Method and system for determining the size of a flowback choke for a shale gas well

Abstract

The present disclosure relates to the technical field of oil and gas field development, and provides a shale gas well post-fracturing flowback nozzle size determination method and device. The method comprises: obtaining gas well parameters of a target shale gas well, and calculating a critical sand production flow rate of proppant, a critical liquid carrying flow rate of a wellbore, and a final recoverable reserve of the shale gas well according to the gas well parameters; calculating a first size range, a second size range, and a third size range of a flowback nozzle according to the critical sand production flow rate, the critical liquid carrying flow rate, and the final recoverable reserve respectively, wherein the first size range comprises a fourth size range before fracture closure and a fifth size range after fracture closure; 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 present disclosure can greatly improve the success rate and work efficiency.

Description

TECHNICAL FIELD

[0001] The present disclosure relates to the technical field of oil and gas field development, and particularly relates to a method and system for determining the size of a flowback nozzle after fracturing of a shale gas well. BACKGROUND

[0002] As a kind of unconventional resource with great potential, shale gas reservoirs are of great significance to promote oil and gas reserves and production. Shale gas wells are developed by using horizontal wells and large-scale hydraulic fracturing. During the flowback stage after fracturing, how to reasonably select the size of the flowback nozzle becomes a key problem. Shale gas formations have problems such as stress sensitivity, sand production from fracture networks, and retrograde condensation. If the size of the flowback nozzle is too large, it may cause damage to permeability, support agent backflow, and retrograde condensation pollution. If the size of the flowback nozzle is too small, it may cause the fracturing fluid to be unable to effectively flow back, the shale gas well to be late in gas breakthrough, the wellbore to be liquid-filled, and the shale gas well production to be affected. Currently, the selection of the flowback nozzle size after fracturing of a shale gas well mainly relies on field experience, and the selection of the flowback nozzle has a high error rate and low efficiency. SUMMARY

[0003] Therefore, the present disclosure provides a method and system for determining the size of a flowback nozzle after fracturing of a shale gas well to solve the problem that the selection of the flowback nozzle size after fracturing of a shale gas well relies on field experience in the prior art, and the selection of the flowback nozzle has a high error rate and low efficiency.

[0004] In a first aspect, the present disclosure provides a method for determining the size of a flowback nozzle after fracturing of a shale gas well, comprising:

[0005] obtaining gas well parameters of a target shale gas well, and calculating a critical sand production flow rate of a support agent, a critical liquid carrying flow rate of a wellbore, and a final recoverable reserve 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 flow rate, the critical liquid carrying flow rate, and the final recoverable reserve, respectively, wherein the first size range includes a fourth size range before fracture closure and a fifth size range after fracture closure;

[0007] determining an optimal size range according to the second size range, the third size range, the fourth size range, and the fifth size range.

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

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

[0010] when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure corresponding to each set choke size;

[0011] when the bottom hole pressure is less than the minimum horizontal principal stress, calculating the critical sand production flow rate under different Reynolds numbers after fracture closure corresponding to each set choke size, and taking the choke size range corresponding to the hydraulic fracture aperture flow rate less than the critical sand production flow rate after fracture closure as the fifth size range.

[0012] In some embodiments, according to the gas well parameter and a plurality of different sizes of set choke sizes preset, the hydraulic fracture aperture flow rate corresponding to each set choke size during flowback is calculated, including:

[0013] obtaining the hydraulic fracture height, the hydraulic fracture aperture width, the wellbore radius, the wellhead pressure, the delivery pressure, the fracturing fluid density, the proppant density, the local resistance coefficient, the proppant particle size, and the fracturing fluid viscosity corresponding to the gas well parameter;

[0014] calculating the hydraulic fracture aperture flow rate during flowback corresponding to each set choke size according to a preset first calculation formula, wherein the first calculation formula includes:

[0015]

[0016] wherein, is the hydraulic fracture aperture flow rate during flowback, is the fracturing fluid density, is the local resistance coefficient, is the plurality of different sizes of choke sizes preset, is the wellbore radius, is the wellhead pressure, is the delivery pressure, is the hydraulic fracture height, is the hydraulic fracture aperture width.

[0017] In some embodiments, when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, the critical sand production flow rate before fracture closure is calculated, including:

[0018] when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure corresponding to each set choke size;

[0019]

[0020] wherein, the Re is the Reynolds number, is the fracturing fluid density, for a hydraulic fracture tip velocity at flowback, for a proppant size in the gas well parameters, for a fracturing fluid viscosity in the gas well parameters;

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

[0022] when , the critical sand production flow rate is:

[0023]

[0024] when , the critical sand production flow rate is:

[0025]

[0026] when , the critical sand production flow rate is:

[0027]

[0028] wherein, is a proppant size, is a fracturing fluid viscosity, is the critical sand production flow rate before fracture closure, is a gravitational acceleration, is a proppant density, is a fracturing fluid density.

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

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

[0031] when , the critical sand production flow rate is:

[0032]

[0033] when , the critical sand production flow rate is:

[0034]

[0035] when , the critical sand production flow rate is:

[0036]

[0037] wherein, is a critical sand production flow rate after fracture closure, is a preset cohesion coefficient, is a preset film parameter.

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

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

[0040] calculating a wellbore droplet major axis length and a 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 a wellbore critical liquid carrying flow rate according to the wellbore droplet major axis length and the wellbore droplet drag coefficient;

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

[0044] calculating a critical liquid carrying flow rate according to the wellbore critical liquid carrying flow rate;

[0045] determining a choke size range corresponding to the wellbore flowback flow rate being greater than the critical liquid carrying flow rate as the second size range.

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

[0047] obtaining a wellbore full angle change rate, a wellbore pressure, a wellbore temperature, a wellbore radius, a shale gas viscosity, a shale gas relative density, a shale gas density, a shale gas deviation coefficient, a flowback fracturing fluid salinity, a production fluid volume, a wellhead pressure, a transportation pressure, a fracturing fluid density, a shale gas adiabatic index, a shale gas deviation coefficient corresponding to the critical liquid carrying flow rate;

[0048] calculating the gas-liquid surface tension according to a preset fifth calculation formula, wherein the fifth calculation formula comprises:

[0049]

[0050] wherein, is a gas-liquid surface tension, is a shale gas density, is a wellbore temperature, is a flowback fracturing fluid salinity.

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

[0052] calculating the wellbore droplet major axis length according to a predetermined sixth calculation formula, wherein the sixth calculation formula comprises:

[0053]

[0054]

[0055] wherein, is a gas-liquid surface tension, is a shale gas density, is a fracturing fluid density, is a gravitational acceleration, is a wellbore droplet major axis length, is a liquid production rate, is a shale gas viscosity, is a wellbore droplet axis ratio, is a wellbore radius.

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

[0057] calculating the wellbore droplet drag coefficient according to a predetermined seventh calculation formula, wherein the seventh calculation formula comprises:

[0058]

[0059] wherein, is a wellbore droplet drag coefficient, is a wellbore droplet axis ratio.

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

[0061] calculating the wellbore critical liquid carrying flow rate according to a predetermined eighth calculation formula, wherein the eighth calculation formula comprises:

[0062]

[0063] wherein, is a wellbore critical liquid carrying flow rate, is a wellbore full angle change rate.

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

[0065] calculating the critical liquid carrying flow rate according to a predetermined ninth calculation formula, and the wellbore critical liquid carrying flow rate, wherein the ninth calculation formula comprises:

[0066]

[0067] wherein the is a critical liquid-carrying flow rate (standard condition), is a shale gas deviation coefficient, T is a wellbore temperature, R is a wellbore radius, P is a wellbore pressure.

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

[0069] calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and the shale gas relative density, and a preset tenth calculation formula, wherein the tenth calculation formula comprises:

[0070]

[0071] wherein, is a wellbore flowback flow rate (standard condition), is a shale gas adiabatic index, is a shale gas relative density, is a wellhead pressure, is a delivery pressure.

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

[0073] predicting a plurality of final recoverable reserves of the target shale gas well under different choke radii according to the trained numerical simulation model;

[0074] selecting a maximum value from the plurality of final recoverable reserves, and determining a choke size range corresponding to the maximum value as the third size range.

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

[0076] obtaining porosity, permeability, saturation, original formation pressure, seismic data, geological layering data, wellhead data, well trajectory data, logging interpretation result data, number of fracturing sections and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experiment data, pressure and production production performance data in the gas well parameters;

[0077] establishing a static geological model of the target shale gas well by using facies modeling method and attribute modeling method according to the porosity, permeability, saturation, original formation pressure, seismic data, geological layering data, wellhead data, well trajectory data, logging interpretation result data;

[0078] Discretizing the static geological model, and constructing an initial numerical simulation model based on the number of fracturing stages 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 operation;

[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 based on the second size range, the third size range, the fourth size range, and the fifth size range includes:

[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 based on 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 based on 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, then the judgment is repeated by combining the third size range, the fourth size range, and the fifth size range.

[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 based on 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] In a second aspect, the present disclosure provides a shale gas well post-fracturing flowback nozzle size determination system, comprising:

[0091] An acquisition module is configured to acquire gas well parameters of a target shale gas well, and calculate a critical sand production flow rate of proppants, a critical liquid carrying flow rate of a wellbore, and a final recoverable reserve of the shale gas well according to the gas well parameters.

[0092] A calculation module is configured to calculate a first size range, a second size range, and a third size range of a flowback nozzle according to the critical sand production flow rate, the critical liquid carrying flow rate, and the final recoverable reserve, respectively, wherein the first size range comprises a fourth size range before fracture closure and a fifth size range after fracture closure.

[0093] A determination module 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.

[0094] In some embodiments, the calculation of the first size range according to the critical sand production flow rate comprises:

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

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

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

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

[0099] acquiring a hydraulic fracture height, a hydraulic fracture aperture width, a wellbore radius, a wellhead pressure, a delivery pressure, a fracturing fluid density, a proppant density, a local resistance coefficient, a proppant size, a fracturing fluid viscosity corresponding to the gas well parameter;

[0100] calculating a hydraulic fracture aperture flow rate at flowback corresponding to each set of the nozzle size according to a preset first calculation formula, wherein the first calculation formula comprises:

[0101]

[0102] wherein, is the hydraulic fracture aperture flow rate at flowback, is the fracturing fluid density, is the local resistance coefficient, is a plurality of different nozzle sizes preset, is the wellbore radius, is the wellhead pressure, is the delivery pressure, is the hydraulic fracture height, is the hydraulic fracture aperture width.

[0103] In some embodiments, when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, a critical sand flow rate before fracture closure is calculated, comprising:

[0104] when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, a Reynolds number is calculated according to a preset second calculation formula, wherein the second calculation formula comprises:

[0105]

[0106] wherein, the Re is the Reynolds number, is the fracturing fluid density, is the hydraulic fracture aperture flow rate at flowback, is the proppant size in the gas well parameter, is the fracturing fluid viscosity in the gas well parameter;

[0107] the critical sand flow rate before fracture closure is calculated according to the Reynolds number and a preset third calculation formula, the third calculation formula comprising:

[0108] when , the critical sand flow rate is:

[0109]

[0110] when , the critical sand flow rate is:

[0111]

[0112] When the critical sand production flow rate is:

[0113]

[0114] wherein, is the proppant grain size, is the fracturing fluid viscosity, is the critical sand production flow rate before fracture closure, is the gravitational acceleration, is the proppant density, is the fracturing fluid density.

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

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

[0117] When the critical sand production flow rate is:

[0118]

[0119] When the critical sand production flow rate is:

[0120]

[0121] When the critical sand production flow rate is:

[0122]

[0123] wherein, is the critical sand production flow rate after fracture closure, is a preset cohesion coefficient, is a preset film parameter.

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

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

[0126] calculating a wellbore droplet major axis length and a wellbore droplet axis ratio according to the surface tension;

[0127] calculating a wellbore droplet drag coefficient according to the wellbore droplet axis ratio;

[0128] calculating a critical liquid carrying flow rate of the wellbore according to the long axis length of the wellbore droplet and the drag coefficient of the wellbore droplet;

[0129] calculating a flowback flow rate of the wellbore according to the predetermined adiabatic index of the shale gas and the relative density of the shale gas;

[0130] calculating a critical liquid carrying flow rate according to the critical liquid carrying flow rate of the wellbore;

[0131] determining a choke size range corresponding to the flowback flow rate of the wellbore being 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 comprises:

[0133] obtaining a wellbore full angle change rate, a wellbore pressure, a wellbore temperature, a wellbore radius, a shale gas viscosity, a shale gas relative density, a shale gas density, a shale gas deviation factor, a flowback fracturing fluid salinity, a produced fluid volume, a wellhead pressure, a transportation pressure, a fracturing fluid density, a shale gas adiabatic index, a shale gas deviation factor corresponding to the critical liquid carrying flow rate;

[0134] calculating the gas-liquid surface tension according to a preset fifth calculation formula, wherein the fifth calculation formula comprises:

[0135]

[0136] wherein, is a gas-liquid surface tension, is a shale gas density, is a wellbore temperature, is a flowback fracturing fluid salinity.

[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] calculating the long axis length of the wellbore droplet according to a preset sixth calculation formula, wherein the sixth calculation formula comprises:

[0139]

[0140]

[0141] wherein, is a gas-liquid surface tension, is a shale gas density, is a fracturing fluid density, is a gravitational acceleration, is a wellbore droplet long axis length, is a produced fluid volume, is a shale gas viscosity, is a wellbore droplet axis ratio, is a wellbore radius.

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

[0143] calculating the wellbore droplet drag coefficient according to a preset seventh calculation formula, wherein the seventh calculation formula comprises:

[0144]

[0145] wherein, is a wellbore droplet drag coefficient, is a wellbore droplet axis ratio.

[0146] In some embodiments, the step of calculating a wellbore critical liquid carrying flow rate according to the wellbore droplet major axis length and the wellbore droplet drag coefficient comprises:

[0147] calculating the wellbore critical liquid carrying flow rate according to a preset eighth calculation formula, wherein the eighth calculation formula comprises:

[0148]

[0149] wherein, is a wellbore critical liquid carrying flow rate, is a wellbore full angle change rate.

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

[0151] calculating the critical liquid carrying flow rate according to a preset ninth calculation formula and the wellbore critical liquid carrying flow rate, wherein the ninth calculation formula comprises:

[0152]

[0153] wherein, the is a critical liquid carrying flow rate (standard condition), is a shale gas deviation coefficient, T is a wellbore temperature, R is a wellbore radius, P is a wellbore pressure.

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

[0155] calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and the shale gas relative density, and a preset tenth calculation formula, wherein the tenth calculation formula comprises:

[0156]

[0157] wherein, is the wellbore flowback flow rate (standard condition), is the shale gas adiabatic index, is the shale gas relative density, is the wellhead pressure, is the export pressure.

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

[0159] predicting a plurality of final recoverable reserves of the target shale gas well under different choke radii according to the trained numerical simulation model;

[0160] selecting a maximum value from the plurality of final recoverable reserves, and determining the size range corresponding to the maximum value as the third size range.

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

[0162] obtaining porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, logging interpretation result data, number of fracturing sections, number of fracturing clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity experiment data, pressure and production production dynamic data in the gas well parameters;

[0163] establishing a static geological model of the target shale gas well by using facies modeling method and attribute modeling method according to the porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, logging interpretation result data;

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

[0165] simulating the injection process of fracturing fluid in the initial numerical simulation model according to the fracturing fluid injection volume, to obtain the distribution of formation pressure field and saturation field at the end of fracturing operation;

[0166] performing history matching according to the pressure and production production dynamic data, and training the numerical simulation model to obtain the target 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 comprises:

[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, 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 comprises:

[0172] 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 also have no intersection, a re-determination is made in combination of the third size range, the fourth size range and the fifth size range.

[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 comprises:

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

[0176] In a third aspect, the embodiments of the present disclosure provide an electronic device, including a memory, a processor, and a computer program stored in the memory and capable of running on the processor, and the processor implements the above steps when executing the computer program.

[0177] In a fourth aspect, the embodiments of the present disclosure provide a computer readable storage medium, which stores a computer program, and the computer program implements the above steps when executed by a processor.

[0178] In a fifth aspect, the present disclosure provides a computer program product comprising a computer program or instructions which, when executed by a processor, implement the steps described above.

[0179] By acquiring the gas well parameters of the target shale gas well, and calculating the critical sand 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; according to the critical sand flow rate, the critical liquid carrying flow rate and the ultimate recoverable reserves, the first size range, the second size range and the third size range of the flowback nozzle are calculated, respectively, wherein the first size range includes the fourth size range before the fracture closure and the fifth size range after the fracture closure; according to the second size range, the third size range, the fourth size range and the fifth size range, the optimal size range is determined, so that the size range of the flowback nozzle can be determined without field experience, and the success rate and work efficiency are greatly improved. BRIEF DESCRIPTION OF DRAWINGS

[0180] In order to more clearly illustrate the technical solutions in the embodiments of the present disclosure, the drawings needed to be used in the embodiments or prior art description will be briefly introduced as follows. Obviously, the drawings in the following description are only for the embodiments of the present disclosure, and other drawings can also be obtained by those skilled in the art without creative labor.

[0181] Figure 1 is a schematic diagram of one application scenario of a shale gas well post-fracturing flowback nozzle size determination method provided according to the embodiments of the present disclosure;

[0182] Figure 2 is a flowchart of some embodiments of a shale gas well post-fracturing flowback nozzle size determination method provided according to the embodiments of the present disclosure;

[0183] Figure 3 is a flowchart of some other embodiments of another shale gas well post-fracturing flowback nozzle size determination method provided according to the embodiments of the present disclosure;

[0184] Figure 4 is a simple structure schematic diagram of a shale gas well post-fracturing flowback nozzle size determination system provided according to the embodiments of the present disclosure;

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

[0186] Figure 6a is a schematic diagram of a comparison between the hydraulic fracture aperture flow rate during flowback and the critical sand flow rate before fracture closure according to the embodiments of the present disclosure;

[0187] Figure 6bis a schematic diagram of another comparison case of the hydraulic fracture opening flow rate 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 is a schematic diagram of a comparison case of the wellbore flowback flow rate and the critical liquid carrying flow rate according to an embodiment of the present disclosure.

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

[0190] Embodiments of the present disclosure will be described in more detail with reference to the drawings. Although some embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure can be implemented in various forms, and should not be interpreted as being limited to the embodiments set forth herein. Rather, these embodiments are provided so that the present disclosure can be more thoroughly and completely understood. It should be understood that the drawings and embodiments of the present disclosure are only for illustrative purposes, and are not intended to limit the scope of protection of the present disclosure.

[0191] In addition, it should be further noted that, for the convenience of description, only the parts related to the present disclosure are shown in the drawings. The embodiments in the present disclosure and the features in the embodiments can be combined with each other without conflict.

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

[0193] It should be noted that the adjectives "one", "multiple" mentioned in the present disclosure are illustrative and not limiting, and those skilled in the art should understand that, unless otherwise explicitly indicated in the context, it should be understood as "one or more".

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

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

[0196] Embodiment one:

[0197] Figure 1 is a schematic diagram of one application scenario of a shale gas well post-pressing flowback nozzle size determination method according to embodiment one of the present disclosure.

[0198] In Figure 1In the application scenario, first, the computing device 101 may obtain gas well parameters 102 of the target shale gas well, and calculate 102 the critical sand production velocity 103 of the proppant, the critical liquid carrying flow rate 104 of the wellbore, and the ultimate recoverable reserves 105 of the shale gas well;

[0199] A first size range 106, a second size range 107, and a third size range 108 of the flowback nozzle are calculated based on the critical sand production velocity 103, the critical liquid carrying flow rate 104, and the ultimate recoverable reserves 105, respectively. 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 based on 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 either 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 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 limitations are given here.

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

[0203] Example 2:

[0204] Continue to refer Figure 2 , shows the 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 a flowback nozzle after pressure reduction in a shale gas well comprises the following steps:

[0205] Step 201 : 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 based on the gas well parameters.

[0206] In some embodiments, the execution subject of the method for determining the size of the shale gas well post-pressure return nozzle (such as Figure 1The computing device 101 shown can be connected to the target device through wired connection or wireless connection, then the gas well parameters of the target shale gas well are acquired, and the critical sand flow rate of the proppant, the critical liquid carrying flow rate of the wellbore and the ultimate 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 shale gas well operation process. The critical sand flow rate of the proppant, the critical liquid carrying flow rate of the wellbore and the ultimate recoverable reserves of the shale gas well are all common parameters in the art, which are calculated according to the data in the gas well parameters and will not be described here.

[0207] It should be noted that the wireless connection mode can include but is not limited to 3G / 4G / 5G connection, WiFi connection, Bluetooth connection, WiMAX connection, Zigbee connection, UWB (ultra wideband) connection and other now known or future developed wireless connection modes.

[0208] Step 202, respectively according to the critical sand flow rate, the critical liquid carrying flow rate and the ultimate recoverable reserves, the first size range, the second size range and the third size range of the flowback choke are calculated, wherein the first size range includes a fourth size range before the fracture closes and a fifth size range after the fracture closes. The first size range, the second size range, the third size range, the fourth size range and the fifth size range respectively refer to different ranges of choke size.

[0209] In some embodiments, the execution subject can calculate the first size range according to the critical sand production flow rate based on the following steps: first, calculate the hydraulic fracture aperture flow rate corresponding to each set choke size during flowback according to the gas well parameters and a plurality of preset different sizes of set choke sizes; second, 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 set choke size; the choke size range corresponding to the hydraulic fracture aperture flow rate during flowback that is less than the critical sand production flow rate before fracture closure is the fourth size range; third, when the bottom hole pressure is less than the minimum horizontal principal stress, calculate the critical sand production flow rate under different Reynolds numbers after fracture closure corresponding to each set choke size, and the choke size range corresponding to the hydraulic fracture aperture flow rate during flowback that is less than the critical sand production flow rate after fracture closure is the fifth size range. It should be noted that the choke size is not arbitrarily set, but is a plurality of different sizes that are determined in advance; for example, the choke size can be one of the following: 2.1, 3.2, 3.6 (mm), etc. When calculating each data, the existing plurality of choke sizes (i.e., set choke sizes) are selected and introduced into each calculation formula for calculation, and the range of the determined choke is also based on the existing size of the choke, for example, the choke size can be (2.1 to 3.2) (mm). However, it should be noted that the above-mentioned sizes of the choke are only for illustration, and the specific size of the choke is set according to the actual situation, and is not limited thereto.

[0210] In some optional implementations of some embodiments, the hydraulic fracture aperture flow rate corresponding to each set choke size during flowback is calculated according to the gas well parameters and a plurality of preset different sizes of set choke sizes, as shown in Figure 6a and Figure 6b which show the comparison between the two hydraulic fracture aperture flow rates during flowback and the critical sand production flow rates before and after fracture closure, including: obtaining the hydraulic fracture height, the hydraulic fracture aperture width, the wellbore radius, the wellhead pressure, the export pressure, the fracturing fluid density, the proppant density, the local resistance coefficient, the proppant particle size, and the fracturing fluid viscosity corresponding to the gas well parameters; calculating the hydraulic fracture aperture flow rate during flowback corresponding to each set choke size according to a preset first calculation formula, wherein the first calculation formula includes:

[0211]

[0212] wherein, is the hydraulic fracture aperture flow rate during flowback, is the fracturing fluid density, is the local resistance coefficient, is the plurality of different preset choke sizes, is the wellbore radius, is a wellhead pressure, is a flowline pressure, is a hydraulic fracture height, is a hydraulic fracture aperture.

[0213] In some optional implementations of some embodiments, when the bottomhole pressure in the gas well parameter is greater than the minimum horizontal principal stress, calculating the critical sand production flow rate before fracture closure comprises: when the bottomhole pressure in the gas well parameter is greater than the minimum horizontal principal stress, calculating the Reynolds number according to a preset second calculation formula, wherein the second calculation formula comprises:

[0214]

[0215] wherein the Re is a Reynolds number, is a fracturing fluid density, is a hydraulic fracture aperture flow rate during flowback, is a proppant size in the gas well parameter, is a fracturing fluid viscosity in the gas well parameter; calculating the critical sand production flow rate before fracture closure according to the Reynolds number and a preset third calculation formula, wherein the third calculation formula comprises:

[0216] when , the critical sand production flow rate is:

[0217]

[0218] when , the critical sand production flow rate is:

[0219]

[0220] when , the critical sand production flow rate is:

[0221]

[0222] wherein, is a proppant size, is a fracturing fluid viscosity, is a critical sand production flow rate before fracture closure, is a gravitational acceleration, is a proppant density, is a fracturing fluid density.

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

[0224] When the critical sand production flow rate is:

[0225]

[0226] When the critical sand production flow rate is:

[0227]

[0228] When the critical sand production flow rate is:

[0229]

[0230] wherein, is the critical sand production flow rate after fracture closure, is a preset cohesion coefficient, is a preset film parameter in the gas well parameters. The preset cohesion coefficient and the preset film parameter can be parameters prepared in advance.

[0231] In some optional implementations of some embodiments, the step of calculating the second size range according to the critical liquid carrying flow rate comprises: calculating a gas-liquid surface tension according to the gas well parameters; calculating a wellbore droplet major axis length and a wellbore droplet axis ratio according to the surface tension; calculating a wellbore droplet drag coefficient according to the wellbore droplet axis ratio; calculating a wellbore critical liquid carrying flow rate according to the wellbore droplet major axis length and the wellbore droplet drag coefficient; calculating a wellbore flowback flow rate according to a predetermined shale gas adiabatic index and shale gas relative density; calculating a critical liquid carrying flow rate according to the wellbore critical liquid carrying flow rate; and determining an oil choke size range corresponding to the wellbore flowback flow rate greater than the critical liquid carrying flow rate as the second size range.

[0232] In some optional implementations of some embodiments, the step of calculating a gas-liquid surface tension according to the gas well parameters comprises:

[0233] obtaining a wellbore full angle change rate, a wellbore pressure, a wellbore temperature, a wellbore radius, a shale gas viscosity, a shale gas relative density, a shale gas density, a shale gas deviation coefficient, a flowback fracturing fluid salinity, a produced fluid volume, a wellhead pressure, a transportation pressure, a fracturing fluid density, a shale gas adiabatic index, and a 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, wherein the fifth calculation formula comprises:

[0235]

[0236] wherein, is a gas-liquid surface tension, is shale gas density, is wellbore temperature, is fracturing fluid return concentration.

[0237] In some optional implementations of some embodiments, the step of calculating the wellbore droplet prolate length and the wellbore droplet axis ratio according to the surface tension comprises:

[0238] calculating the wellbore droplet prolate length according to a preset sixth calculation formula, wherein the sixth calculation formula comprises:

[0239]

[0240]

[0241] wherein, is gas-liquid surface tension, is shale gas density, is fracturing fluid density, is gravitational acceleration, is wellbore droplet prolate length, is liquid production rate, is shale gas viscosity, is wellbore droplet axis ratio, is 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 comprises:

[0243] calculating the wellbore droplet drag coefficient according to a preset seventh calculation formula, wherein the seventh calculation formula comprises:

[0244]

[0245] wherein, is wellbore droplet drag coefficient, is wellbore droplet axis ratio.

[0246] In some optional implementations of some embodiments, the step of calculating the wellbore critical liquid-carrying flow rate according to the wellbore droplet prolate length and the wellbore droplet drag coefficient comprises:

[0247] calculating the wellbore critical liquid-carrying flow rate according to a preset eighth calculation formula, wherein the eighth calculation formula comprises:

[0248]

[0249] wherein, is wellbore critical liquid-carrying flow rate, is wellbore full-angle change rate.

[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 comprises:

[0251] According to a preset ninth calculation formula and the critical liquid-carrying flow rate of the wellbore, the critical liquid-carrying flow rate is calculated, as shown in the following formula: Figure 7 The ninth calculation formula comprises:

[0252]

[0253] The critical liquid-carrying flow rate (standard condition) is calculated according to the following formula: is a shale gas deviation coefficient, T is a wellbore temperature, R is a wellbore radius, P is a wellbore pressure.

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

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

[0256]

[0257] The wellbore flowback flow rate (standard condition) is calculated according to the following formula: is a shale gas adiabatic index, is a shale gas relative density, is a wellhead pressure, is a delivery pressure.

[0258] In some optional implementations of some embodiments, the step of calculating the third size range according to the final recoverable reserves comprises: predicting a plurality of final recoverable reserves of the target shale gas well under different choke sizes according to the trained numerical simulation model; screening a maximum value from the plurality of final recoverable reserves, and determining a choke size range corresponding to the maximum value as the third size range.

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

[0260] ​​In some optional implementations of some embodiments, the training step of the numerical simulation model comprises: obtaining porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, well logging interpretation results data, number of fracturing sections, number of clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary pressure curve data, stress sensitivity experiment data, pressure and production performance data; establishing a static geologic model of the target shale gas well using facies modeling and attribute modeling according to the porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, well logging interpretation results data; discretizing the static geologic model and constructing an initial numerical simulation model according to the number of fracturing sections, fracture length, relative permeability data, capillary pressure curve data, stress sensitivity experiment data (see Figure 8 ) ; simulating the fracturing fluid injection process in the initial numerical simulation model according to the fracturing fluid injection volume to obtain the distribution of the formation pressure field and saturation field at the end of fracturing operation; performing history matching according to the pressure and production performance data to train the numerical simulation model to obtain the target numerical simulation model. Each of the above parameters is a commonly used parameter in the field, and will not be described in detail here. History matching can refer to data fitting according to historical data to train the target numerical simulation model. The initial numerical simulation model and the target numerical simulation model can respectively refer to the calculation models before / after training for predicting the final recoverable reserve data according to the above parameters.

[0261] Step 203, determining the 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 above execution subject can 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] 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, then the first intersection and the second intersection are determined as the optimal size range.

[0264] 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] Third step, if the second size range, the third size range and the fourth size range have no intersection, the second size range, the third size range and the fifth size range also have no intersection, then the third size range, the fourth size range and the fifth size range are combined to make a second judgment;

[0266] 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, then the third intersection and the fourth intersection are determined as the optimal size range.

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

[0268] In addition, it should be noted that the first size range is relatively large, and under normal circumstances, it will have an intersection with the third size range. In special cases, the fourth size range before flowback may have no intersection with the third size range, or the fourth size range before flowback may have no intersection with the second size range and the third size range, in which case the fourth size range is selected to determine the oil nozzle range before flowback.

[0269] The beneficial effects of one of the implementation manners of the above embodiments of the present disclosure at least include: obtaining the gas well parameters of the target shale gas well, and calculating the critical sand 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; calculating the first size range, the second size range and the third size range of the flowback oil nozzle according to the critical sand flow rate, the critical liquid carrying flow rate and the ultimate recoverable reserves respectively, wherein the first size range includes the fourth size range before fracture closure and the fifth size range after 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, which can determine the size range of the flowback oil nozzle without the need for field experience, greatly improving the success rate and work efficiency.

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

[0271] Taking a shale gas well Y10 well in A area as an example, the post-fracturing flowback oil nozzle system optimization design is carried out.

[0272] Step one: collecting the shale gas reservoir parameters, fracture parameters, wellbore parameters, fluid parameters and proppant parameters of Y10 well. Including, the minimum horizontal principal stress is 65 MPa, the hydraulic fracture height is 40 m, the hydraulic fracture aperture width is 0.003 m, the wellbore radius 0.031 m, wellhead pressure 45 ~ 25 MPa, bottom hole pressure 75 ~ 55 MPa, export pressure 0.1 MPa, fracturing fluid density 1020 kg / m 3 , fracturing fluid viscosity 0.008 ~ 0.002 Pa·s, proppant density 2780 kg / m 3 , proppant particle size 0.0004 m.

[0273] Step two: according to the foregoing method, when the bottom hole pressure is greater than the minimum horizontal principal stress , the hydraulic fracture mouth flow rate during flowback is less than the critical sand production flow rate before fracture closure , the corresponding choke size range is stored as the suitable choke size range for preventing proppant flowback before fracture closure, and the suitable choke size range for preventing proppant flowback before fracture closure of the Y10 well is 2 ~ 3 mm (the fourth size range). When the bottom hole pressure is less than the minimum horizontal principal stress , the hydraulic fracture mouth flow rate during flowback is less than the critical sand production flow rate after fracture closure , the corresponding choke size range is stored as the suitable choke size range for preventing proppant flowback after fracture closure, and the suitable choke size range for preventing proppant flowback after fracture closure of the Y10 well is 2 ~ 12 mm (the fifth size range).

[0274] Step three: collect the shale gas wellbore parameters and fluid parameters of the Y10 well. Including, the wellbore full angle change rate 0.001 ~ 5.8° / 30 m, wellbore pressure 15 ~ 27 MPa, wellbore temperature 296 ~ 349 K, shale gas viscosity 0.02 × 10 -3 ~ 0.03 × 10 -3 Pa·s, shale gas relative density 0.68, shale gas density 169 ~ 217 kg / m 3 , shale gas deviation factor 0.75 ~ 0.9, flowback fracturing fluid salinity 45140 ppm, liquid production 15 m3 / d.

[0275] Step 4: Calculate the wellbore flow rate according to the above method: Greater than critical liquid carrying capacity The corresponding nozzle size range is used as the appropriate nozzle size range for effective wellbore liquid carrying and is stored in U2 (second size range). For well Y10, where the wellbore flowback rate exceeds the critical liquid carrying rate, the appropriate nozzle size range is 5-12 mm (second size range).

[0276] Step 5: Collect shale gas reservoir parameters, well parameters, fracture parameters, fluid parameters, and production performance parameters for Well Y10. These include original formation pressure, seismic data, geological stratification data, wellhead data, wellbore trajectory data, logging interpretation data, number of fracture stages and clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary force curve data, stress sensitivity test data, and pressure and production performance 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. Then, build a numerical simulation model for Well Y10 based on the number of fracturing stages and clusters, fracture length, relative permeability data, capillary force curve data, and stress sensitivity experimental data. Figure 8 shown.

[0279] Step 8: Based on the injection volume of the fracturing fluid, the fracturing fluid injection process 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 operation.

[0280] Step 9: Perform history fitting of Well Y10 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 application.

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

[0282]

[0283] Table 1 EUR simulation of well Y10

[0284] Step eleven: the intersection of the choke size ranges U1, U2, U3 of well Y10 is taken as the optimal choke system for post-fracturing flowback of the shale gas well, and is stored as U4, which is the choke system that can simultaneously meet the requirements of preventing proppant flowback, effectively carrying liquid in the wellbore, and EUR. The choke size range U1 of well Y10 is: the suitable choke size range for preventing proppant flowback before fracture closure is 2-3 mm, and the suitable choke size range for preventing proppant flowback after fracture closure is 2-12 mm. The choke size range U2 of well Y10 is: the suitable choke size range for the wellbore flowback flow to be greater than the critical liquid-carrying flow is 5-12 mm. The choke size range U3 of well Y10 is: the choke size range corresponding to the maximum value of EUR is 5-6 mm. Taking the intersection of the choke ranges U1, U2, U3 as the optimal choke system for post-fracturing flowback of well Y10, U4 is: the optimal choke size range before fracture closure is 2-3 mm, and the optimal choke size range after fracture closure is 5-6 mm.

[0285] Example three

[0286] With reference to Figure 3 , a flowchart 300 of example three of a method for determining a post-fracturing flowback choke size of a shale gas well according to the present disclosure is shown, which can be performed by the computing device 101 in Figure 1 . The method for determining a post-fracturing flowback choke size of a shale gas well includes:

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

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

[0289] Step 303, 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 corresponding to each set choke size before fracture closure. The choke size range corresponding to the hydraulic fracture aperture flow rate during flowback being less than the critical sand production flow rate before fracture closure is taken as the fourth size range.

[0290] Step 304, when the bottom hole pressure is less than the minimum horizontal principal stress, calculating the critical sand production flow rate under different Reynolds numbers corresponding to each set choke size after fracture closure. The choke size range corresponding to the hydraulic fracture aperture flow rate during flowback being less than the critical sand production flow rate after 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 wellbore droplet major axis length 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, calculating the wellbore critical liquid-carrying flow rate according to the wellbore droplet major axis length and the wellbore droplet drag coefficient.

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

[0296] Step 310, calculating the critical liquid-carrying flow rate according to the wellbore critical liquid-carrying flow rate.

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

[0298] Step 312, predicting a plurality of ultimate recoverable reserves of the target shale gas well under different choke radii according to the trained numerical simulation model.

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

[0300] Step 314, determining the 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 resulting technical effects can refer to those steps in Figure 2 Embodiment Two, which will not be described here.

[0302] All the optional technical solutions described above can be combined to form optional embodiments of the present application, which will not be described one by one here.

[0303] Embodiment Four:

[0304] The following is an embodiment of the system 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 reference Figure 4 , as an implementation of the above method, the present disclosure provides an embodiment of a shale gas well post-frac flowback choke size determination system. The system embodiment corresponds to Figure 2 Embodiment Two described above.

[0306] As shown in Figure 4 The shale gas well post-fracturing flowback nozzle size determination system 400 of the embodiment comprises:

[0307] An acquisition module 401 is configured to acquire gas well parameters of a target shale gas well, and calculate a critical sand production flow rate of proppants, a critical liquid carrying flow rate of a wellbore, and a final recoverable reserve of the shale gas well according to the gas well parameters.

[0308] A calculation module 402 is configured to calculate a first size range, a second size range, and a third size range of a flowback nozzle according to the critical sand production flow rate, the critical liquid carrying flow rate, and the final recoverable reserve, respectively, wherein the first size range comprises a fourth size range before fracture closure and a fifth size range after fracture closure.

[0309] A 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 alternative implementations of some embodiments, the calculation step of calculating the first size range according to the critical sand production flow rate comprises:

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

[0312] when the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, calculating a critical sand production flow rate corresponding to each set nozzle size before fracture closure, and taking a nozzle size range corresponding to a hydraulic fracture aperture flow rate less than the critical sand production flow rate before fracture closure as the fourth size range during flowback;

[0313] when the bottom hole pressure is less than the minimum horizontal principal stress, calculating a critical sand production flow rate corresponding to each set nozzle size under different Reynolds numbers after fracture closure, and taking a nozzle size range corresponding to a hydraulic fracture aperture flow rate less than the critical sand production flow rate after fracture closure as the fifth size range during flowback.

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

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

[0316] calculating the hydraulic fracture tip flow rate at the flowback time corresponding to each of the preset nozzle sizes according to a preset first calculation formula, wherein the first calculation formula comprises:

[0317]

[0318] wherein, is the hydraulic fracture tip flow rate at the flowback time, is the fracturing fluid density, is the local resistance coefficient, is the preset plurality of different nozzle sizes, is the wellbore radius, is the wellhead pressure, is the export pressure, is the hydraulic fracture height, is the hydraulic fracture tip width.

[0319] In some optional implementations of some embodiments, when the bottom hole pressure in the gas well parameter is greater than the minimum horizontal principal stress, the critical sand production flow rate before the fracture closure is calculated, comprising:

[0320] 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 comprises:

[0321]

[0322] wherein, the Re is the Reynolds number, is the fracturing fluid density, is the hydraulic fracture tip flow rate at the flowback time, is the proppant particle size in the gas well parameter, is the fracturing fluid viscosity in the gas well parameter;

[0323] the critical sand production flow rate before the fracture closure is calculated according to the Reynolds number and a preset third calculation formula, the third calculation formula comprising:

[0324] when , the critical sand production flow rate is:

[0325]

[0326] when , the critical sand production flow rate is:

[0327]

[0328] when , the critical sand production flow rate is:

[0329]

[0330] wherein, is the proppant size, is the fracturing fluid viscosity, is the critical sand production flow rate before fracture closure, is the gravitational acceleration, is the proppant density, is the fracturing fluid density.

[0331] In some alternative implementations of some embodiments, when the bottomhole pressure in the gas well parameters is less than the minimum horizontal principal stress, calculating the critical sand production flow rate after fracture closure comprises: calculating the critical sand production flow rate after fracture closure according to the Reynolds number and a preset fourth calculation formula, wherein the fourth calculation formula comprises:

[0332] when , the critical sand production flow rate is:

[0333]

[0334] when , the critical sand production flow rate is:

[0335]

[0336] when , the critical sand production flow rate is:

[0337]

[0338] wherein, is the critical sand production flow rate after fracture closure, is a preset cohesion coefficient, is a preset film parameter.

[0339] In some alternative implementations of some embodiments, the step of calculating the second size range according to the critical liquid carrying flow rate comprises: calculating the gas-liquid surface tension according to the gas well parameters; calculating the wellbore droplet major axis length and the wellbore droplet axis ratio according to the surface tension; calculating the wellbore droplet drag coefficient according to the wellbore droplet axis ratio; calculating the wellbore critical liquid carrying flow rate according to the wellbore droplet major axis length and the wellbore droplet drag coefficient; calculating the wellbore flowback flow rate according to a predetermined shale gas adiabatic index and shale gas relative density; calculating the critical liquid carrying flow rate according to the wellbore critical liquid carrying flow rate; determining the choke size range corresponding to the wellbore flowback flow rate greater than the critical liquid carrying flow rate as the second size range.

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

[0341] acquire 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 factor, flowback fracturing fluid salinity, liquid production, wellhead pressure, external transport pressure, fracturing fluid density, shale gas adiabatic index, shale gas deviation factor corresponding to the critical liquid carrying flow rate;

[0342] calculate the gas-liquid surface tension according to a preset fifth calculation formula, wherein the fifth calculation formula comprises:

[0343]

[0344] wherein, is the gas-liquid surface tension, is the shale gas density, is the wellbore temperature, is the flowback fracturing fluid salinity.

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

[0346] calculate the wellbore droplet major axis length according to a preset sixth calculation formula, wherein the sixth calculation formula comprises:

[0347]

[0348]

[0349] wherein, is the gas-liquid surface tension, is the shale gas density, is the fracturing fluid density, is the gravitational acceleration, is the wellbore droplet major axis length, is the liquid production, is the shale gas viscosity, is the wellbore droplet axis ratio, 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 comprises:

[0351] calculate the wellbore droplet drag coefficient according to a preset seventh calculation formula, wherein the seventh calculation formula comprises:

[0352]

[0353] wherein, is the wellbore droplet drag coefficient, is the wellbore droplet axis ratio.

[0354] In some alternative implementations of some embodiments, the step of calculating the critical liquid-carrying flow rate of the wellbore according to the wellbore droplet major axis length and the wellbore droplet drag coefficient comprises:

[0355] calculating the critical liquid-carrying flow rate of the wellbore according to a preset eighth calculation formula, wherein the eighth calculation formula comprises:

[0356]

[0357] wherein, is the critical liquid-carrying flow rate of the wellbore, is the full angle change rate of the wellbore.

[0358] In some alternative 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 comprises:

[0359] calculating the critical liquid-carrying flow rate according to a preset ninth calculation formula and the critical liquid-carrying flow rate of the wellbore, wherein the ninth calculation formula comprises:

[0360]

[0361] wherein, the is the critical liquid-carrying flow rate (standard condition), is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, P is the wellbore pressure.

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

[0363] calculating the wellbore flowback flow rate according to the predetermined shale gas adiabatic index and the shale gas relative density, and a preset tenth calculation formula, wherein the tenth calculation formula comprises:

[0364]

[0365] wherein, is the wellbore flowback flow rate (standard condition), is the shale gas adiabatic index, is the shale gas relative density, is the wellhead pressure, is the export pressure.

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

[0367] predicting a plurality of ultimate recoverable reserves of the target shale gas well under different choke radii according to the trained numerical simulation model;

[0368] selecting a maximum value from the plurality of ultimate recoverable reserves, and determining a choke size range corresponding to the maximum value as the third size range.

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

[0370] obtaining porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, well logging interpretation results data, number of fracturing sections, number of fracturing clusters, fracturing fluid injection volume, fracture length, relative permeability data, capillary pressure curve data, stress sensitivity experiment data, pressure and production performance data.

[0371] establishing a static geologic model of the target shale gas well by using facies modeling and attribute modeling according to the porosity, permeability, saturation, initial formation pressure, seismic data, geologic layering data, wellhead data, well trajectory data, and well logging interpretation results data.

[0372] discretizing the static geologic model, and constructing an initial numerical simulation model according to the number of fracturing sections, number of fracturing clusters, fracture length, relative permeability data, capillary pressure curve data, and stress sensitivity experiment data.

[0373] simulating the injection process of the fracturing fluid in the initial numerical simulation model according to the fracturing fluid injection volume, to obtain the distribution of the formation pressure field and saturation field at the end of the fracturing operation.

[0374] performing history matching according to the pressure and production performance data, and training the numerical simulation model to obtain the target numerical simulation model.

[0375] In some alternative 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 comprises:

[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, then determining the first intersection and the second intersection as the optimal size range.

[0377] In some alternative 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 comprises:

[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 based on 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, then the judgment is repeated by combining the third size range, the fourth size range, and the fifth size range.

[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 based on 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 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 repeated here.

[0385] Embodiment 5:

[0386] like Figure 5 As shown, 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 programs stored in a read-only memory (ROM) 502 or programs loaded from a storage device 508 into a random access memory (RAM) 503. RAM 503 also stores various programs and data required for the operation of electronic device 500. Processing device 501, ROM 502, and RAM 503 are interconnected via a bus 504. An input / output (I / O) interface 505 is also connected to bus 504.

[0387] In general, the following devices can be connected to the I / O interface 505: input devices 506 including, for example, a touch screen, a touch pad, a keyboard, a mouse, a camera, a microphone, an accelerometer, a gyroscope, and the like; output devices 507 including, for example, a liquid crystal display (LCD), a speaker, a vibrator, and the like; storage devices 508 including, for example, a magnetic tape, a hard disk, and the like; and communication devices 509. The communication devices 509 can allow the electronic device 500 to communicate wirelessly or wired with other devices to exchange data. Although Figure 5 The electronic device 500 is shown with various devices, but it is understood that all of the shown devices are not required to be implemented or present. More or less devices can alternatively be implemented or present. Figure 5 Each block shown in the flowcharts can represent a device or multiple devices as needed.

[0388] In particular, according to the present embodiment, the processes described above with reference to the flowcharts can be implemented as a computer software program. For example, the present embodiment includes a computer program product comprising a computer program or instructions carried on a computer readable medium, the computer program or instructions containing program code for executing the methods shown in the flowcharts. In the present embodiment, the computer program can be downloaded and installed from a network through the communication devices 509, or installed from the storage devices 508, or installed from the ROM 502. When the computer program is executed by the processing devices 501, the processes Figure 2 corresponding ones of the steps.

[0389] It should be noted that the computer readable medium in the embodiments disclosed above can be a computer readable signal medium or a computer readable storage medium or any combination of the two. The computer readable storage medium may, for example, but is not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, device or apparatus, or any combination of the above. More specific examples of the computer readable storage medium can include, but are not limited to, an electrical connection having one or more wires, a portable computer diskette, 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 disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the above. In the embodiments disclosed above, the computer readable storage medium can be any tangible medium that contains or stores a program that can be used by or in connection with an instruction execution system, apparatus or device. In the embodiments disclosed above, the computer readable signal medium can include a data signal carried in a baseband or as a part of a carrier wave, which carries computer readable program code. Such a propagated data signal can take on many forms, including but not limited to an electromagnetic signal, an optical signal or any suitable combination of the above. The computer readable signal medium can also be any computer readable medium that can send, propagate or transmit the program for use by or in connection with an instruction execution system, apparatus or device. The program code contained in the computer readable medium can be transmitted by any suitable medium, including but not limited to a wire, cable, optical fiber, RF (radio frequency), or any suitable combination of the above.

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

[0391] The computer readable medium described above can be included in the apparatus described above; or can exist separately therefrom, and can not be incorporated in the electronic device. The computer readable medium described above can carry one or more programs that, when executed by the electronic device, cause the electronic device to perform any one or more of the steps described above. Figure 2 The corresponding steps.

[0392] Computer program code for carrying out operations of the embodiments can be written in any combination of one or more programming languages, including an object oriented programming language such as Java, Smalltalk, C++ or the like and conventional procedural programming languages, such as the "C" programming language or similar programming languages. The program code can execute entirely on the user's computer, partly on the user's computer, as a stand-alone software package, partly on the user's computer and partly on a remote computer or entirely on the remote computer or server. In the latter scenario, 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 the connection can be made to an external computer (for example, through the Internet using an Internet Service Provider).

[0393] The flow diagrams and the block diagrams in the drawings are illustrations of architectures, functionalities, and operations of possible implementations of systems, methods, and computer program products according to various embodiments of the present disclosure. In this regard, each block in the flow diagrams or block diagrams can represent a module, a segment, or a portion of code, which comprises one or more executable instructions for implementing the specified logical function(s). It should also be noted that in some alternative implementations, the functions noted in the blocks can occur out of the order noted in the figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently or the blocks may

[0394] The modules described in the embodiments can be implemented through software and / or hardware. The modules described can be stored in processor, for example, and can be described as being:

[0395] An obtaining module, a calculating module, and a determining module. For example, the obtaining module can also be described as a "module for obtaining a gas well parameter of a target shale gas well".

[0396] The functions described above in the detailed description can be performed by one or more hardware logic components. For example, and without limitation, illustrative types of hardware logic components that can be used include Field-programmable Gate Arrays (FPGAs), Program-specific Integrated Circuits (ASICs), Program-specific Standard Products (ASSPs), System-on-a-chip systems (SOCs), Complex Programmable Logic Devices (CPLDs), etc.

[0397] The above description is merely exemplary of some preferred embodiments of the present disclosure and of the principles thereof. It is to be understood that the present disclosure is not limited to the specific technical features described above, and that the scope of the present disclosure is not limited to the technical solutions formed by the specific combinations of the above technical features, but also covers other technical solutions formed by the combinations of the above technical features or equivalent features thereof without departing from the above inventive concept. For example, the above technical features are replaced with the technical features with similar functions disclosed in the embodiments of the present disclosure (but not limited to) to form technical solutions.

Claims

1. A method for determining the size of a shale gas well flowback nozzle after pressure reduction, characterized in that: include: 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 based on the gas well parameters; 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 ultimate recoverable reserves, respectively, wherein the first size range includes a fourth size range before fracture closure and a fifth size range after fracture closure; determining an optimal size range based on the second size range, the third size range, the fourth size range, and the fifth size range; The calculation step of calculating the first size range according to the critical sand production flow rate includes: calculating the hydraulic fracture opening flow rate corresponding to each set nozzle size during flowback according to the gas well parameters and a plurality of preset set nozzle sizes of different sizes; 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 the fracture closure corresponding to each set nozzle size; taking the nozzle size range corresponding to the hydraulic fracture opening flow rate during flowback being less than the critical sand production flow rate before the fracture closure as the fourth size range; when the bottom hole pressure is less than the minimum horizontal principal stress, calculating the critical sand production flow rate under different Reynolds numbers after the fracture closure corresponding to each set nozzle size, and taking the nozzle size range corresponding to the hydraulic fracture opening flow rate during flowback being less than the critical sand production flow rate after the fracture closure as the fifth size range; The step of calculating the second size range based on the critical liquid carrying flow rate includes: calculating gas-liquid surface tension based on the gas well parameters; calculating the wellbore liquid droplet major axis length and the wellbore liquid droplet axial ratio based on the surface tension; calculating the wellbore liquid droplet drag coefficient based on the wellbore liquid droplet axial ratio; calculating the wellbore critical liquid carrying flow rate based on the wellbore liquid droplet major axis length and the wellbore liquid droplet drag coefficient; calculating the wellbore flowback 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 flowback flow rate being greater than the critical liquid carrying flow rate as the second size range; The calculation steps for calculating the third size range based on the final recoverable reserves include: predicting multiple final recoverable reserves of the target shale gas well under different nozzle radius conditions based on the 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.

2. The method according to claim 1, characterized in that 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, including: Obtaining the hydraulic fracture height, hydraulic fracture width, wellbore radius, wellhead pressure, external pressure, fracturing fluid density, proppant density, local resistance coefficient, proppant particle size, and fracturing fluid viscosity corresponding to the gas well parameters; The hydraulic fracture orifice 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: in, is the flow velocity at the hydraulic fracture opening during flowback, is the fracturing fluid density, is the local resistance coefficient, For multiple preset nozzle sizes, is the wellbore radius, is the wellhead pressure, is the output pressure, is the hydraulic fracture height, is the width of the hydraulic fracture.

3. The method according to claim 2, characterized in that When the bottom hole pressure in the gas well parameters is greater than the minimum horizontal principal stress, the critical sand production velocity before the fracture closes is calculated, including: When the bottom hole pressure in the gas well parameters 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: Wherein, Re is the Reynolds number, is the fracturing fluid density, is the flow velocity at the hydraulic fracture opening during flowback, is the proppant particle size in the gas well parameters, is the fracturing fluid viscosity in the gas well parameters; The critical sand production velocity before the crack is closed is calculated according to the Reynolds number and a preset third calculation formula, wherein the third calculation formula includes: when When , the critical sand flow rate is: when When , the critical sand flow rate is: when When , the critical sand flow rate is: in, is the proppant particle size, is the fracturing fluid viscosity, is the critical sand production velocity before the fracture closes, is the acceleration due to gravity, is the proppant density, is the density of the fracturing fluid.

4. The method according to claim 3, characterized in that When the bottom hole pressure in the gas well parameters is less than the minimum horizontal principal stress, the critical sand production velocity after the fracture is closed is calculated, including: The critical sand production velocity after the crack is closed is calculated according to the Reynolds number and a preset fourth calculation formula, wherein the fourth calculation formula includes: when When , the critical sand flow rate is: when When , the critical sand flow rate is: when When , the critical sand flow rate is: in, is the critical sand production velocity after the fracture is closed, is the preset adhesion coefficient, are the preset film parameters.

5. The method according to claim 1, wherein 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: in, is the gas-liquid surface tension, is the density of shale gas, is the wellbore temperature, is the salinity of the flowback fracturing fluid.

6. The method according to claim 5, characterized in that The steps of calculating the long axis length 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: in, is the gas-liquid surface tension, is the shale gas density, is the fracturing fluid density, is the acceleration due to gravity, is the long axis length of the wellbore droplet, is the liquid production, is the shale gas viscosity, is the wellbore droplet axis ratio, is the wellbore radius.

7. The method according to claim 6, 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: in, is the wellbore droplet drag coefficient, is the wellbore droplet axis ratio.

8. The method according to claim 7, 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: in, is the critical liquid-carrying velocity in the wellbore, is the full angle change rate of the wellbore.

9. The method according to claim 8, 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 a preset ninth calculation formula and the critical liquid carrying flow rate of the wellbore, wherein the ninth calculation formula includes: Among them, the is the critical liquid carrying flow rate (standard condition), is the shale gas deviation coefficient, T is the wellbore temperature, R is the wellbore radius, P is the wellbore pressure.

10. The method according to claim 5, characterized in that The calculation of 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 based on the predetermined shale gas adiabatic index and shale gas relative density and a preset tenth calculation formula, wherein the tenth calculation formula includes: in, is the wellbore flowback flow (standard condition), is the shale gas adiabatic index, is the relative density of shale gas, is the wellhead pressure, The external output pressure.

11. The method according to claim 1, characterized in that The training steps of the numerical simulation model include: Obtaining the gas well parameters including 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 test data, and pressure and production dynamic data; 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 well logging interpretation results data; Discretizing the static geological model, and constructing an initial numerical simulation model based on the number of fracturing stages 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 operation; 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.

12. The method according to claim 1, characterized in that Determining an optimal size range based on 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.

13. The method according to claim 12, 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.

14. The method according to claim 13, 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, then the judgment is repeated by combining the third size range, the fourth size range, and the fifth size range. 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.

15. The method according to claim 14, 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.

16. A shale gas well post-pressure return oil nozzle size determination system, characterized in that: include: An acquisition module is used to obtain 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 based on the gas well parameters; a calculation module, configured to calculate 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 rate, and the ultimate recoverable reserves, wherein the first size range includes a fourth size range before fracture closure and a fifth size range after fracture closure; a determination module, configured to determine an optimal size range based on the second size range, the third size range, the fourth size range, and the fifth size range; The calculation step of calculating the first size range according to the critical sand production flow rate includes: calculating the hydraulic fracture opening flow rate corresponding to each set nozzle size during flowback according to the gas well parameters and a plurality of preset set nozzle sizes of different sizes; 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 the fracture closure corresponding to each set nozzle size; taking the nozzle size range corresponding to the hydraulic fracture opening flow rate during flowback being less than the critical sand production flow rate before the fracture closure as the fourth size range; when the bottom hole pressure is less than the minimum horizontal principal stress, calculating the critical sand production flow rate under different Reynolds numbers after the fracture closure corresponding to each set nozzle size, and taking the nozzle size range corresponding to the hydraulic fracture opening flow rate during flowback being less than the critical sand production flow rate after the fracture closure as the fifth size range; The step of calculating the second size range based on the critical liquid carrying flow rate includes: calculating gas-liquid surface tension based on the gas well parameters; calculating the wellbore liquid droplet major axis length and the wellbore liquid droplet axial ratio based on the surface tension; calculating the wellbore liquid droplet drag coefficient based on the wellbore liquid droplet axial ratio; calculating the wellbore critical liquid carrying flow rate based on the wellbore liquid droplet major axis length and the wellbore liquid droplet drag coefficient; calculating the wellbore flowback 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 flowback flow rate being greater than the critical liquid carrying flow rate as the second size range; The calculation steps for calculating the third size range based on the final recoverable reserves include: predicting multiple final recoverable reserves of the target shale gas well under different nozzle radius conditions based on the 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.

17. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the computer program, the steps of the method according to any one of claims 1 to 15 are implemented.

18. 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 15 are implemented.

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