A method for optimizing the oil return nozzle after deep coal-rock gas pressure considering the influence of multiple factors

Abstract

The present invention discloses a method for optimizing the flowback nozzle after deep coal-rock gas is compressed and takes into account the influence of multiple factors, and belongs to the technical field of coal-rock gas exploitation. Aiming at the problem of controlling the flow rate of the flowback fluid in the development of deep coal-rock gas, the method establishes a model of seepage in the matrix and fractures and a two-phase flow model in the wellbore, comprehensively considers the influence of coal powder, proppant migration and coal seam cleat fractures, optimizes the size of the wellhead nozzle, reduces the probability of coal powder blocking the fractures, and improves the conductivity of the fractures. The key points of the technical solution include establishing a multi-stage and multi-cluster fracturing-flowback model, a nozzle wellbore flow model, a critical flow model of proppant and coal powder in the fractures, and optimizing the nozzle size range according to the reservoir IPR curve to adapt to the change of formation pressure. Compared with traditional methods, the present invention has significant advantages in improving the efficiency of fracturing transformation and efficient exploitation of coal-rock gas, and provides an innovative solution for the scientific research and engineering application of deep coal-rock gas.

Description

Technical Field

[0001] The invention belongs to the technical field of unconventional natural gas development, and relates to a deep coal rock gas pressure backflow nozzle control method taking into account the influence of coal powder, proppant migration and coal seam cleat cracks. Background Art

[0002] With the continuous deepening of coalbed methane exploration and exploitation in my country, deep coal-rock gas development has become a strategic successor resource for increasing China's natural gas reserves and production; so how to efficiently and reasonably exploit coal-rock gas is a new challenge we face; under the action of high pressure and temperature, the adsorption capacity of coal rocks in my country's deep coal-rock gas reservoirs reaches its limit, forming a supersaturated deep coal-bed methane reservoir with "high gas content, high saturation, and free gas". Affected by its reservoir characteristics, hydraulic fracturing technology has been widely used in the development of coal-rock gas. After the fracturing construction of the coal seam, the fracturing fluid must be returned in time to reduce the residence time of the fracturing fluid in the reservoir and reduce the damage of the fracturing fluid to the coal seam. In addition, due to the fragility of the coal seam itself, coal powder is easily generated in the coal rock reservoir and mining process, which will block the flow channel in the fracture, reduce the fracture conductivity, and greatly affect the production capacity of coal rock gas. Therefore, it is considered that in the process of coal rock gas return, the flow rate of the return fluid is controlled to prevent the coal powder in the reservoir matrix from flowing, discharge the coal powder in the fracture, and improve the fracture conductivity, which is the key to the efficient exploitation of deep coal rock gas at present. In terms of mechanism, many studies have been carried out at home and abroad on the mechanism of coal powder output and damage to the reservoir, two-phase flow, post-fracturing fracturing fluid return and proppant return. However, a systematic model of coupling nozzle, wellbore, reservoir, proppant and coal powder migration has not been established, and a coupled integrated drainage optimization system has not been given. In engineering, the return rate of the liquid after fracturing is mainly controlled by empirically adjusting the nozzle size, thereby controlling the settlement and laying state of the proppant.

[0003] Domestic and foreign scholars have conducted some research on the control of the nozzle during the post-fracturing flowback process. At present, the optimization of the nozzle after fracturing has been carried out mainly for shale gas, conventional reservoirs and shallow coalbed methane. For coalbed methane, some scholars have established a fracturing fluid flowback model considering the characteristics of the proppant settling immediately after fracturing in coalbed methane wells and the cementation between particles, and have controlled and adjusted the nozzle with the purpose of preventing the proppant from flowing back (Zhang Zhuang. Post-fracturing flowback technology of coalbed methane wells [J]. Coalfield Geology and Exploration, 2017, 45(5): 70-74.). Some scholars have also considered the adsorption and desorption characteristics and seepage mechanism of coalbed methane, and found that coalbed methane wells that are too quickly discharged, well washing and repair, well closure, and liquid level below the top of the coal seam are prone to cause pollution, resulting in a sharp drop in gas and water production. Based on the damage characteristics and damage mechanism, combined with many years of drainage experience, a drainage system based on constant pressure drainage, reasonable working pressure difference control and moderate coal powder output control has been established. This formula is only related to pore radius, pore shape, etc., but does not consider the migration of proppant and coal powder in the fracture and the flow of wellbore and nozzle, and has not established an optimization model for wellhead nozzle control (Zhang Suian, Cao Lihu, Du Caixia. Research on gas production mechanism and drainage pressure control and powder control in coalbed methane wells [J]. Journal of China Coal Society, 2014, 39(9): 1928-1931). In addition, some scholars analyzed the differences in geological conditions between Yanchuan South and Qinnan coalbed methane, and combined with the on-site drainage parameters of Yanchuan South coalbed methane wells, established a corresponding drainage system. The study divided the drainage system of deep coalbed methane reservoirs in Yanchuan South coalbed methane field into five drainage stages, namely: rapid pressure reduction stage, stable pressure reduction stage, production stage, production fluctuation stage and stable production stage. According to the bottom hole pressure drop corresponding to each stage, a refined drainage control method was constructed; however, since the bottom hole pressure drop is difficult to monitor and control, and the influence of proppant, coal powder and reservoir is not taken into account, this study still has major defects (Zhao Xinglong, Tang Dazhen, Zhang Yan. Establishment and optimization of drainage system for deep coalbed methane reservoirs in Yanchuan South Coalbed Methane Field [J]. Coal Science and Technology, 2021, 49(6): 251-257); In addition, some scholars have also considered the migration of proppant and coal powder in the fracture, constructed an artificial fracture-wellbore-nozzle flow system, studied the theory of coal powder startup and proppant reflux control, and established a mathematical model for calculating the size of the return nozzle after coalbed methane well pressure relief; however, this theory does not consider the changes in liquid phase during the return process, the influence of fracture closure and the influence of the real reservoir (Zhao Qihong. Research on the method of determining the size of the return nozzle after coalbed methane well pressure relief [D]. Chengdu: Southwest Petroleum University, 2017).

[0004] Analysis of past studies shows that most optimizations for post-fracturing flowback consider controlling the bottom hole pressure drop, but monitoring and controlling the bottom hole pressure drop is a difficult process and is difficult to implement; while most studies on nozzle control consider a single influencing factor or the factors considered are not comprehensive enough; in general, the current research lacks an overall system construction, which makes it difficult to promote the current wellhead nozzle optimization method; since a complete set of post-fracturing wellhead nozzle size optimization methods that fully consider proppant, coal powder migration, multiphase flow and reservoir changes has not yet been established for deep coal gas, it is necessary to build a new optimization system and method; in order to achieve this goal, we have established a deep coal-bearing tight gas matrix and fracture seepage model and a two-phase steady-state flow model in the wellbore based on seepage mechanics, elastic mechanics, fluid mechanics, dual-porosity media model, etc. Figure 1 ); Considering the change of formation pressure after fracturing, which makes the proppant stress difference, a proppant stress model and a minimum critical velocity model for proppant activation of fracturing fluid return are established respectively, and a critical velocity model for coal powder activation in the fracture is established at the same time; thus, a complete optimization method for deep coal-bearing tight gas pressure return oil nozzle is constructed. Summary of the invention

[0005] The present invention proposes a new wellhead nozzle optimization method for controlling the nozzle during the backflow process after deep coal-rock gas fracturing. The method is based on seepage mechanics, elastic mechanics, fluid mechanics, and dual-porosity medium models. It takes into account the seepage in the matrix and fractures, the two-phase steady-state flow in the wellbore, the proppant after hydraulic fracturing, and the difference in the force of coal powder. The corresponding mathematical models are established respectively, and finally a new method for optimizing the size of the backflow nozzle after deep coal-rock gas pressure is constructed. Through this method, the relationship between the wellhead nozzle and the wellhead pressure of the corresponding fracturing well during the backflow process can be obtained according to the input basic construction and reservoir parameters. This method combines all the physical properties of deep coal-rock gas, is an important innovation in studying the backflow control theory after deep coal-rock gas pressure, and can serve as a good reference for scientific research and engineering applications.

[0006] The technical solution provided by the present invention to solve the above technical problems is: a method for optimizing the deep coal-rock gas pressure backflow nozzle considering the influence of multiple factors, comprising the following steps:

[0007] (1) Based on the dual-porosity medium model, a multi-stage and multi-cluster fracturing-flowback model was established to continuously simulate the injection and production processes. The physical behavior of the two-phase flow during fracturing and flowback was characterized by adjusting the fracturing fluid rate during the injection and production processes.

[0008] (2) Establish a flow model of the nozzle and wellbore system, and use the material balance principle to establish the pressure transfer relationship between the two and the fracturing-flowback model;

[0009] (3) Establish a critical flow model of proppant and coal powder in fractures;

[0010] (4) determining the range of nozzle sizes under a certain formation pressure by using the relationship between the nozzle critical flow rate and nozzle size obtained in step (2), the reservoir IPR curve obtained in step (1), and the critical flow rates corresponding to proppant activation and coal powder activation in the fracture obtained in step (3);

[0011] (5) As the flowback time increases, the formation pressure decreases, the phase state changes, and the reservoir IPR curve and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture will also change. Repeat step (4) to obtain a new range of nozzle sizes after the formation pressure decreases. The corresponding wellhead pressure at this time is integrated with the optimized nozzle size to obtain a relationship map between the nozzle size and the wellhead pressure after fracturing.

[0012] A further technical solution is to establish a multi-stage multi-cluster fracturing-flowback model based on the dual-porosity medium model, continuously simulate the two processes of injection and production, and simulate the fracturing-flowback flow process by adjusting the fracturing fluid rate during injection and production. The fracturing-flowback model is shown below:

[0013]

[0014] In the formula, ▽ is the symbol of the gradient operator, dimensionless; is the partial differential symbol, dimensionless; t is time, s; φ f is the fracture porosity, dimensionless; k f is the fracture permeability, 10 -3 μm 2 ;p fg 、p fw are respectively the gas phase and water phase pressure in the fracture system, MPa; μ fg , μ fw are the viscosities of gas and water in the fracture system, mPa·s; k rgf , k rwf are the relative permeabilities of gas and water in the fracture system, dimensionless; ρ fg , fw are the densities of gas and water in the fracture system, kg / m 3 ; g is the acceleration due to gravity, g = 9.8 m / s 2 ; H is the formation depth, m; B fg , B fw are the volume coefficients of gas and water phases in the fracture system, dimensionless; S fg , S fw are the gas and water saturations in the fracture system, dimensionless; q vg ,q vw are the gas and water production per unit volume of coal reservoir, m3 / (m 3 ·s);q * gmf ,q * wmf are the gas and water exchange amounts between the fracture and matrix pore systems, m 3 / (m 3 ·s);φ m is the matrix porosity, dimensionless; S mg , S mw are the gas and water saturations in the matrix pore system, dimensionless; B mg , B mw are the volume coefficients of gas and water in the matrix pores, dimensionless; q vm is the flow rate of desorbed gas from the matrix pore surface to the matrix pore, m 3 / (m 3 ·s).

[0015] A further technical solution is that the specific process of step (2) is: establishing a flow model of the nozzle and wellbore system, and using the material balance principle to establish the pressure transfer relationship between the two and the fracturing-flowback model:

[0016] a. Nozzle gas-liquid two-phase flow model:

[0017]

[0018] In the formula, q L is the liquid flow rate, m 3 / d;d 0 is the nozzle diameter, mm; R p is the production gas-oil ratio, m 3 / m 3 ;p 1 is the pressure before the mouth, MPa;

[0019] c 1 、c 2 、c 3 is the empirical coefficient, dimensionless; d 1 d 2 Adjust the size of the front and rear oil nozzles according to the working system, mm; q L1 ,q L2 The oil well liquid production before and after the working system adjustment, m 3 / d;

[0020] b. Two-phase flow pressure calculation model in wellbore:

[0021]

[0022] ρ m =ρ g(1-H L )+ρ L H L (8)

[0023] Where d is the differential symbol and is dimensionless; ρ m is the density of gas-liquid mixture, kg / m 3 ; sin is the sine function, dimensionless; θ is the wellbore inclination angle, °; g is the gravitational acceleration, m / s 2 ; τ w is the shear stress between the mixture and the inner wall of the wellbore, MPa; S p is the wellbore wetted perimeter, m; A is the wellbore cross-sectional area, m 2 ;v m is the flow velocity of the gas-liquid two-phase mixture, m / s; ρ g is the gas phase density, kg / m 3 ρ L is the liquid density, kg / m 3 ;H L is the liquid holdup of the wellbore cross section, dimensionless.

[0024] A further technical solution is that the specific process of step (3) is to establish a critical flow model of proppant and coal powder in the fracture of deep coal gas reservoir, and the specific formula is as follows:

[0025] a. Critical flow rate of proppant:

[0026]

[0027] In the formula, v c1 is the critical velocity of the proppant, m / s; ρ c is the particle density, kg / m 3 ;d c is the particle diameter, m; ρ is the fluid density, kg / m 3 ; μ is the fluid viscosity, mPa·s; g is the acceleration due to gravity, g=9.8m / s 2 ;

[0028] b. Critical flow rate of pulverized coal:

[0029]

[0030] In the formula, v c2 is the critical velocity of coal powder, m / s; ε is the cohesion coefficient, which is 2.56 dyn / cm; p c is the pressure of the fracture wall on the proppant, MPa; p is the fluid pressure in the fracture, MPa; τ is a specific constant, dimensionless.

[0031] A further technical solution is that the specific process of step (4) is as follows: based on the model established in steps (1) to (3), the relationship between the critical flow rate of the nozzle and the nozzle size, the reservoir IPR curve (the relationship between the bottom hole pressure difference and the flow rate) and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture are obtained to determine the nozzle size range d under a certain formation pressure. c1 ~d c2 (like Figure 2 shown).

[0032] A further technical solution is that the specific process of step (5) is as follows: as the backflow time increases and the formation pressure decreases, the phase state will change, and the reservoir IPR curve and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture will also change accordingly. By repeating step (4), a new range of nozzle sizes after the formation pressure decreases can be obtained. By integrating the corresponding wellhead pressure with the optimized nozzle size, a relationship map between the nozzle size and the wellhead pressure after the well is fracturing can be obtained (such as Figure 3 shown).

[0033] The present invention is aimed at the control of the nozzle in the process of deep coal-rock gas post-fracturing flowback, and proposes a new method for optimizing the wellhead nozzle after fracturing flowback. Based on the seepage mechanics, elastic mechanics, fluid mechanics, dual-porosity medium model, etc., we established the deep coal-bearing tight gas matrix and fracture seepage model and the two-phase steady-state flow model in the wellbore; based on the force model of the proppant in the fracture, we constructed the minimum critical velocity model for the proppant to start in the process of fracturing fluid flowback, and at the same time established the critical velocity model for the coal powder to start in the fracture, and finally constructed a complete set of deep coal-bearing tight gas post-fracturing flowback nozzle optimization method. This method is superior to the traditional conventional method, and takes into account the main characteristics of the formation, fracture, wellbore and nozzle in the deep coal-rock gas post-fracturing flowback. It is an important innovation in the study of the control theory of deep coal-rock gas post-fracturing flowback, and can provide scientific and reasonable guidance for deep coal-rock gas post-fracturing flowback, which has important engineering significance for improving the efficiency of fracturing transformation. BRIEF DESCRIPTION OF THE DRAWINGS

[0034] Figure 1 It is a schematic diagram of the choke-wellbore-reservoir coupling proposed in the present invention;

[0035] Figure 2 It is the relationship between wellhead pressure, flow rate and nozzle size at a certain moment;

[0036] Figure 3 This is a diagram showing the relationship between the wellhead pressure of a deep coal-rock gas well after pressure relief and the optimal nozzle size;

[0037] Figure 4 Schematic diagram of a simulation physical model of an embodiment. DETAILED DESCRIPTION

[0038] In order to make the purpose, technical solutions and advantages of the present invention more clearly understood, the present invention is further illustrated below with reference to the accompanying drawings and embodiments.

[0039] A method for optimizing deep coal-rock gas pressure backflow nozzles considering multiple factors, comprising the following steps:

[0040] In step (1) of the present invention, it is necessary to establish a multi-stage multi-cluster fracturing-flowback model based on a dual-porosity medium model, continuously simulate the two processes of injection and production, and simulate the fracturing-flowback flow process by adjusting the fracturing fluid rate during the injection and production processes:

[0041]

[0042] In the formula, ▽ is the symbol of the gradient operator, dimensionless; is the partial differential symbol, dimensionless; t is time, s; φ f is the fracture porosity, dimensionless; k f is the fracture permeability, 10 -3 μm 2 ;p fg 、p fw are respectively the gas phase and water phase pressure in the fracture system, MPa; μ fg , μ fw are the viscosities of gas and water in the fracture system, mPa·s; k rgf , k rwf are the relative permeabilities of gas and water in the fracture system, dimensionless; ρ fg , fw are the densities of gas and water in the fracture system, kg / m 3 ; g is the acceleration due to gravity, g = 9.8 m / s 2 ; H is the formation depth, m; B fg , B fw are the volume coefficients of gas and water phases in the fracture system, dimensionless; S fg , S fw are the gas and water saturations in the fracture system, dimensionless; q vg ,q vw are the gas and water production per unit volume of coal reservoir, m 3 / (m 3 ·s);q * gmf ,q * wmf are the gas and water exchange amounts between the fracture and matrix pore systems, m 3 / (m 3 ·s);φ m is the matrix porosity, dimensionless; S mg , Smw are the gas and water saturations in the matrix pore system, dimensionless; B mg , B mw are the volume coefficients of gas and water in the matrix pores, dimensionless; q vm is the flow rate of desorbed gas from the matrix pore surface to the matrix pore, m 3 / (m 3 ·s).

[0043] In step (2) of the present invention, a flow model of the nozzle and wellbore system is established, and the pressure transmission relationship between the two and the fracturing-flowback model is established by using the material balance principle, wherein:

[0044] a. Gas-liquid two-phase flow nozzle model:

[0045]

[0046] In the formula, q L is the liquid flow rate, m 3 / d;d 0 is the nozzle diameter, mm; R p is the production gas-oil ratio, m 3 / m 3 ;p 1 is the pressure before the mouth, MPa;

[0047] c 1 、c 2 、c 3 is the empirical coefficient, dimensionless; d 1 d 2 Adjust the size of the front and rear oil nozzles according to the working system, mm; q L1 ,q L2 The oil well liquid production before and after the working system adjustment, m 3 / d;

[0048] b. Two-phase flow pressure calculation model in wellbore:

[0049]

[0050] ρ m =ρ g (1-H L )+ρ L H L (8)

[0051] Where d is the differential symbol and is dimensionless; ρ g is the gas phase density, kg / m 3 ρ L is the liquid density, kg / m 3 ρ mis the density of gas-liquid mixture, kg / m 3 ; sin is the sine function, dimensionless; θ is the wellbore inclination angle, °; g is the gravitational acceleration, m / s 2 ; τ w is the shear stress between the mixture and the inner wall of the wellbore, MPa; S p is the wellbore wetted perimeter, m; A is the wellbore cross-sectional area, m 2 ;v m is the flow velocity of the gas-liquid two-phase mixture, m; H L is the liquid holdup of the wellbore cross section, dimensionless.

[0052] In the present invention, step (3) is to establish a critical flow model of proppant and coal powder in the fracture of deep coal gas reservoir, and the specific expression is as follows:

[0053] a. Critical flow rate of proppant:

[0054]

[0055] In the formula, v c1 is the critical velocity of the proppant, m / s; ρ c is the particle density, kg / m 3 ;d c is the particle diameter, m; ρ is the fluid density, kg / m 3 ; μ is the fluid viscosity, mPa·s; g is the acceleration due to gravity, g=9.8m / s 2 ;

[0056] b. Critical flow rate of pulverized coal:

[0057]

[0058] In the formula, v c2 is the critical velocity of coal powder, m / s; ε is the cohesion coefficient, which is 2.56 dyn / cm; p c is the pressure of the fracture wall on the proppant, MPa; p is the fluid pressure in the fracture, MPa; τ is a specific constant, dimensionless.

[0059] In the present invention, step (4) is to obtain the relationship between the critical flow rate through the nozzle and the nozzle size, the reservoir IPR curve (the relationship between the bottom hole pressure difference and the flow rate) and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture based on the model established in steps (1) to (3), and determine the nozzle size range under a certain formation pressure, such as Figure 2 As shown, the nozzle range is d c1 ~d c2 .

[0060] In the present invention, step (5) takes into account that the increase in flowback time will lead to a decrease in formation pressure, which will cause phase changes, thereby affecting the reservoir IPR curve and the critical flow rate corresponding to proppant startup and coal powder startup in the fracture; repeating step (4) can obtain a new range of nozzle sizes after the formation pressure is reduced, and integrate the corresponding wellhead pressure with the optimized nozzle size, such as Figure 3 As shown, we can get the relationship between the nozzle size and the wellhead pressure after fracturing.

[0061] Example 1: This example is implemented in a deep coal-rock gas reservoir in the Ordos Basin. The Ordos Basin is rich in deep coal-rock gas. Through on-site logging and well testing, geological data of the block are obtained, and the parameters obtained are representative. The schematic diagram of the simulated physical model is as follows Figure 4 As shown, the specific simulation method steps are as follows:

[0062] 1. Geological parameters obtained through on-site logging and well testing: burial depth 2789m; pressure coefficient 0.95; thickness 10m; permeability 4md; porosity 0.08; average cluster spacing 18m; casing diameter 139.7mm; proppant density 2700kg / m 3 ; Proppant diameter 0.6mm; Fracturing fluid viscosity 10mPa·s; Water saturation 0.6; Coal powder concentration 0.02m 3 / m 3 ; Coal powder density 1400kg / m 3 .

[0063] 2. Substituting all geological parameters into the established model, i.e., formulas (1) to (10), we can obtain the relationship between the critical flow rate of the nozzle and the nozzle size, the reservoir IPR curve (the relationship between the bottom hole pressure difference and the flow rate), and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture, and determine the nozzle size range under a certain formation pressure. Repeating the above steps, we can obtain the new nozzle size range after the formation pressure is reduced. By integrating the corresponding wellhead pressure with the optimized nozzle size, we can obtain the relationship between the formation pressure, water saturation distribution, and nozzle size and wellhead pressure during the flowback process after fracturing.

[0064] The above description is not intended to impose any form of limitation on the present invention. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A method for optimizing the deep coal-rock gas pressure return oil nozzle considering the influence of multiple factors, characterized in that: The main steps are as follows: (1) Based on the dual-porosity medium model, a multi-stage multi-cluster fracturing-flowback model is established to continuously simulate the injection and production processes. The physical behavior of the gas-liquid two-phase flow during fracturing and flowback is characterized by adjusting the fracturing fluid rate during the injection and production processes. The model specifically includes the following equations: In the formula, is the symbol of the gradient operator, dimensionless; is the partial differential symbol, dimensionless; t is time, s; φ f is the fracture porosity, dimensionless; k f is the fracture permeability, 10 -3 μm 2 ;p fg 、p fw are respectively the gas phase and water phase pressure in the fracture system, MPa; μ fg , μ fw are the viscosities of gas and water in the fracture system, mPa·s; k rgf , k rwf are the relative permeabilities of gas and water in the fracture system, dimensionless; ρ fg , fw are the densities of gas and water in the fracture system, kg / m 3 ; g is the acceleration due to gravity, g = 9.8 m / s 2 ; H is the formation depth, m; B fg , B fw are the volume coefficients of gas and water phases in the fracture system, respectively, dimensionless; S fg , S fw are the gas and water saturations in the fracture system, dimensionless; q vg ,q vw are the gas and water production per unit volume of coal reservoir, m 3 / (m 3 ·s);q * gmf ,q * wmf are the gas and water exchange amounts between the fracture and matrix pore systems, m 3 / (m 3 ·s);φ m is the matrix porosity, dimensionless; S mg , S mw are the gas and water phase saturations in the matrix pore system, respectively, dimensionless; B mg , B mw are the volume coefficients of gas and water in the matrix pores, respectively, dimensionless; q vm is the flow rate of desorbed gas from the matrix pore surface to the matrix pore, m 3 / (m 3 s); (2) Establish a flow model of the nozzle and wellbore system, and use the material balance principle to establish the pressure transfer relationship between the two and the fracturing-flowback model; (3) Establish a critical flow model of proppant and coal powder in fractures; (4) determining the range of nozzle sizes under a certain formation pressure by using the reservoir IPR curve obtained in step (1), the relationship between the nozzle critical flow rate and nozzle size obtained in step (2), and the critical flow rates corresponding to proppant activation and coal powder activation in the fracture obtained in step (3); (5) As the flowback time increases, the formation pressure decreases, the phase state changes, and the reservoir IPR curve and the critical flow corresponding to the proppant start-up and the coal powder start-up in the fracture will also change. Repeat step (4) to obtain a new nozzle size range after the formation pressure decreases. The corresponding wellhead pressure at this time is integrated with the optimized nozzle size range to obtain a relationship map between the nozzle size and the wellhead pressure after fracturing.

2. A deep coal-rock gas pressure backflow nozzle optimization method considering multiple factors as claimed in claim 1, characterized in that: The pressure transmission relationship model between the flow model of the nozzle and wellbore system and the fracturing-flowback model established in step (2) specifically includes: a. Nozzle gas-liquid two-phase flow model: In the formula, q L is the liquid flow rate, m 3 / d; d0 is the nozzle diameter, mm; R p is the production gas-oil ratio, m 3 / m 3 ; p1 is the pressure before the nozzle, MPa; c1, c2, c3 are empirical coefficients, dimensionless; d1, d2 are the dimensions of the nozzle before and after the working system is adjusted, mm; q L1 ,q L2 The oil well liquid production before and after the working system adjustment, m 3 / d; b. Calculation model of gas-liquid two-phase flow pressure in the wellbore: r m =ρ g (1-H L )+r L H L (8) Where d is the differential symbol and is dimensionless; ρ g is the gas phase density, kg / m 3 ρ L is the liquid density, kg / m 3 ρ m is the density of gas-liquid mixture, kg / m 3 ; sin is the sine function, dimensionless; θ is the wellbore inclination angle, °; g is the gravitational acceleration, m / s 2 ; τ w is the shear stress between the mixture and the inner wall of the wellbore, MPa; S p is the wellbore wetted perimeter, m; A is the wellbore cross-sectional area, m 2 ;v m is the flow velocity of the gas-liquid two-phase mixture, m; H L is the liquid holdup of the wellbore cross section, dimensionless.

3. The method for optimizing the deep coal-rock gas pressure return nozzle considering multiple factors as claimed in claim 1, characterized in that: The critical flow model of proppant and coal powder in the deep coal gas reservoir fracture established in step (3) includes: In the formula, v c1 is the critical velocity of the proppant, m / s; ρ c is the particle density, kg / m 3 ;d c is the particle diameter, m; ρ is the fluid density, kg / m 3 ; μ is the fluid viscosity, mPa·s; g is the acceleration due to gravity, g=9.8m / s 2 ;v c2 is the critical velocity of coal powder, m / s; ε is the cohesion coefficient, which is 2.56 dyn / cm; p c is the pressure of the fracture wall on the proppant, MPa; p is the fluid pressure in the fracture, MPa; τ is a specific constant, dimensionless.

4. A method for optimizing deep coal-rock gas pressure return nozzles considering multiple factors as claimed in claim 1, characterized in that: The specific process of step (4) is as follows: based on the model established in steps (1) to (3), the relationship between the critical flow rate through the nozzle and the nozzle size, the reservoir IPR curve and the critical flow rate corresponding to the proppant start-up and the coal powder start-up in the fracture are obtained, and the nozzle size range d under a certain formation pressure is determined. c1 ~d c2 .

5. The method for optimizing the deep coal-rock gas pressure return oil nozzle considering the influence of multiple factors as claimed in claim 1, characterized in that: The step (5) specifically includes: considering that the increase in the backflow time will lead to a decrease in formation pressure, which will cause phase changes, thereby affecting the reservoir IPR curve and the critical flow corresponding to the proppant startup and the coal powder startup in the fracture; repeating step (4) can obtain a new range of nozzle sizes after the formation pressure is reduced, and integrating the corresponding wellhead pressure with the optimized nozzle size to obtain a relationship map between the nozzle size and the wellhead pressure after fracturing of the well.

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