Shale gas gathering and transportation station yard blockage and high-low pressure gathering and transportation interference diagnosis optimization method

Abstract

The invention discloses a shale gas gathering and transportation station yard blockage and high-low pressure gathering and transportation interference diagnosis optimization method, and belongs to the field of natural gas mine field gathering and transportation. According to the method, the judgment method of the blockage site of the pipeline in the station and the calculation method of the blockage degree are determined by checking the friction resistance of the whole-station pipe fitting of the shale gas station and calculating the pressure drop of the pipeline in the station, and a solution is provided for the problem of gathering and transportation interference in the high-pressure well mine field and the low-pressure well mine field. The method is suitable for shale gas gathering and transportation stations in the middle and later periods of development, can assist in making of equipment overhaul and production parameter optimization schemes, further improves the operation efficiency of a pipe network, and has wide application prospects.

Description

Technical Field

[0001] The present invention belongs to the field of natural gas field gathering and transportation, and particularly relates to a method for diagnosing and optimizing blockage and high-low pressure gathering and transportation interference in a shale gas gathering and transportation station yard. Background Art

[0002] The development of shale gas reservoirs generally adopts the production-increasing method of horizontal well staged fracturing. However, hydraulic fracturing will have a certain impact on the formation, resulting in more or less sand production problems during the production process of shale gas wells. The desander can effectively remove sand so that the downstream pipeline section is basically sand-free. However, after the single-well gathering pipeline is put into production, pigging operations are basically not carried out. After years of accumulation, serious sand blockages are likely to form in some pipeline sections from the wellhead to the desander, greatly increasing the gathering and transportation pressure drop. The actual flow-through area of the pipeline blocked is much smaller than the initial construction parameters, and the degree of blockage cannot be determined, making it difficult to conduct in-station pressure drop analysis in segments later. There are problems with high initial pressure but fast decline rate in the production of shale gas wells. At the same time, due to the rolling development mode adopted in shale gas fields, new wells are incorporated into the gathering and transportation pipeline network year by year, resulting in different backpressures for each gas well, causing greater gathering and transportation interference at the manifold, affecting the gas gathering efficiency of the pipeline. To solve the problem of high-low pressure interference in the pipeline, pressure drop analysis needs to be carried out in segments. Therefore, it is necessary to quantitatively analyze the blockage situation of the in-station pipeline, correct the parameters of the blocked pipeline to ensure that the pressure drop of this part of the pipeline conforms to the actual working conditions, and then determine the actual pressure drop loss of each pipeline section, provide a preliminary location guide for the maintenance of the blocked pipeline section, and select an appropriate optimization plan according to actual needs to optimize the production parameters of each well.

[0003] Traditional evaluation schemes do not target pipeline analysis of the blockage degree, and the in-station pressure drop calculation does not consider the influence of pipeline blockage, and cannot effectively solve the high-low pressure interference problem actually encountered in the in-station gathering and transportation process. This results in a lack of integrated analysis of the overall station pressure loss and the production parameters of each well when the production of shale gas wells decreases in the middle and late stages of the development of a certain platform station yard, and a lack of calculation basis for in-station process optimization. Summary of the Invention

[0004] In view of the above technical problems existing in the prior art, the present invention proposes a method for diagnosing and optimizing blockage and high-low pressure gathering and transportation interference conditions in a shale gas gathering and transportation station yard. After obtaining the production parameters of each well and the pressure and flow measurement point data, this method fully analyzes the in-station layout and the pressure drop of in-station pipeline fittings, determines the blocked sites of the in-station pipeline according to the measurement point range and quantifies the blockage degree. Further, based on the corrected pipeline parameters, it analyzes and solves the high-low pressure well gathering and transportation interference problem, and gives a production parameter optimization plan according to on-site requirements.

[0005] The technical solution of the present invention is as follows:

[0006] A method for diagnosing and optimizing blockage and high-low pressure gathering and transportation interference conditions in a shale gas gathering and transportation station yard, comprising the following steps:

[0007] Step 1: Obtain the first set of production data of each production well in the target station field, as well as the second set of production data including at least the pressure and flow rate of the outlet pipeline section;

[0008] Step 2: Obtain the local resistance coefficient, pipeline geometric parameters, and layout information of the pipelines within the station; the geometric parameters include inner diameter, wall thickness, roughness, length, and elevation;

[0009] Step 3: Based on the data in Step 1 and Step 2, use the multiphase pipe flow calculation method or numerical modeling method to calculate the pressure drop of the entire process within the station;

[0010] Step 4: According to the calculation results in Step 3, analyze the blockage sites and blockage degrees of the single-well pipelines, and diagnose the high-low pressure well gathering interference problems;

[0011] Step 5: Based on the blockage degree calculated in Step 4, correct the corresponding pipeline parameters, optimize the gathering interference problems, calculate the wellhead pressure of each well, and determine the optimal production parameters of each well according to requirements.

[0012] Preferably, the determination of the local resistance coefficient in Step 2 includes:

[0013] For elbow pipes, use formula (2) to calculate the local resistance coefficient;

[0014]

[0015] where d is the inner diameter of the elbow pipe, in mm; R is the radius from the center of the curvature circle of the elbow pipe to the axis of the elbow pipe, in mm; θ is the bending angle of the elbow pipe;

[0016] For sudden change pipe sections, use formula (3) to calculate the local resistance coefficient of sudden reduction or expansion;

[0017]

[0018] where ζ1 is the local resistance coefficient of sudden reduction of the cross-sectional area of the circular pipe; ζ2 is the local resistance coefficient of sudden expansion; A1 is the inlet cross-sectional area, in mm 2 ; A2 is the outlet cross-sectional area, in mm 2 ;

[0019] If there is no empirical formula for the pipe fitting, use formula (5) to determine the local resistance coefficient through numerical simulation by FLUENT software;

[0020]

[0021] where p in is the statistically weighted average value of the pressure at the inlet cross-section of the pipe fitting, in Pa; p outis the statistical weighted average of the pressure at the outlet cross-section of the pipe fitting, with the unit of Pa; ρ is the density of the mixed natural gas passing through the pipe fitting, with the unit of kg / m 3 ; v is the average flow velocity of the mixed natural gas, with the unit of m / s; the density is obtained by the Beggs-Brill multiphase flow calculation method;

[0022] The local friction loss of the pipe fitting is calculated through the local resistance coefficient, as shown in formula (1):

[0023]

[0024] Among them, h j is the local friction loss when passing through the pipe fitting, with the unit of m; ζ i is the local resistance coefficient of the pipe fitting, dimensionless; g is the acceleration of gravity, with the unit of m / s 2 .

[0025] Preferably, in step 3, the Beggs-Brill multiphase flow calculation method is adopted for pressure drop calculation, which specifically includes the following steps:

[0026] Step 3.1: Calculate the liquid holdup of the gas-liquid two-phase flow;

[0027] When the flow pattern is not the transitional flow pattern; according to formula (7), calculate the liquid holdup H1(θ):

[0028]

[0029] Among them, H1(θ) is the liquid holdup of the gas-liquid two-phase flow at an inclination angle of θ; H1(0) is the liquid holdup during horizontal flow under the same flow parameters; ψ is the inclination correction coefficient; a, b, and c are constants related to the flow pattern; E1 is the inlet volume liquid fraction; N Fr is the Froude number; the calculation formula is as follows:

[0030]

[0031] Among them, Q1 is the inlet liquid-phase volume flow rate, with the unit of m 3 / s; Q g is the inlet gas-phase volume flow rate, with the unit of m 3 / s; D is the inner diameter of the circular pipe, with the unit of mm

[0032] When the calculated pipe section is a horizontal pipe, calculate the inclination correction coefficient ψ according to formula (10):

[0033]

[0034] When the calculated pipe section is a vertical pipe, calculate the inclination correction coefficient ψ according to formula (11):

[0035] ψ = 1 + 0.3C(11);

[0036] wherein, the coefficient C is related to the inlet volume liquid holdup E1, the Froude number N Fr and the liquid phase velocity number N vl ;

[0037] According to formula (12), calculate the liquid phase velocity number N vl and the coefficient C:

[0038]

[0039] wherein, σ is the liquid phase surface tension; the coefficients d, e, f, g are constants;

[0040] When the flow regime is the transitional flow regime, according to formula (13), calculate the liquid holdup H1(θ):

[0041] H1(θ) = AH1(separation) + BH1(intermittent) (13);

[0042] wherein,

[0043]

[0044] Step 3.2: Calculate the mixed density of the gas-liquid two-phase flow;

[0045] According to the liquid holdup and formula (14), calculate the actual density of the mixture:

[0046]

[0047] wherein, M is the molar mass of the gas phase, with the unit of g / mol; R is the gas constant, with the unit of J / (kg·K); T is the gas temperature, with the unit of K; Z is the compressibility factor;

[0048] Calculate the compressibility factor Z through formula (15):

[0049]

[0050] wherein, P is the gas pressure, with the unit of MPa; Δ is the relative density of the gas;

[0051] Step 3.3: Calculate the friction factor of the gas-liquid two-phase flow;

[0052] λ = e s λ′(16);

[0053] wherein, λ is the friction factor of the gas-liquid two-phase flow, dimensionless; λ′ is the friction factor of the gas-liquid two-phase flow without slip, dimensionless; e is the base of the natural logarithm; s is the correlation coefficient, and s is calculated according to the following formula (17):

[0054]

[0055] In formula (17), y is calculated according to the following formula (18):

[0056]

[0057] For λ′, it is calculated using the following formula (19):

[0058]

[0059]

[0060] where N Re is the Reynolds number corresponding to the flow regime;

[0061] Step 3.4: Iteratively calculate the pressure drop of each pipe section;

[0062] Divide the in-station pipeline into several pipe sections, and calculate the local friction loss and the frictional resistance loss along the way for each section;

[0063] For horizontal pipe sections, calculate the pressure drop using formula (21), and correct the inclination angle for vertical pipe sections;

[0064]

[0065] where n i is the number of a certain pipe fitting in a certain pipe section; when the pressure drop of the pipe section is small, calculate the density of the mixed gas using the pressure at the inlet position; when the pipe section is long, take the inlet pressure to calculate the initial value of the density, and after obtaining the initial value of the pressure drop, recalculate the density using the average pressure of the two end faces and perform iteration, and determine the number of iterations according to the accuracy requirements; for vertical pipe sections, correct the pressure drop according to the correction method in the Beggs-Brill method.

[0066] Preferably, the liquid holdup is corrected according to the formula corresponding to the separated flow, intermittent flow or dispersed flow according to the flow regime, and the flow regime is judged by the Froude number and the inlet volume liquid holdup.

[0067] Preferably, the determination of the blockage degree in step 4 includes the following steps:

[0068] Step 4.1: Calculate the error between the theoretical pressure drop and the actual pressure drop. If the root mean square error exceeds the threshold, reduce the inner diameter of the pipeline and perform iterative calculation until the error meets the accuracy requirements;

[0069] Calculate the error between the theoretically calculated pressure drop and the actual pressure drop according to the following formula (22):

[0070]

[0071] where: ΔP cis the theoretical calculated pressure drop, with the unit of Pa or MPa; ΔP a is the actual pressure drop, and the unit corresponds to that of the theoretical calculated pressure drop;

[0072] Step 4.2: Calculate at least 6 groups of test data for each production well in the whole station, obtain the error values of each group of data, and calculate the mean error ME and root mean square error RMSE according to the following formula (23):

[0073]

[0074] where, e i is the error value calculated for each group of data according to formula (22); n is the number of data groups;

[0075] Determine the plugging site according to the error sign. When ME>0 for a certain well, it means that the theoretical calculated pressure drop is greater than the actual pressure drop; when ME<0 for a certain well, the theoretical calculated pressure drop is less than the actual pressure drop;

[0076] Step 4.3: Calculate the degree of plugging according to formula (24);

[0077]

[0078] where, D b is the inner diameter of the pipeline before correction, with the unit of mm; D a is the inner diameter of the pipeline after correction, with the unit of mm.

[0079] Preferably, the scheme for optimizing the gathering and transportation interference in step 5 includes:

[0080] (a) Throttling scheme for high-pressure wells: Based on the lowest inlet pressure of the manifold, calculate the pressure after throttling of the high-pressure wells in reverse;

[0081] (b) Boosting scheme for low-pressure wells: Based on the highest inlet pressure of the manifold, calculate the pressure after boosting of the low-pressure wells in reverse;

[0082] (c) Compromise scheme: Adjust the throttling or boosting of some wells to balance the manifold pressure.

[0083] Preferably, the reverse calculation adopts the pressure-flow iteration method:

[0084] Starting from the manifold pressure, reverse-iterate to calculate the outlet pressure of a single well according to the corrected pipeline parameters until the density error is less than 5%.

[0085] Preferably, in step 1, the first group of production data includes the pressure after throttling at the outlet of a single well, the daily gas production, the daily water production, and the gas physical property parameters.

[0086] Preferably, the diagnosis of high and low pressure gathering and transportation interference in step 4 includes:

[0087] Based on the corrected pipeline parameters, calculate the inlet pressure of each well gathering pipe. If the pressures are inconsistent, it is determined that there is gathering and transportation interference;

[0088] Adjust the outlet pressure of a single well to make the inlet pressure of the gathering pipe consistent, and select an optimization plan in combination with the external transportation pressure requirement.

[0089] The beneficial technical effects brought by the present invention:

[0090] The present invention determines the judgment method of the pipeline blockage site and the calculation method of the blockage degree in the station pipeline by checking the friction resistance of all pipe fittings in the shale gas station yard and calculating the pressure drop in the station pipeline, and provides a solution to the problem of gathering and transportation interference between high-pressure and low-pressure wells. The present invention is applicable to the shale gas gathering and transportation station yard in the middle and late stages of development, can assist in equipment maintenance and the formulation of production parameter optimization plans, and thus improve the operation efficiency of the pipeline network, and has a wide application prospect. Description of the Drawings

[0091] Figure 1 It is the flow chart of the shale gas station yard diagnosis and optimization method of the present invention;

[0092] Figure 2 It is the flow chart for determining the local resistance coefficient of pipe fittings of the present invention;

[0093] Figure 3 It is the flow chart for analyzing the site of the blocked pipe section of the pipeline of the present invention;

[0094] Figure 4 It is the flow chart for calculating the blockage degree of the blocked pipe section of the pipeline of the present invention;

[0095] Figure 5 It is the flow chart for analyzing the gathering and transportation interference between high-pressure and low-pressure of the present invention;

[0096] Figure 6 It is the flow chart for optimizing the gathering and transportation interference between high-pressure and low-pressure of the present invention. Detailed Embodiment

[0097] The present invention will be further described in detail below in conjunction with the drawings and specific embodiments:

[0098] A method for diagnosing and optimizing blockage and gathering and transportation interference between high-pressure and low-pressure in a shale gas gathering and transportation station yard includes the following steps:

[0099] Step 1: Obtain the pressure after throttling at the outlet of a single well, the daily gas production, the daily water production, etc. as the first set of production data required for calculation; at least obtain the second set of production data of the outbound pipe section at the corresponding moment (the more data measurement points there are in the station pipeline, the more accurate the pressure drop calculation result and the determination interval of the blockage site). When there are multiple production wells in the station, at least obtain the production data of all production wells at 6 different moments for cross-verification and comprehensive analysis;

[0100] The basic gas well production data includes the tubing head pressure, the pressure after throttling, the bottom-hole flowing pressure, the composition of the produced gas (or water cut), viscosity, relative density, and temperature corresponding to the gas well production. When the molar fractions of each component of the produced gas are provided, higher calculation accuracy can be obtained through gas component analysis; when data is missing, it can be calculated through the water content and relative density of the produced gas.

[0101] Step 2: Obtain the local resistance coefficients of the pipe fittings in the station; the assembly drawing of all pipeline equipment including elevation, pipeline inner diameter, wall thickness, roughness, and length are used for calculating the pressure drop in the station;

[0102] The local resistance coefficients of the pipe fittings are used to calculate the total pressure loss of the station;

[0103] Step 2.1: The general formula for calculating the local friction loss of pipe fittings through the local resistance coefficient:

[0104]

[0105] where h j is the local friction loss when passing through the pipe fitting, with the unit of m; ζ i is the local resistance coefficient of the pipe fitting, dimensionless; v is the average flow velocity of natural gas in the pipe, with the unit of m / s; g is the acceleration due to gravity, with the unit of m / s 2 ; The following are some empirical formulas recommended for calculating the local friction coefficients of some pipe fittings:

[0106]

[0107] This formula is used to calculate the local resistance coefficient of the elbow. Among them, d is the inner diameter of the elbow, with the unit of mm; R is the radius from the center of the curvature circle of the elbow to the axis of the elbow, with the unit of mm; θ is the bending angle of the elbow. When there is an abrupt change in the inner diameter of the pipe fitting, the following formula is used to calculate the local resistance coefficient of the abrupt change part:

[0108]

[0109] where ζ1 is the local resistance coefficient of the sudden reduction of the cross-sectional area of the circular pipe; ζ2 is the local resistance coefficient of the sudden expansion; A1 is the inlet cross-sectional area, with the unit of mm 2 ; A2 is the outlet cross-sectional area, with the unit of mm 2 ;

[0110] Step 2.2: When there is no recommended value or empirical formula for the local resistance coefficient of the pipe fitting used, it can be obtained through numerical simulation using FLUENT software. Export the weighted average of the statistical areas of the inlet and outlet cross-sections of the pipe fitting for subsequent calculations, and the simulation geometric parameters are consistent with the field. To avoid large errors in the results caused by incomplete formation of the flow field, the straight pipe sections at least 6 times the pipe diameter should be extended at the inlet and outlet positions of the pipe fitting.

[0111] Step 2.3, the resistance coefficient of the FLUENT simulation pipe is calculated as follows:

[0112]

[0113] Among them, P in It is the statistical weighted average pressure of the pipe inlet section, in Pa; P out is the statistical weighted average pressure of the pipe outlet section, in Pa; ρ is the density of the mixed natural gas passing through the pipe, in kg / m 3 ; Density is obtained by the Beggs-Brill multiphase flow calculation method, and the following assumptions and applicable conditions are noted:

[0114] (1) Applicable to the case where the flowing medium consists of only gas and liquid phases and no solid phases such as sand particles;

[0115] (2) Assume that the gas-liquid mixture system is adiabatic and does not exchange heat with the outside world;

[0116] (3) Assume that the medium in the pipelines of the entire station is in a constant flow state;

[0117] (4) Applicable to calculation of gas-liquid two-phase pipe flow in horizontal, vertical and arbitrarily inclined positions;

[0118] (5) The applicable conditions for the calculation formula of gas compressibility factor selected in this application are: relative density satisfies

[0119] Δ=0.55~0.70, pressure satisfies P=0~6.89MPa, temperature satisfies T=272.2~333.3K;

[0120] Beggs-Brill method basic equation:

[0121]

[0122] Where ρ1 is the liquid density under flow conditions, which is generally taken as a constant in kg / m 3 ρ g is the gas phase density under flow conditions, in kg / m 3 ; v is the average velocity of the mixture, in m / s; v sg is the gas apparent (converted) velocity, in m / s; Z is the flow direction; θ is the angle between the pipeline and the horizontal direction (degree system); D is the inner diameter of the pipe, in m; G is the mass flow rate of the mixture, in kg / s; H1 is the liquid holdup, calculated as follows:

[0123]

[0124] Among them, H1(θ) is the liquid holdup of gas-liquid two-phase flow at an inclination angle of θ; H1(0) is the liquid holdup during horizontal flow under the same flow parameters; ψ is the inclination correction coefficient; a, b, and c are constants related to the flow pattern, and the relevant values are shown in the following table:

[0125] Table 1: Table of constants a, b, and c

[0126]

[0127]

[0128] The Beggs-Brill method determines the flow regime according to the following steps:

[0129] Calculate the Froude number and the inlet volume liquid holdup:

[0130]

[0131] Among them, Q1 is the inlet (in-situ) liquid-phase volume flow rate; Q2 is the inlet (in-situ) gas-phase volume flow rate. Taking E1 as the abscissa and N Fr as the ordinate, draw a flow regime partition discrimination diagram, and the partition line equation is as follows:

[0132]

[0133] The following table shows the flow regime discrimination conditions combined with the discrimination diagram:

[0134] Table 2: Flow regime discrimination in the Beggs-Brill method

[0135]

[0136] The inclination correction coefficient in the aforementioned formula (7) is calculated according to the following formula:

[0137]

[0138] When the calculated pipe section is a vertical pipe, it is calculated according to the following formula:

[0139] ψ = 1 + 0.3C(11);

[0140] Among them, the coefficient C is related to the no-slip liquid holdup E1, the Froude number N Fr and the liquid-phase velocity number N vl . The liquid-phase velocity number and the coefficient C are calculated according to the following formula:

[0141]

[0142] Among them, σ is the liquid-phase surface tension; the coefficients d, e, f, and g are determined according to the following table:

[0143] Table 3: Coefficients d, e, f, and g

[0144]

[0145] Based on the above content, the H1(θ) values of flow patterns other than the transitional flow pattern can be calculated. For the transitional flow pattern, it is calculated according to the following formula:

[0146] H1(θ) = AH1(separation) + BH1(intermittent) (13);

[0147]

[0148] The actual density of the mixture can be calculated from the liquid holdup according to the following formula:

[0149]

[0150] Where M is the molar mass of the gas phase, with the unit g / mol; R is the gas constant, with the unit J / (kg·K); T is the gas temperature, with the unit K; Z is the gas compressibility factor, dimensionless, and the calculation adopts the formula of the California Natural Gas Association (CNGA) of the United States:

[0151]

[0152] Where P is the gas pressure (absolute), with the unit MPa; Δ is the relative density of the gas; when higher precision requirements for the calculation of the compressibility factor are needed, the gas BWRS equation can be used for calculation.

[0153] Step 3: Use the multiphase pipe flow calculation method or numerical modeling method to perform modeling and auxiliary calculation on the entire station process;

[0154] Regarding the part of the calculation of the total station pressure loss, the main basis is the Beggs-Brill multiphase flow calculation method. Through this method, the friction factor of the gas-liquid two-phase flow is calculated:

[0155] λ = e s λ′(16);

[0156] Where λ is the friction factor of the gas-liquid two-phase flow, dimensionless; λ` is the friction factor of the gas-liquid two-phase flow without slip, dimensionless; e is the base of the natural logarithm; s is the correlation coefficient, and s is calculated according to the following formula:

[0157]

[0158] In formula (17), y is calculated according to the following formula:

[0159]

[0160] Step 3.1: For λ`, it is calculated using the following formula:

[0161]

[0162] where N Re is the Reynolds number under the corresponding flow regime;

[0163] Step 3.2: After determining the above parameters, calculate the pressure drop of each pipeline section. The gathering and transportation pipelines are usually laid separately for each well from the outlet of the single well to the front of the desander. After passing through this section, the gas from each well enters the header pipe. When calculating, take the outlet of the single well as the starting point, take the pressure after throttling, and calculate the pressure drop from each single well to the header pipe according to the local resistance coefficient and the friction resistance coefficient of each pipe fitting. The calculation method for the horizontal pipe section is as follows:

[0164]

[0165] where n i is the quantity of a certain pipe fitting in a certain pipeline section; when the pressure drop of the pipeline section is small, calculate the density of the mixed gas using the pressure at the inlet position; when the pipeline section is long, take the inlet pressure to calculate the initial value of the density, and after obtaining the initial value of the pressure drop, recalculate the density using the average pressure of the two end faces and perform iteration, and determine the number of iterations according to the accuracy requirements; for the vertical pipeline section, correct the pressure drop according to the correction method in the Beggs-Brill method.

[0166] Step 3.3: The whole station pipelines are separated from the following nodes: desander, vertical pipe, header pipe, separator, pressure and flow measurement device, globe valve, gate valve, elbow, and calculate the pressure drop for each section using the above formula.

[0167] Step 4: Analyze the blockage site and degree of the single well pipeline and the interference situation of the gathering of each well based on the calculated data analysis;

[0168] Calculation of pipeline blockage degree, analysis of interference between wells, and implementation methods of production parameters:

[0169] Step 4.1: The blockage problem is concentrated in the pipeline section from the outlet of the single well to the desander. When there is no desander in the station, take the pipeline section from the outlet of the single well to the header pipe for analysis. Taking the outlet of the single well as the starting point, the calculation of each section of the pipeline is based on the coupling of pressure and flow rate, and calculate the pressure drop of the pipeline to the position of the header pipe or desander. This calculation result is the theoretical calculated pressure drop; when providing the pressure and flow rate test data at the position of the header pipe or desander, take the difference between the pressure after throttling of the single well and the pressure at this position as the actual pressure drop comparison value; when there is no pressure and flow rate data at this site, use the outlet pressure and flow rate data to calculate backward to this position to obtain the pressure drop comparison value, and calculate the error between the theoretical calculated pressure drop and the actual pressure drop comparison value according to the following formula:

[0170]

[0171] where: ΔP c is the theoretical calculated pressure drop, with the unit of Pa or MPa; ΔP a is the actual pressure drop, with the unit corresponding to the theoretical calculated pressure drop;

[0172] Step 4.2: Calculate at least 6 groups of test data for each production well in the whole station according to the above method, obtain the error values of each group of data to ensure the accuracy of the criterion, and calculate the average error and root mean square error according to the following formula:

[0173]

[0174] where, e i is the error value calculated from each group of data according to formula (22); n is the number of data groups; when ME>0 for a certain well, it means that the theoretically calculated pressure drop is greater than the actual pressure drop, when ME<0 for a certain well, the theoretically calculated pressure drop is less than the actual pressure drop, and when the root mean square error < 15%, it can be considered that the engineering accuracy is achieved, and appropriate adjustments can be made when higher accuracy requirements are needed;

[0175] Step 4.3: Calculate ME and RMSE for the gathering pipelines of each well respectively. When the initial value of RMSE of a certain well meets the accuracy requirements, it is considered that there is no blockage problem in the pipeline; when it is greater than 15%, the pipeline parameters need to be corrected. At this time, if ME<0 and the difference is large, it can be determined that there is a blockage in this part of the pipeline. When there are other measuring points in this section of the pipeline, segment the pipeline from the measuring point, calculate the theoretical pressure drop and the recorded pressure drop of each segment, recalculate RMSE and ME for each segment. If RMSE and ME of each segment are equal, it is considered that the blockage degree of this part of the pipeline is consistent, and the pipeline parameters will be corrected as a whole subsequently; if RMSE and ME of each segment are not equal after calculation, it is necessary to correct the segments separately from the position of the measuring point.

[0176] Step 4.4: For the pipeline section to be corrected, each time the inner diameter is reduced by 5% during iteration and the pressure drop of the pipeline section is recalculated, compared with the measured pressure drop, and RSME is calculated according to formula (23). Iterative calculations are performed multiple times until the RMSE value meets the accuracy requirements, and the final iterative value is the corrected value of the inner diameter of the pipeline section; for the pipeline section to be corrected segmented from the data measuring point, first correct each segment independently to make the RMSE value meet the accuracy requirements, and the ME values of each segment have the same sign. After the parameters of each segment are corrected, recalculate the pressure drop and RMSE value of the whole section and repeat the above iterative process until the RMSE value of the whole section meets the requirements. The more data measuring points there are in the gathering pipeline of a single well, the more accurate the judgment of the blockage position and the calculation of the blockage degree will be.

[0177] Step 4.5: The calculation of the blockage degree is based on the following formula:

[0178]

[0179] where, D b is the inner diameter of the pipeline before correction, in mm; D a is the inner diameter of the pipeline after correction, in mm;

[0180] Step 4.6: It is possible to calculate and analyze whether there may be high-low pressure gathering and transportation interference problems when all production wells in the station produce at different production rates and pressures. First, based on the content in the above Steps 4.1 to 4.5, complete the judgment of the pipeline blockage degree and the pipe diameter correction, and obtain the production data such as the production rate and pressure of each well at the target moment. Use the corrected pipeline inner diameter and pipe fitting friction coefficient to perform pressure iteration according to Steps 2 and 3, calculate the gas inlet pressure of each well at the manifold, and compare. When the pressures at each location are equal, there is no gathering and transportation interference; otherwise, there is an interference problem.

[0181] Step 5: Based on the blockage degree calculated in Step 4, correct the corresponding pipeline parameters, analyze and solve the high-low pressure well gathering and transportation interference problem, and determine the optimal production parameters of each well according to the requirements. The determination method of the production parameters of each well in the whole station is as follows:

[0182] Step 5.1: Increasing the outlet pressure of low-pressure wells or decreasing the outlet pressure of high-pressure wells to make the pressures at the manifolds of the gathering pipelines of each well consistent can solve the high-low pressure well gathering and transportation interference problem. Low-pressure wells generally use non-throttling external transportation. To increase their outlet pressure, booster equipment needs to be added. While solving the well interference, it can increase the production rate, reduce the abandonment pressure, and increase the recovery rate, but it will generate additional costs; using the method of decreasing the outlet pressure of high-pressure wells to solve the gathering and transportation interference will affect the production rate, but no additional costs will be generated.

[0183] Step 5.2: Method for pressure balance at the manifold: Calculate the pressure drop from the outlet of each single well to the inlet of the manifold according to Step 4.5, compare the inlet pressures of each manifold, and take the lowest value as the initial pressure of the manifold. Use the aforementioned pressure drop calculation method to calculate the outlet pressure and pipeline pressure drop. When the outlet pressure meets the external transportation requirements, this pressure can be considered as the reference pressure of the manifold to throttle the high-pressure wells; otherwise, only the low-pressure wells can be boosted.

[0184] Step 5.3: Further elaborate on three different optimization schemes:

[0185] (1) High-pressure well throttling scheme: The reference pressure at the manifold is the lowest inlet pressure. The production wells corresponding to this pressure are not adjusted. Use the pressure-flow iteration calculation method to calculate the outlet pressures of other wells in reverse from the manifold. This pressure is the pressure after throttling for each well;

[0186] (2) Low-pressure well boosting scheme: The reference pressure at the manifold is the highest inlet pressure. The production wells corresponding to this pressure are not adjusted. Use the pressure-flow iteration calculation method to calculate the outlet pressures of other wells in reverse from the manifold. This pressure is the pressure after boosting for the low-pressure wells. Select the compressor according to the actual outlet pressure, boosted pressure, and production rate of the low-pressure wells;

[0187] (3) Compromise scheme: Select a compromise pressure, use the throttling process for high-pressure wells and the boosting process for low-pressure wells to balance the pressure.

[0188] Step 5.4. Further elaborate on the pressure-flow iterative calculation method in Step 5.3: Based on the pressure drop calculation methods in Steps 2 and 3, calculate backward to the outlet of a single well to obtain an initial wellhead pressure. During the first calculation, the mixed gas density is calculated based on the header pressure; calculate the mixed gas density according to the average value of the single well outlet pressure and the header pressure obtained from the first calculation, and calculate the error between this density and the density calculated using the header pressure. When the error is less than 5%, the accuracy requirement is met; otherwise, recalculate the wellhead pressure using this density and iterate successively until the allowable error is reached.

[0189] The following introduces the basic situation of the embodiment:

[0190] In this embodiment, the station is the H11 platform station in a certain shale gas block in the southwest. There are 6 production wells in the station. Among them, Wells 2#, 3#, and 4# are all in normal production, and the rest of the wells are currently shut in; the produced gas mainly contains methane and a small amount of water; there is no desander in the station. The gas from each well reaches the process area through the gathering pipeline, enters the rotating metering valve group for metering, and then enters the header. The outlet of the header is connected to a DN800 horizontal three-phase separator. When the outlet pressure of the three-phase separator is not sufficient for external transportation, it is pressurized by a compressor and then transported externally; otherwise, it is directly transported externally.

[0191] The following further elaborates on the present invention in detail with reference to the drawings and specific embodiments:

[0192] See Figure 1 , a method for diagnosing and optimizing blockage and high-low pressure gathering interference in a shale gas gathering station, implementation steps: obtain the production data of gas wells required; obtain the layout and relevant geometric parameters of on-site pipe fittings and pipelines; determine the local resistance coefficient of pipe fittings; calculate the pressure drop of each pipeline according to the aforementioned Steps 2 and 3, analyze the blockage position and degree of the pipeline; correct the pipeline parameters according to the pipeline blockage degree, further calculate the gathering interference situation of each well and give the recommended production parameters. The specific steps in combination with the embodiment are as follows:

[0193] The basic gas well production data includes the pressure after throttling of the gas well, the water content, viscosity, relative density, and temperature of the produced gas; obtain the local resistance coefficient of the pipe fittings in the station, and the implementation steps are shown in Figure 2 the local resistance coefficient determination process; obtain the assembly drawing of the whole station pipeline equipment including elevation, pipeline inner diameter, wall thickness, roughness, and length for calculating the pressure drop in the station.

[0194] Figure 3 For the schematic diagram of the judgment process of the pipeline blockage site in the station, the following explains the specific implementation steps in combination with the embodiment:

[0195] After determining the above parameters, calculate the pressure drop of each pipe section. Starting from the outlet of a single well, take the pressure after throttling, and calculate the pressure drop from each single well to the header part according to the local resistance coefficient and the friction resistance coefficient of each pipe fitting. The calculation method for the horizontal pipe section refers to formula (21):

[0196]

[0197] When calculating, the initial value of density is taken as the inlet pressure. After obtaining the initial value of pressure drop, the density is recalculated using the average pressure at both ends and iteration is performed until the error is less than 0.1%. The pressure drop of the vertical pipe section is corrected based on the Beggs-Brill method.

[0198] The whole station pipeline is separated from the following nodes: vertical pipes, header pipes, separators, pressure and flow measurement devices, globe valves, gate valves, elbows and other pipe fittings, and the pressure drop is calculated section by section using the above formula.

[0199] There is no desander in the station, so the pipe section from the single well outlet to the header pipe is taken to analyze the blockage site and degree. Starting from the single well outlet, the calculation of each section of the pipeline is based on the coupling of pressure and flow, and the pressure drop of the pipeline is calculated to the inlet of the header pipe. This calculation result is the theoretical calculated pressure drop. The difference between the pressure after throttling at the single well and the field test data of the header pipe pressure is taken as the actual pressure drop comparison value, and the error between the theoretical calculated pressure drop and the actual pressure drop is calculated according to formula (22):

[0200]

[0201] For this part of the pipeline, 6 groups of data at different test times are used to calculate the theoretical pressure drop and the actual pressure drop according to formula (13), and then the error is calculated according to formula (22) to obtain 6 groups of error values. For all error values, formula (23) is used to calculate the mean error (ME) and the root mean square error (RMSE):

[0202]

[0203] When ME>0 for a certain well, it means that the theoretical calculated pressure drop is greater than the actual pressure drop. When ME<0 for a certain well, it means that the theoretical calculated pressure drop is less than the actual pressure drop. When RMSE<15%, it is considered that the accuracy requirement is met. The following are the first calculation data of some wells (the initial inner diameter of each pipeline during construction is 65mm):

[0204] Table 4: Statistical table of calculated pressure drop and error of Well 1#, Well 5# and Well 6#

[0205]

[0206] According to the data in the table, it can be seen that there is a problem that the average error of Well 1#, Well 5# and Well 6# is less than 0. Therefore, there is a blockage problem in the pipe section from the single well outlet to the header pipe of Well 1#, Well 5# and Well 6# at this time. In practical applications, the blockage position can be determined in the pipe section between the two pressure measurement points, and the positioning accuracy of the blockage site increases with the increase in the number of measurement points; when the number of measurement points is limited, the overall pipe section is uniformly reduced by a certain proportion to process the flow area.

[0207] Figure 4This is a flow chart for calculating the blockage degree of a blocked pipe section in a pipeline. The following specifically explains the implementation steps in conjunction with an embodiment:

[0208] For the pipe section to be corrected, the inner diameter is reduced by 5% each time through iteration, and the pressure drop of the pipe section is recalculated and compared with the measured pressure drop. RSME is calculated according to formula (23). Multiple iterations are performed until the RMSE value meets the accuracy requirements. The final iteration value is the correction value of the inner diameter of the pipe section. Some of the results of the iterative calculation process in this example are as follows:

[0209] Table 5: Iterative calculation results of the revised pipe diameters of Well 1#, Well 5#, and Well 6# (original pipe diameter 65mm)

[0210]

[0211]

[0212] According to the iterative calculation results, when the pipe diameter of Well 1# is reduced to 37mm, the error is reduced from -54.29% to 13.73%; when the pipe diameter of Well 5# is reduced to 35mm, the error is reduced from -79.43% to 9.39%; when the pipe diameter of Well 6# is reduced to 27mm, the error is reduced from -85.46% to 16.59%. The calculation accuracy meets the requirements, so the corrected pipe diameter of Well 1# is 37mm, the corrected pipe diameter of Well 5# is 35mm, and the corrected pipe diameter of Well 6# is 27mm.

[0213] The calculation of the degree of congestion is based on formula (24):

[0214]

[0215] Calculation shows that the blockage degree of Well 1# is 67.6%, the blockage degree of Well 5# is 71.01%, and the blockage degree of Well 6# is 82.75%. As the blockage degree of the pipeline corresponding to Well 6# has exceeded 80%, further inspection is required on site and the pipeline from the single well outlet to the manifold corresponding to Well 6# should be replaced.

[0216] Figure 5 This is a flow chart for analyzing interference between high and low voltage transmission. The following explains the analysis steps in conjunction with an example:

[0217] Based on the above steps, the pipeline blockage degree calculation is completed, and the corrected pipeline inner diameter is used to perform high and low pressure gathering and transportation interference analysis. Perform pressure iteration according to steps 2 and 3, calculate and compare the incoming gas pressure of each well at the manifold. When the pressures at each location are equal, there is no gathering and transportation interference, otherwise there is an interference problem; the existing production parameters of wells 1#, 5#, and 6# are as follows. The diameter of the pipeline from the single well outlet to the manifold inlet has been corrected according to the above method, and the high and low pressure gathering and transportation interference analysis is now carried out:

[0218] Table 6: Production parameters of wells 2#, 3#, and 4# at a certain time

[0219]

[0220] When the outlet pressures of all three wells are 0.4 MPa, according to the aforementioned calculation method, the inlet pressure of the pipeline manifold for Well 1 is 0.37 MPa, the inlet pressure of the pipeline manifold for Well 5 is 0.28 MPa, and the inlet pressure of the pipeline manifold for Well 6 is 0.38 MPa. Since the inlet pressure of the pipeline manifold for Well 5 is much lower than that of Well 1 and Well 6, it will make it difficult to export the produced gas from Well 5, and production parameters need to be optimized.

[0221] Figure 6 It is a flowchart for optimizing the interference between high and low pressure gathering and transportation. The following explains the optimization steps in combination with the embodiments:

[0222] Pressure balance method at the manifold: Calculate the pressure drop from the outlet of each single well to the inlet of the manifold according to Step 4.5, compare the inlet pressures of each manifold, and take the lowest value as the initial pressure of the manifold. Use the aforementioned pressure drop calculation method to calculate the station outlet pressure and pipeline pressure drop. When the station outlet pressure meets the export requirements, this pressure can be considered as the reference pressure of the manifold to throttle the high-pressure wells; otherwise, only the low-pressure wells can be pressurized.

[0223] Three different optimization schemes:

[0224] (1) High-pressure well throttling scheme: The pressure reference at the manifold is the lowest inlet pressure. The production well corresponding to this pressure is not adjusted. Use the pressure-flow iterative calculation method to calculate the outlet pressures of other wells in reverse from the manifold. This pressure is the pressure after throttling for each well;

[0225] (2) Low-pressure well pressurization scheme: The pressure reference at the manifold is the highest inlet pressure. The production well corresponding to this pressure is not adjusted. Use the pressure-flow iterative calculation method to calculate the outlet pressures of other wells in reverse from the manifold. This pressure is the pressure after pressurizing the low-pressure wells. Select a compressor according to the actual outlet pressure, pressurized pressure, and production volume of the low-pressure wells;

[0226] (3) Compromise scheme: Select a compromise pressure, adopt a throttling process for high-pressure wells, and a pressurization process for low-pressure wells to balance the pressure.

[0227] In this embodiment, the production parameters are optimized using three schemes respectively. First, the high-pressure well throttling scheme is adopted. When the outlet pressures of all wells are known to be 0.4 MPa, the inlet pressures of the manifolds corresponding to the pipelines of each well are 0.37 MPa, 0.28 MPa, and 0.38 MPa respectively. At this time, the lowest pressure is 0.28 MPa, and the lowest export pressure is 0.25 MPa. When using the throttling scheme, the requirements can be met, and the other two wells need to be throttled at the wellhead. Calculate based on the pressure-flow iterative calculation method in Step 5.4 above. The final results are as follows:

[0228] Table 7: Final values of iterative calculation of outlet pressure of each well for throttling scheme

[0229]

[0230] According to the calculation results, when the throttling scheme is adopted, the production parameters of Well 5 do not need to be adjusted. The pressure of Well 1 should reach 0.314 MPa after throttling at the wellhead, and the pressure of Well 6 should reach 0.305 MPa after throttling at the wellhead.

[0231] Adopt the pressurization scheme to optimize the interference problem between gathering pipelines of Well 1, Well 5 and Well 6: According to the aforementioned calculation results, when the outlet pressure of each well is 0.4 MPa, the inlet pressure of the manifold of Well 6 is the highest at 0.38 MPa. When the pressurization scheme is adopted, based on the highest inlet pressure, the outlet pressure of Well 6 is selected as the benchmark for iterative calculation of the pressure of the pipelines of the other two wells until the pressures of the gathering pipelines corresponding to the three wells at the manifold are equal. The final results are as follows:

[0232] Table 8: Final values of iterative calculation of outlet pressure of each well for pressurization scheme

[0233]

[0234] According to the calculation results, when the throttling scheme is adopted, the production parameters of Well 6 do not need to be adjusted. The pressure of Well 1 should reach 0.406 MPa after pressurization, and the pressure of Well 5 should reach 0.472 MPa after pressurization. At this time, the interference problem of gathering between high and low pressure wells can be solved.

[0235] Adopt the compromise scheme to optimize the interference problem between gathering pipelines of Well 1, Well 5 and Well 6: According to the aforementioned calculation results, when the outlet pressure of each well is 0.4 MPa, the inlet pressure of the manifold of Well 1 is between Well 5 and Well 6 at 0.37 MPa. When the compromise scheme is adopted, a certain median pressure is used as the benchmark. In this embodiment, since only the production parameters of 3 wells are analyzed, the outlet pressure of Well 1 is selected as the benchmark for iterative calculation of the pressure of the pipelines of the other two wells until the pressures of the gathering pipelines corresponding to the three wells at the manifold are equal. The final results are as follows:

[0236] Table 9: Final values of iterative calculation of outlet pressure of each well for compromise scheme

[0237]

[0238] According to the calculation results, when the throttling scheme is adopted, the production parameters of Well 1 do not need to be adjusted. The pressure of Well 5 should reach 0.464 MPa after pressurization at the wellhead, and the pressure of Well 6 should reach 0.39 MPa after throttling. At this time, the interference problem of gathering between high and low pressure wells can be solved.

[0239] In summary, through the method of the present invention, it is possible to determine the blockage site and degree of blockage of the pipelines in the shale gas station by checking the friction resistance of all pipe fittings in the whole shale gas station and calculating the pressure drop of the pipelines in the station, providing a solution to the problem of interference in the gathering and transportation of high and low pressure wells in the mine field. It is applicable to the shale gas gathering and transportation stations in the middle and late stages of development, effectively assisting the formulation of equipment maintenance and gathering and transportation pipeline network adjustment plans, and improving the operation efficiency of the pipeline network.

[0240] Of course, the above description is not a limitation of the present invention, and the present invention is not limited to the above examples. Changes, modifications, additions or substitutions made by those skilled in the art within the scope of the essence of the present invention should also fall within the protection scope of the present invention.

Claims

1. A diagnostic optimization method for blockage and high-low pressure gathering and transportation interference conditions in a shale gas gathering and transportation station, characterized in that: It includes the following steps: Step 1: Obtain the first set of production data of each production well in the target station field, and the second set of production data including at least the pressure and flow rate of the outbound pipeline section; Step 2: Obtain the local resistance coefficient, pipeline geometric parameters and layout information of the pipelines in the station; the geometric parameters include inner diameter, wall thickness, roughness, length and elevation; Step 3: Based on the data in Step 1 and Step 2, use the multiphase pipe flow calculation method or numerical modeling method to calculate the pressure drop of the entire process in the station; Step 4: According to the calculation results in Step 3, analyze the blockage sites and blockage degrees of the single-well pipelines, and diagnose the problems of high-low pressure well gathering interference; Step 5: Based on the blockage degree calculated in Step 4, correct the corresponding pipeline parameters, optimize the gathering interference problem, calculate the wellhead pressure of each well, and determine the optimal production parameters of each well according to requirements.

2. The diagnostic optimization method for the plugging and high-low pressure gathering and transportation interference conditions of the shale gas gathering and transportation station yard according to claim 1, characterized in that: The determination of the local resistance coefficient in Step 2 includes: For elbow pipes, the local resistance coefficient ζ is calculated using Equation (2). i ; where d is the inner diameter of the elbow, in mm; R is the radius from the center of the curvature circle of the elbow to the axis of the elbow, in mm; θ is the bending angle of the elbow; For sudden change pipe sections, use formula (3) to calculate the local resistance coefficient of sudden contraction or expansion; Among them, ζ1 is the local resistance coefficient of the sudden contraction of the cross-section of the circular pipe; ζ2 is the local resistance coefficient of the sudden expansion; A1 is the inlet cross-sectional area, with the unit of mm 2 ; A2 is the outlet cross-sectional area, with the unit of mm 2 ; If there is no empirical formula for the pipe fittings, use formula (5) and perform numerical simulation through FLUENT software to determine the local resistance coefficient; Among them, p in is the statistically weighted average pressure of the pipe fitting inlet section, with the unit of Pa; p out is the statistically weighted average pressure of the pipe fitting outlet section, with the unit of Pa; ρ is the density of the mixed natural gas passing through the pipe fitting, with the unit of kg / m 3 ; the density is obtained by the Beggs-Brill multiphase flow calculation method; v is the average flow velocity of the mixed natural gas, with the unit of m / s; Calculate the local friction loss of the pipe fittings through the local resistance coefficient, as shown in formula (1); Among them, h j is the local frictional loss when passing through the pipe fitting, with the unit of m; ζ i is the local resistance coefficient of the pipe fitting, dimensionless; g is the acceleration of gravity, with the unit of m / s 2 .

3. The diagnostic optimization method for the plugging and high-low pressure gathering and transportation interference conditions of the shale gas gathering and transportation station yard according to claim 1, characterized in that: In Step 3, use the Beggs-Brill multiphase flow calculation method to calculate the pressure drop, which specifically includes the following steps: Step 3.1: Calculate the liquid holdup of the gas-liquid two-phase flow; When the flow pattern is not the transitional flow pattern; according to formula (7), calculate the liquid holdup H1(θ): where, H1(θ) is the liquid holdup of gas-liquid two-phase flow at an inclination angle of θ; H1(0) is the liquid holdup during horizontal flow under the same flow parameters; ψ is the inclination correction coefficient; a, b, and c are constants related to the flow pattern; E1 is the inlet volume liquid holdup; N Fr is the Froude number; the calculation formula is as follows: Among them, Q1 is the inlet liquid-phase volume flow rate, with the unit of m 3 / s; Q g is the inlet gas-phase volume flow rate, with the unit of m 3 / s; D is the inner diameter of the circular tube, with the unit of mm; When the calculated pipe section is a horizontal pipe, calculate the inclination correction coefficient ψ according to formula (10); When the calculated pipe section is a vertical pipe, calculate the inclination correction coefficient ψ according to formula (11); ψ = 1 + 0.3C(11); Among them, the coefficient C is related to the inlet volume liquid holdup E1, the Froude number N Fr and the liquid phase velocity number N vl ; Calculate the liquid-phase velocity number N according to Equation (12). vl and coefficient C: where σ is the liquid surface tension; the coefficients d, e, f, g are constants; When the flow pattern is the transitional flow pattern, calculate the liquid holdup H1(θ) according to formula (13): H1(θ) = AH1(separated) + BH1(intermittent) (13); where Step 3.2: Calculate the mixed density of the gas-liquid two-phase flow; According to the liquid holdup and formula (14), calculate the actual density of the mixture: where M is the molar mass of the gas phase, in g / mol; R is the gas constant, in J / (kg·K); T is the gas temperature, in K; Z is the compressibility factor; Calculate the compressibility factor Z through formula (15): Wherein, P is the gas pressure, with the unit of MPa; Δ is the relative density of the gas; Step 3.3: Calculate the friction coefficient along the length of the gas-liquid two-phase flow; λ = e s λ′ (16); where λ is the resistance coefficient of the gas-liquid two-phase flow, dimensionless; λ′ is the resistance coefficient of the gas-liquid two-phase flow without slip, dimensionless; e is the base of the natural logarithm; s is the correlation coefficient, and s is calculated according to the following formula (17): In formula (17), y is calculated according to the following formula (18): For λ′, use the following formula (19) to calculate: where N Re is the Reynolds number for the corresponding flow regime; Step 3.4: Iteratively calculate the pressure drop of each pipe section; Divide the pipelines in the station into several pipe sections, and calculate the local friction loss and the friction loss along the length for each section; Use formula (21) to calculate the pressure drop for the horizontal pipe sections, and perform inclination correction for the vertical pipe sections; Among them, n i is the quantity of a certain pipe fitting in a certain pipe section; when the pressure drop of the pipe section is small, the pressure at the inlet position is used to calculate the density of the mixed gas; when the pipe section is long, the initial value of the inlet pressure is taken to calculate the density, and after obtaining the initial value of the pressure drop, the density is recalculated using the average pressure of both ends and iterated, and the number of iterations is determined according to the accuracy requirements; for the vertical pipe section, the pressure drop is corrected according to the correction method in the Beggs-Brill method.

4. The diagnostic and optimization method for the blockage of shale gas gathering and transportation station yard and the interference condition between high and low pressure gathering and transportation according to claim 3, wherein: The hold-up is corrected according to the flow pattern using the corresponding formula for separated flow, intermittent flow or dispersed flow, and the flow pattern is determined by the Froude number and the inlet volume liquid holdup.

5. The diagnostic optimization method for the plugging and high-low pressure gathering and transportation interference conditions of a shale gas gathering and transportation station yard according to claim 3, wherein: The determination of the degree of blockage in Step 4 includes the following steps: Step 4.1: Calculate the error between the theoretical pressure drop and the actual pressure drop. If the root mean square error exceeds the threshold, reduce the inner diameter of the pipeline and perform iterative calculations until the error meets the accuracy requirements. Calculate the error between the theoretical calculated pressure drop and the actual pressure drop according to the following formula (22): where: ΔP c is the theoretical calculated pressure drop, with the unit of Pa or MPa; ΔP a is the actual pressure drop, and the unit corresponds to the theoretical calculated pressure drop; Step 4.2: Calculate at least 6 groups of test data for each production well in the whole station, obtain the error values of each group of data, and calculate the mean error ME and the root mean square error RMSE according to the following formula (23): where e i is the error value calculated from each group of data according to Equation (22); n is the number of groups of data; Determine the blockage site according to the error sign. When ME>0 for a certain well, it means that the theoretical calculated pressure drop is greater than the actual pressure drop; when ME<0 for a certain well, the theoretical calculated pressure drop is less than the actual pressure drop. Step 4.3: Calculate the degree of blockage according to formula (24). Among them, D b is the inner diameter of the pipeline before correction, with the unit of mm; D a is the inner diameter of the pipeline after correction, with the unit of mm.

6. The diagnostic optimization method for the plugging of shale gas gathering and transportation station yard and the interference condition between high and low pressure gathering and transportation according to claim 1, characterized in that: The scheme for optimizing the gathering and transportation interference in Step 5 includes: (a) Throttling of high-pressure wells: Based on the lowest inlet pressure of the manifold, calculate the pressure after throttling of high-pressure wells in reverse. (b) Boosting of low-pressure wells: Based on the highest inlet pressure of the manifold, calculate the pressure after boosting of low-pressure wells in reverse. (c) Compromise: Adjust the throttling or boosting of some wells to balance the manifold pressure.

7. The diagnostic and optimization method for the blockage of shale gas gathering and transportation station yard and the interference condition between high and low pressure gathering and transportation according to claim 6, characterized in that: The reverse calculation uses the pressure-flow iterative method: Starting from the manifold pressure, reverse-iteratively calculate the outlet pressure of a single well according to the corrected pipeline parameters until the density error is less than 5%.

8. The diagnostic and optimization method for the plugging of shale gas gathering and transportation station yard and the interference condition of high and low pressure gathering and transportation according to claim 1, wherein: In Step 1, the first set of production data includes the pressure after throttling at the outlet of a single well, the daily gas production, the daily water production, and the gas physical property parameters.

9. The diagnostic and optimization method for the plugging and high-low pressure gathering and transportation interference conditions of a shale gas gathering and transportation station yard according to claim 1, characterized in that: The diagnosis of high and low pressure gathering and transportation interference in Step 4 includes: Based on the corrected pipeline parameters, calculate the inlet pressure of the manifold for each well. If the pressures are inconsistent, it is determined that there is gathering and transportation interference. Make the inlet pressure of the manifold consistent by adjusting the outlet pressure of a single well, and select an optimization scheme in combination with the external transmission pressure requirement.

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