow rate include: Calculating gas-liquid surface tension according to the gas well parameters; Calculating the long axis length of the wellbore droplet and the wellbore droplet axis ratio according to the surface tension; Calculating a wellbore droplet drag coefficient according to the wellbore droplet axis ratio; Calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet; Calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density; Calculating the critical liquid carrying flow rate according to the critical liquid carrying flow velocity of the wellbore; The nozzle size range corresponding to the wellbore flowback flow being greater than the critical liquid carrying flow rate is determined as the second size range.

7. The method according to claim 6, characterized in that The step of calculating the gas-liquid surface tension according to the gas well parameters comprises: Obtaining the wellbore full-angle change rate, wellbore pressure, wellbore temperature, wellbore radius, shale gas viscosity, shale gas relative density, shale gas density, shale gas deviation coefficient, flowback fracturing fluid salinity, liquid production, wellhead pressure, external transmission pressure, fracturing fluid density, shale gas adiabatic index, and shale gas deviation coefficient corresponding to the critical liquid-carrying flow rate; The gas-liquid surface tension is calculated according to a preset fifth calculation formula, wherein the fifth calculation formula includes: Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, T is the wellbore temperature, C s is the mineralization of the flowback fracturing fluid.

8. The method according to claim 7, characterized in that The steps of calculating the long axis length of the wellbore droplet and the axis ratio of the wellbore droplet according to the surface tension include: The long axis length of the wellbore droplet is calculated according to a preset sixth calculation formula, wherein the sixth calculation formula includes: Where σ is the gas-liquid surface tension, ρ g is the density of shale gas, ρ l is the density of the fracturing fluid, g is the acceleration due to gravity, d ec is the long axis length of the wellbore droplet, Q l is the liquid production, μ g is the shale gas viscosity, α is the wellbore droplet axis ratio, and R is the wellbore radius.

9. The method according to claim 8, characterized in that The step of calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio comprises: The wellbore droplet drag coefficient is calculated according to a preset seventh calculation formula, wherein the seventh calculation formula includes: Among them, C d is the wellbore droplet drag coefficient, and α is the wellbore droplet axial ratio.

10. The method according to claim 9, characterized in that The step of calculating the critical liquid-carrying velocity of the wellbore according to the long axis length of the wellbore liquid droplet and the drag coefficient of the wellbore liquid droplet comprises: The critical liquid-carrying velocity of the wellbore is calculated according to a preset eighth calculation formula, wherein the eighth calculation formula includes: Among them, v c is the critical liquid-carrying velocity in the wellbore, R θ is the full angle change rate of the wellbore.

11. The method according to claim 10, characterized in that The step of calculating the critical liquid carrying flow rate according to the critical liquid carrying flow velocity of the wellbore comprises: The critical liquid carrying flow rate is calculated according to the preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, wherein the ninth calculation formula includes: Among them, the Q c is the critical liquid carrying flow rate (standard condition), Z is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, and P is the wellbore pressure.

12. The method according to claim 7, characterized in that The method of calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and shale gas relative density includes: The wellbore flowback flow rate is calculated according to the predetermined shale gas adiabatic index and shale gas relative density and the preset tenth calculation formula, wherein the tenth calculation formula includes: Among them, Q f is the wellbore flow rate (standard condition), κ is the shale gas adiabatic index, γ g is the relative density of shale gas, P t is the wellhead pressure, and P0 is the external transmission pressure.

13. The method according to claim 1, characterized in that The step of calculating the third size range according to the final recoverable reserves comprises: Predict multiple ultimate recoverable reserves of target shale gas wells under different nozzle radius conditions based on the trained numerical simulation model; A maximum value is screened out from the multiple ultimately recoverable reserves, and a nozzle size range corresponding to the maximum value is determined as the third size range.

14. The method according to claim 13, characterized in that The training steps of the numerical simulation model include: Obtaining the gas well parameters such as porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation results data, number of fracturing stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experimental data, and pressure and output production dynamic data; According to the porosity, permeability, saturation, original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, and logging interpretation data, a static geological model of the target shale gas well is established by using lithofacies modeling and attribute modeling methods; Discretizing the static geological model, and constructing an initial numerical simulation model according to the number of fracturing segments and clusters, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data; According to the injection amount of the fracturing fluid, the injection process of the fracturing fluid is simulated in the initial numerical simulation model to obtain the distribution of the formation pressure field and saturation field at the end of the fracturing construction; The target numerical simulation model is obtained by performing historical matching based on the pressure and output production dynamic data and training the numerical simulation model.

15. The method according to claim 1, characterized in that Determining an optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range includes: If the second size range, the third size range and the fourth size range form a first intersection, and the second size range, the third size range and the fifth size range form a second intersection, the first intersection and the second intersection are determined as the optimal size range.

16. The method according to claim 15, characterized in that The method further comprises: If the second size range, the third size range and the fourth size range have no intersection, and the second size range, the third size range and the fifth size range form the second intersection, then the fourth size range and the second intersection are determined as the optimal size range.

17. The method according to claim 16, characterized in that The method further comprises: If the second size range, the third size range and the fourth size range do not intersect, and the second size range, the third size range and the fifth size range do not intersect, the third size range, the fourth size range and the fifth size range are combined to perform another judgment; If the third size range and the fourth size range form a third intersection, and the third size range and the fifth size range form a fourth intersection, the third intersection and the fourth intersection are determined as the optimal size range.

18. The method according to claim 17, characterized in that The method further comprises: If the third size range and the fourth size range have no intersection, the third size range and the fifth size range form the fourth intersection, and the fourth size range and the fourth intersection are determined as the optimal size range.

19. A shale gas well post-pressure return oil nozzle size determination system, characterized in that: include: An acquisition module, used to acquire gas well parameters of a target shale gas well, and calculate the critical sand production velocity of the proppant, the critical liquid carrying flow rate of the wellbore, and the ultimate recoverable reserves of the shale gas well according to the gas well parameters; A calculation module, for calculating a first size range, a second size range and a third size range of the flowback nozzle according to the critical sand production velocity, the critical liquid carrying flow rate and the final recoverable reserves, wherein the first size range includes a fourth size range before the fracture closure and a fifth size range after the fracture closure; A determination module is used to determine an optimal size range according to the second size range, the third size range, the fourth size range and the fifth size range.

20. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that: When the processor executes the computer program, the steps of the method according to any one of claims 1 to 18 are implemented.

21. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by a processor, the steps of the method according to any one of claims 1 to 18 are implemented.

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