A method for diagnosing liquid accumulation depth in throttling gas wells based on pressure profile method

Abstract

The present invention discloses a method for diagnosing the depth of liquid accumulation in a throttling gas well based on a pressure profile method, and belongs to the field of oil and gas production engineering. The method comprises the following steps: using a static gas column pressure drop model to calculate the pressure at the pipe shoe of the oil pipe, and obtaining the pressure profile in the casing; according to the pressure and temperature at the pipe shoe, in combination with a multiphase flow model, calculating the liquid column profile of the accumulated liquid from the pipe shoe upward; using a multi-phase pipe flow pressure drop calculation method and a nozzle flow pressure drop calculation method to calculate the pressure drop in the oil pipe, and obtaining the pressure drop profile of the oil pipe; calculating the pipe shoe pressure of the oil pipe downward according to the casing pressure, calculating the gas-liquid two-phase flow pressure distribution line B of the liquid accumulation section upward along the oil pipe according to the pipe shoe pressure, and calculating the flowing gas-liquid two-phase flow pressure distribution line A downward along the oil pipe according to the oil pressure and wellhead production data; obtaining the intersection point h of line A and line B as the depth of liquid accumulation. The present invention diagnoses the actual liquid accumulation situation of the throttling gas well through the pressure profile curve, formulates flexible timing for salvaging the throttling device and draining gas production, and achieves the best production efficiency.

Description

Technical Field

[0001] The invention belongs to the field of oil and gas production engineering, and in particular relates to a method for diagnosing liquid accumulation depth in a throttling gas well based on a pressure profile method. Background Art

[0002] Downhole throttling technology can reduce surface pipeline pressure, prevent hydrate formation, and simplify surface gathering and transportation processes. It is a key technology for low-cost and efficient exploitation of gas fields. However, when the gas well enters the low-pressure and low-production stage, the downhole throttling device limits the gas well's production capacity, aggravates the wellbore liquid accumulation phenomenon, and even makes it difficult to implement the drainage gas production process. Therefore, it is necessary to choose a reasonable time to salvage the throttling device, further release production capacity while ensuring safe production, and help the gas well remove liquid accumulation and resume production.

[0003] The downhole choke limits the depth of the detector, and the liquid accumulation profile under the choke cannot be detected. This patent analyzes the pressure profile of the choked gas well, uses the pressure drop difference between the gas-liquid two-phase flow and the liquid column to calculate the liquid accumulation depth of the choked gas well, realizes the gas well liquid accumulation diagnosis, and provides a basis for the selection of subsequent drainage and gas production measures. 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 the liquid accumulation depth in a throttling gas well based on the pressure profile method, which has a reasonable design, overcomes the shortcomings of the prior art, and has good effects.

[0005] In order to achieve the above-mentioned purpose, the present invention adopts the following technical scheme: a method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method, comprising the following steps: Step 1: Calculate the pressure at the tube shoe of the oil pipe using a static gas column pressure drop model to obtain a pressure profile inside the casing; Step 2: Calculate the liquid column profile of the liquid accumulation from the tube shoe upwards according to the pressure and temperature at the tube shoe calculated in step 1 in combination with a multiphase flow model; Step 3: Calculate the pressure drop inside the oil pipe using a multi-phase pipe flow pressure drop calculation method and a nozzle flow pressure drop calculation method to obtain a pressure drop profile of the oil pipe; Step 4: Calculate the tube shoe pressure of the oil pipe downwards according to the casing pressure, calculate the gas-liquid two-phase flow pressure distribution line B of the liquid accumulation section upwards along the oil pipe according to the tube shoe pressure, and calculate the flowing gas-liquid two-phase flow pressure distribution line A downwards along the oil pipe according to the oil pressure and wellhead production data; Step 5: Obtain the intersection point h of line A and line B as the liquid accumulation depth.

[0006] Preferably, step 1 includes the following steps: step 1.1: input initialization parameters; step 1.2: read well depth and well inclination data; step 1.3: obtain temperature gradient; step 1.4: calculate gas compression factor; calculate the gas compression factor by iterative method according to the humidity type and relative density parameters of the gas; step 1.5: solve the pressure at the tube shoe.

[0007] Preferably, in step 1.1, the initial test parameters include the wellhead pressure P wh 、Daily gas production Q g 、Daily liquid output Q l , wellhead temperature T wh , casing inner diameter rci, casing outer diameter rco, tubing outer diameter rto, tubing diameter D, natural gas relative density Water Density , Natural gas viscosity , water viscosity , thermal conductivity W / (m·K) and gas types including dry gas and wet gas.

[0008] Preferably, in step 1.2, an Excel format file is used to store the well section data, including the length data1 and the well inclination angle data2 of each well section; the file is imported through the file selection dialog box, and the well section length difference and the well section inclination angle are stored in the data1 and data2 arrays respectively.

[0009] Preferably, in step 1.3, the temperature gradient is calculated according to formula (1): (1); among which, for Temperature at the section (℃); is the number of well depth sections; is the number of well depths read; is the depth of the i-th segment; For the first ( ) The depth of the segment; is the ground temperature.

[0010] Preferably, step 1.5 specifically includes the following steps: Step 1.5.1: Comprehensively consider the effects of temperature, gravity and inclination angle on pressure, calculate the pressure drop of each section, and the pressure calculation formula is: ;in, is the pressure drop of each section, For the The gas density of the segment, is the ground temperature, For the The depth of the segment, is the corresponding well inclination angle, is the wellhead casing pressure, is the corresponding compression factor; Step 1.5.2: Accumulate the pressure at the tube shoe ;in, For the The pressure at the deepest part of the well.

[0011] Preferably, step 2 includes the following steps: step 2.1: initializing constants and input parameters; the input parameters include bottom hole flow pressure Pwf, gas flow rate Qg and bottom hole temperature Tec; step 2.2: reading well depth and well inclination data; inverting and processing the data using the NumPy library; step 2.3: setting the initial values ​​of wellbore pressure and temperature; flipping the read well depth and well inclination data and storing them in data11 and data21; initializing the pressure array and temperature array, and setting the pressure Pwf at the shoe and the bottom hole temperature Tec as the initial values; step 2.4: multiple flow calculations; step 2.5: temperature and pressure coupling equations; the temperature and pressure coupling calculation of each section in the wellbore is realized by the fourth-order Runge-Kutta method.

[0012] Preferably, step 2.5 includes the following steps: Step 2.5.1: Calculate the thermal conduction time constant At of the fluid: ;in, : specific heat capacity, the unit is J / (kg·K), : Mass flow rate of the mixed liquid, in kg / s, : The radius inside the wellbore, in meters; : Thermal conductivity, which indicates the heat transfer when the fluid flows

[0013] Coefficient, unit is W / (m²·K); : temperature ratio; : Thermal conductivity of the pipe wall, unit is W / (m·K).

[0014] .

[0015] .

[0016] .

[0017] .

[0018] in, For the The temperature of the well section, is the well inclination angle of the corresponding well section, g is the gravitational acceleration, is the superficial velocity of the mixed fluid, is the superficial velocity of the gas, is the deepest pressure in the i-th well section, is the viscosity of the mixed fluid, is the pressure drop in the well section, is the depth of the well section; finally The update formula is ; Where K1, K2, K3, and K4 are the slopes of temperature changes at different time points; Step 2.5.2: Use the temperature and pressure distribution to calculate the density, viscosity, and other thermodynamic properties of the fluid in each well section to obtain an accurate temperature gradient.

[0019] Preferably, step 3 includes the following steps: step 3.1: data reading and preprocessing; step 3.2: obtaining the liquid velocity coefficient; step 3.3: calculating the liquid content of the inlet volume and the Froude number N Fr(i) , determine the flow pattern and solve the gas-liquid two-phase holdup; Step 3.4: Calculate the resistance coefficient ; Step 3.5: Calculate the pressure gradient.

[0020] The beneficial technical effects brought about by the present invention are as follows: the present invention invents a solution for diagnosing the depth of liquid accumulation in throttling gas wells, diagnoses the actual liquid accumulation situation of throttling gas wells through pressure profile curves, formulates flexible timing for salvaging throttling devices and draining water for gas production, and achieves optimal production benefits. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 This is a schematic diagram of a throttling gas well; Figure 2 Schematic diagram of the mouth flow model; Figure 3 is the mouth flow characteristic curve; Figure 4 is a schematic diagram of casing pressure profile; Figure 5 This is a schematic diagram of throttling wellbore pressure drop; Figure 6 This is a schematic diagram of the temperature drop in the throttling wellbore; Figure 7 This is a schematic diagram of casing effusion; Figure 8 This is a schematic diagram of fluid accumulation in the oil pipe; Fig. 9 This is a schematic diagram of just no fluid accumulation; Fig.10 This is a schematic diagram of the output results. DETAILED DESCRIPTION

[0022] The present invention is further described in detail below in conjunction with the accompanying drawings and specific implementation methods: In theory, the wellbore of a gas well without a packer is a U-shaped connecting pipe, and the casing annulus is a static fluid. If the pressure difference between the casing and the tubing can allow all the liquid in the casing annulus to enter the tubing, that is, the casing annulus is a pure gas column, then the pressure drop profile can be calculated according to the static gas column pressure drop model. Since the static gas column pressure drop gradient is small, the calculation result is consistent with the actual situation, so it can be regarded as a true value; and the pressure drop profile in the tubing can be calculated according to the continuous liquid-carrying gas-liquid two-phase flow pressure drop model in the throttling gas well. According to the pipe shoe pressure, the gas-liquid two-phase flow pressure distribution of the liquid accumulation section is calculated upward along the tubing, and the intersection of the two pressure profile lines in the tubing is the liquid accumulation page depth.

[0023] Figure 1 Schematic diagram of a throttling gas well.

[0024] According to the gas-liquid distribution state in the wellbore after the throttling gas well liquid accumulation, a wellbore liquid accumulation height calculation model is established.

[0025] Assumptions: (1) The main liquid produced by liquid accumulation in gas wells is water; (2) There is no production in the casing annulus and the production time is long enough, so the annulus is pure gas; (3) Stable production is achieved using tubing, and the liquid level in the tubing of the liquid accumulation well can be considered to be a stable two-phase flow with a larger gas production and a smaller industry.

[0026] Considering the influence of the throttle on the gas-liquid flow in the tubing, the tubing shoe pressure, the height of the accumulated liquid at the lower end of the throttle and the position of the accumulated liquid level are calculated using the ground casing pressure, oil pressure, gas production, water production and throttle parameters.

[0027] Step 1: Use the static gas column pressure drop model to calculate the pressure at the tubing shoe and obtain the pressure profile inside the casing (such as Figure 4 The pressure at the casing shoe is equal to the pressure at the tubing shoe.

[0028] Furthermore, the step 1 includes the following steps: Step 1.1: Input initialization parameters; wherein the input initialization parameters include the wellhead pressure P wh 、Daily gas production Q g 、Daily liquid output Q l , wellhead temperature T wh , casing inner diameter rci, casing outer diameter rco, tubing outer diameter rto, tubing diameter D, natural gas relative density Water Density , Natural gas viscosity , water viscosity , thermal conductivity W / (m·K) and gas type (dry gas, wet gas).

[0029] Step 1.2: Read the well depth and well inclination angle data; use Excel format file to store well section data, including the length data1 and well inclination angle data2 of each well section, so as to refine the wellbore pressure drop calculation. Import the file through the file selection dialog box, and store the well section length difference and well section inclination angle in data1 and data2 arrays respectively.

[0030] Corrected well inclination ; Calculate the segment length, denoted as delta_h ( )( =1, 2, 3…n). (the difference between each adjacent well depth); read the well depth section number and record it as ( =1, 2, 3…n). ( is the number of well depths read).

[0031] Step 1.3: Calculate the temperature gradient; where: . for The temperature at the section (°C).

[0032] Step 1.4: Calculation of gas compressibility factor: Calculate the gas compressibility factor by iterative method according to the humidity type, relative density and other parameters of the gas. The specific steps are as follows: Step 1.4.1: Calculation of critical parameters: If the gas is wet gas, when the relative density is less than 0.7, a0, a1, b0, b1 are: 106, 152.22, 4778, -248.21 respectively; when the relative density is greater than 0.7, a0, a1, b0, b1 are: 132, 116.67, 5102, -689.48 respectively.

[0033] If the gas is dry gas, when the relative density is less than 0.7, a0, a1, b0, b1 are respectively: 92, 176.67, 4778, -248.21. When the relative density is greater than 0.7, a0, a1, b0, b1 are respectively: 92, 176.67, 4881, -386.11.

[0034] Step 1.4.2: Temperature calculation: Calculate according to the temperature gradient.

[0035] Step 1.4.3: Iterative calculation of the compressibility factor z: First, solve for the critical temperature : .

[0036] Furthermore, solving the relative temperature : .

[0037] Furthermore, the critical pressure is solved : .

[0038] Further, solving for the relative pressure : .

[0039] Furthermore, a for loop is used to solve Z, where Z(0)=1. It is assumed that the gas is close to an ideal gas in the first step. In each iteration, the Z value of the previous round is used to calculate the gas corrected density. .

[0040] Furthermore, a more accurate Z value is calculated; .

[0041] Furthermore, after 10 cycles, Z[9] is taken as the final result Z final , it is considered that Z has converged at this time.

[0042] Furthermore, the natural gas density at the well depth i is calculated / m3 .

[0043] in, ; is the air density. is the relative density of the gas, is the ground temperature;

[0044] Step 1.5: Solve the pressure at the tube shoe; First, consider the effects of temperature, gravity and inclination on pressure, calculate the pressure drop and pressure at each section The calculation formula is: ;in, is the pressure drop of each section, For the The gas density of the segment, is the ground temperature, For the The depth of the segment, is the corresponding well inclination angle, is the wellhead casing pressure, is the corresponding compression factor; the pressure at the tube shoe is accumulated : .

[0045] in, For the The pressure at the deepest part of the well.

[0046] Step 2: The pressure and temperature at the tube shoe calculated in step 1 are combined with the multiphase flow model to calculate the liquid column profile from the tube shoe upward.

[0047] Step 2.1: Initialize constants and input parameters, input bottom hole pressure Pwf, gas flow rate Q g , bottom hole temperature Tec.

[0048] Step 2.2: Read the well depth and well inclination data; use the NumPy library to invert and process the data so that the liquid column curve can be drawn from the bottom of the well upward.

[0049] Step 2.3: Set the initial values ​​of wellbore pressure and temperature; flip the read well depth and well inclination data and store them in data11 and data21; delta_h represents the calculation segment length, that is, the height difference of each well depth, and θ represents the well inclination angle of each wellbore segment.

[0050] Initialize the pressure array and temperature array, and set the pressure Pwf and temperature Tec at the tube shoe to initial values.

[0051] Step 2.4: Multiple flow calculations; where the gas phase local flow rate is Q gi， ; Further, the liquid phase in situ flow rate is Q l(i) , .

[0052] First, calculate the superficial velocity of the multiphase flow: Among them, the superficial velocity of the gas phase is , ; Furthermore, the superficial velocity of the liquid phase , ; Further, the superficial velocity of the mixture , ; Among them, the inlet volume liquid content ; Where A is the apparent area (m 2 ). .

[0053] Furthermore, the viscosity of the mixture , ; Among them, gas viscosity , Liquid viscosity .

[0054] According to the inlet volume liquid content 、 Froude number N Fr(i) The gas-liquid two-phase holdup H is obtained by the flow pattern (i) .

[0055] The calculation of gas density at well depth i is the same as step 1.4. The density of liquid at well depth i is: .

[0056] The density of the mixed fluid is ρ m（i） = ρ l（i） ×H （i） +ρ g（i） × (1-H （i） )ρ l and ρ g are the densities of liquid and gas respectively.

[0057] Step 2.5: Calculate the pressure drop of the liquid column; Step 2.5.1: Calculate the friction pressure drop (ΔP) using the Darcy-Weisbach equation f ), and corrected in combination with the flow characteristics of the gas-liquid mixture: ;in, is the pressure drop of the i-th section, is the mixed friction coefficient, is the density of the mixture in the i-th section, is the superficial velocity of the mixture in the i-th section, and D is the inner diameter of the oil pipe, which is used to solve the friction factor: ;in, / D is relative roughness; is the Reynolds number of the mixture.

[0058] Step 2.5.2: Calculate the gravitational pressure drop ΔP according to the well deviation angle and the fluid distribution in the wellbore g ; ; where is the well deviation angle corresponding to the i-th well section, is the well depth corresponding to the i-th well section.

[0059] Step 2.5.3: Combine the frictional pressure drop and the gravitational pressure drop to obtain the total pressure drop ΔP, .

[0060] Step 2.5.4: Starting from the bottom hole pressure (Pwf), recursively calculate the total pressure drop section by section upward along the wellbore: .

[0061] When the depth reaches the choke depth, stop the iteration. Thus, the liquid column pressure starting from the bottom hole is obtained.

[0062] Step 3: Calculate the pressure drop in the tubing using the multi-phase flow pressure drop calculation method and the nozzle flow pressure drop calculation method to obtain the tubing pressure drop profile.

[0063] Step 3.1: Data reading and preprocessing; read the depth and well deviation angle data; data difference and segmentation: insert the choke depth at a specific depth, divide the data into two parts before and after the nozzle, and calculate the pressure drop of the choke using the Perkins nozzle flow model here.

[0064] As Figure 2 shown, the specific calculation process using the Perkins model is as follows: First, input the relevant parameters: upstream pipe diameter (or A1), gas nozzle diameter, downstream pipe diameter (or downstream cross-sectional area A2), upstream pressure p1, mass flow rate, gas specific weight (gas relative molecular mass), gas holdup f g . First, assume the flow regime. If P3 > P2, it is subcritical flow, P r = P3 / P1 If P3 = P2, it is transitional flow, P r = P3 / P1 = P2 / P1 If P3 < P2, it is critical flow, Pr = P2 / P1.

[0065] In the calculation of the Perkins model, its mass flow rate expression is as follows: ; where w i is the mass flow rate, with the unit of kg / s; p r is the critical pressure ratio; p1 is the pressure before the choke nozzle, in Pa; A1 is the inner diameter of the tubing, in mm; A2 is the throat diameter of the choke nozzle, in mm; f g is the gas holdup; is the specific volume upstream of the choke.

[0066] ; .

[0067] in, is the liquid content, M is the relative molecular mass, Z is the compression factor, and R is a constant.

[0068] Figure 3 is the nozzle flow characteristic curve.

[0069] Furthermore, based on the upstream pressure and temperature, the density, compressibility factor, adiabatic index k of the gas phase can be calculated, the specific heat capacity of the gas phase at constant pressure and constant volume can be calculated, the amount of gas phase dissolved in the oil phase, that is, the dissolved gas-oil ratio, the mass fraction of the water phase, and the polytropic expansion index value n can be calculated.

[0070] Gas phase specific heat at constant pressure and specific heat at constant volume: ; ; Adiabatic index: ; Variable expansion index n: ; ; The formula for solving Pr is:

[0071] .

[0072] In this way, the pressure drop at the throttle is calculated: the depth changes of "before the mouth" and "after the mouth" are calculated by data segmentation. The Beggs-Brill multiphase flow pressure drop model is used to calculate the pressure drop both "before the mouth" and "after the mouth".

[0073] First, the superficial velocity of the multiphase flow is calculated; the superficial velocity of the gas phase is , .

[0074] Furthermore, the superficial velocity of the liquid phase , .

[0075] Furthermore, the superficial velocity of the mixture , .

[0076] Among them, the inlet volume liquid content .

[0077] Where A is the apparent area (m 2 ), .

[0078] Furthermore, the viscosity of the mixture , ; Among them, gas viscosity , Liquid viscosity .

[0079] According to the inlet volume liquid content 、 Froude number NFr(i) The gas-liquid two-phase holdup H is obtained by the flow pattern (i) .

[0080] Step 3.4: Calculate the drag coefficient .

[0081] First, calculate the constant : .

[0082] Furthermore, the coefficients are calculated : .

[0083] Furthermore, the Reynolds coefficient is calculated : Reynolds coefficient ; where d is the constant corresponding to different flow types, and the coefficient .

[0084] Furthermore, the drag coefficient is calculated ; where e is the base of natural logarithms.

[0085] Step 3.5: Calculate the pressure gradient.

[0086] Use the Beggs-brill pressure drop method to calculate the pressure drop in the oil pipe: ; where ρ g[i] is the density of the gas phase in the ith segment, in m·s -1 ;p [i] is the deepest pressure in the i-th well section, in Pa; ρ l[i] is the density of the liquid phase in the i-th segment, in m·s -1 ; W m is the mass flow rate, in kg·s -1 , A is the pipe area.

[0087] Step 3.6: Use the coupled calculation of the pressure drop and temperature drop in the wellbore.

[0088] The temperature drop model here uses the Hasan-Kabir model, because both the temperature drop and pressure drop models can be expressed as functions of depth delta_h, pressure p and temperature T, so a set of equations can be established.

[0089] .

[0090] The fourth-order Runge-Kutta method with higher computational accuracy is used for numerical solution. By setting the step size z and the known initial value ( , p0, T0) and the pressure drop and temperature drop functions F1 and F2, we can calculate the required numerical solution: ; .

[0091] ; .

[0092] final The update formula is .

[0093] Further, , and the settlement is circulated. When the calculation reaches the throttle position, the Perkins model is used to calculate the pressure drop at the throttle. Then this method is continued to be used to calculate the pressure drop, and the settlement ends at the pipe shoe.

[0094] Thus, the pressure drop curve A and the temperature drop curve inside the oil pipe are obtained.

[0095] Figure 5 This is a schematic diagram of throttling wellbore pressure drop; Figure 6 This is a schematic diagram of the temperature drop in the throttling wellbore; Figure 7 This is a schematic diagram of casing effusion; Figure 8 This is a schematic diagram of fluid accumulation in the oil pipe; Fig. 9 This is a schematic diagram of just no fluid accumulation.

[0096] Step 4: Calculate the tubing shoe pressure downward based on the casing pressure, calculate the gas-liquid two-phase flow pressure distribution line B in the liquid accumulation section upward along the tubing based on the shoe pressure, and calculate the flowing gas-liquid two-phase flow pressure distribution line A downward along the tubing based on the oil pressure and wellhead production data.

[0097] Step 5: The intersection point h of line A and line B is the depth of effusion.

[0098] The present invention will be further described below in conjunction with examples.

[0099] The present invention proposes a method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method. There is a throttling gas well on site, the outer diameter of the casing of the gas well is 139.7MPa, the inner diameter is 114.3mm, the outer diameter of the oil pipe is 60.3mm, the inner diameter is 50.66mm, the wellhead oil pressure is 3.5MPa, the casing pressure is 8.2MPa, the gas production is 10,000 cubic meters, the water production is 1 cubic meter, the throttling nozzle diameter is 3.1mm, the depth is 1800m, the wellhead temperature is room temperature, and the relative density of natural gas is Water Density , Natural gas viscosity , Liquid viscosity The formation thermal conductivity is 1.72 W / (m·K), and the natural gas type is dry gas. The imported well depth and well deviation data are shown in Tables 1 and 2.

[0100] Table 1: Imported well depth and deviation data

[0101] .

[0102] Table 2: Imported well depth and deviation data

[0103] .

[0104] The output is as follows Fig.10 shown.

[0105] The final output of the effusion depth is 2558.47m. While judging the effusion depth, the commonly used effusion depth diagnosis method (velocity profile method) is used on site, and the Li Min model is modified to judge the effusion condition to verify the accuracy of this patent.

[0106] Since it is impossible to verify whether there is liquid accumulation below the choke, the 14 wells without liquid accumulation above the choke determined by the flow pressure test analysis were diagnosed using the currently commonly used velocity profile method. The accuracy of the velocity profile method in the diagnosis of the choke reached 92.9%, and only one well was misdiagnosed. The diagnostic results of this method and the velocity profile method below the choke were compared. The results of the diagnosis of this method were consistent with those of the velocity profile method, and the liquid accumulation depth was given for the liquid accumulation well. The test wells are shown in Table 3.

[0107] Table 3: Test well examples

[0108] .

[0109] 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 technicians in this technical field within the essential scope of the present invention should also fall within the protection scope of the present invention.

Claims

1. A method for diagnosing the depth of liquid accumulation in a throttling gas well based on a pressure profile method, characterized in that: The steps include: Step 1: Calculate the pressure at the tubing shoe using the static gas column pressure drop model to obtain the pressure profile inside the casing; Step 2: Based on the pressure and temperature at the tube shoe calculated in step 1, combined with the multiphase flow model, calculate the liquid column profile from the tube shoe upward; Step 3: Calculate the pressure drop in the oil pipe using multiple pipe flow pressure drop calculation methods and nozzle flow pressure drop calculation methods to obtain the oil pipe pressure drop profile; Step 4: Calculate the tubing shoe pressure downward based on the casing pressure, calculate the gas-liquid two-phase flow pressure distribution line B of the liquid accumulation section upward along the tubing based on the shoe pressure, and calculate the flowing gas-liquid two-phase flow pressure distribution line A downward along the tubing based on the oil pressure and wellhead production data; Step 5: The intersection point h of line A and line B is the depth of effusion.

2. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 1 is characterized by: Step 1 includes the following steps: Step 1.1: Input initial test parameters; Step 1.2: Read the well depth and well inclination angle data; Step 1.3: Calculate the temperature gradient; Step 1.4: Calculation of gas compressibility factor; According to the humidity type and relative density parameters of the gas, the compressibility factor of the gas is calculated by an iterative method; Step 1.5: Solve for the pressure at the tube shoe.

3. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 2 is characterized by: In step 1.1, the initial test parameters include the wellhead pressure P wh 、Daily gas production Q g 、Daily liquid output Q l , wellhead temperature T wh , casing inner diameter rci, casing outer diameter rco, tubing outer diameter rto, tubing diameter D, natural gas relative density Water Density , Natural gas viscosity , water viscosity , thermal conductivity W / (m·K) and gas types including dry gas and wet gas.

4. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 2 is characterized by: In step 1.2, an Excel format file is used to store the well section data, including the length data1 and the well inclination angle data2 of each well section; the file is imported through the file selection dialog box, and the well section length difference and the well section inclination angle are stored in the data1 and data2 arrays respectively.

5. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 2 is characterized by: In step 1.3, the temperature gradient is calculated according to formula (1): （1）； in, for Temperature at the section (℃); is the number of well depth sections; is the number of well depths read; is the depth of the i-th segment; For the first ( ) The depth of the segment; is the ground temperature.

6. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 2 is characterized by: Step 1.5 specifically includes the following steps: Step 1.5.1: Considering the effects of temperature, gravity and inclination on pressure, calculate the pressure drop of each section. The pressure calculation formula is: ； in, is the pressure drop of each section, For the The gas density of the segment, is the ground temperature, For the The depth of the segment, is the corresponding well inclination angle, is the wellhead casing pressure, is the corresponding compression factor; Step 1.5.2: Add up the pressure at the tube shoe: ； in, For the The pressure at the deepest part of the well.

7. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 1 is characterized by: Step 2 includes the following steps: Step 2.1: Initialize constants and input parameters; The input parameters include bottom hole flowing pressure Pwf, gas flow rate Qg and bottom hole temperature Tec; Step 2.2: Read the well depth and well inclination angle data; Use the NumPy library to invert and process the data; Step 2.3: Setting the initial values ​​of wellbore pressure and temperature; The well depth and well inclination angle data read out are flipped and stored in data11 and data21; Initialize the pressure array and temperature array, and set the pressure Pwf at the pipe shoe and the bottom hole temperature Tec to the initial values; Step 2.4: Multiple flow calculations; Step 2.5: Couple the temperature and pressure equations; The temperature and pressure coupling calculation of each section in the wellbore is realized by the fourth-order Runge-Kutta method.

8. The method for diagnosing the depth of liquid accumulation in a throttling gas well based on the pressure profile method according to claim 7 is characterized by: Step 2.5 includes the following steps: Step 2.5.1: Calculate the heat transfer time constant At of the fluid: ； in, : specific heat capacity, the unit is J / (kg·K); : Mass flow rate of the mixed liquid, in kg / s; : The radius inside the wellbore, in meters; : Thermal conductivity, unit is W / (m²·K); : temperature ratio; : Thermal conductivity of the tube wall, in W / (m·K); ； ； ； ； in, For the The temperature of the well section, is the well inclination angle of the corresponding well section, g is the gravitational acceleration, is the superficial velocity of the mixed fluid, is the superficial velocity of the gas, is the deepest pressure in the i-th well section, is the viscosity of the mixed fluid, is the pressure drop in the well section, is the depth of the well section; final The update formula is ； Among them, K1, K2, K3, and K4 are the slopes of temperature changes at different time points; Step 2.5.2: Use the temperature and pressure distributions to calculate the density, viscosity, and other thermodynamic properties of the fluid in each well section to derive accurate temperature gradients.

9. The method for diagnosing liquid accumulation depth in a throttling gas well based on the pressure profile method according to claim 1, characterized in that: Step 3 includes the following steps: Step 3.1: Data reading and preprocessing; Step 3.2: Calculate the liquid velocity coefficient; Step 3.3: According to the inlet volume liquid content and Froude number N Fr(i) , determine the flow pattern and solve the gas-liquid two-phase holdup; Step 3.4: Calculate the drag coefficient ; Step 3.5: Calculate the pressure gradient.

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