Method for calculating liquid accumulation amount and flowing pressure of wellbore of high-pressure gas gathering and conveying well

Abstract

The invention relates to a high-pressure gas gathering and conveying well shaft liquid accumulation amount and flow pressure calculation method, and belongs to the field of gas production engineering. The method comprises the following steps: preparing calculation basic data; secondly, setting an initial value H1 of an equivalent liquid column height of the oil pipe accumulated liquid amount, and calculating an equivalent liquid column height H2 of the annular accumulated liquid amount according to a proportionality coefficient k; the pressure p1 and the flow pressure pwf1 at the oil pipe liquid level are calculated according to the pipe flow model, and the pressure p2 and the flow pressure pwf2 at the annulus accumulated liquid level are calculated according to the static gas column model; and if pwf1 = pwf2 is established, the equivalent liquid column height H1 of the oil pipe liquid accumulation amount is determined, the flow pressure pwf and the shaft liquid accumulation amount Q are calculated according to the gas well basic data, and if pwf1 = pwf2 is not established, the H1 set value is adjusted for iterative operation. According to the method, only gas well production report data needs to be utilized, the cost is low, logicality is high, after the data is converted into a computer program, rapid loop iteration can be automatically achieved, the wellbore liquid accumulation amount and flow pressure can be monitored in real time, drainage gas production process matching is guided in time, the gas well liquid accumulation production reduction risk is reduced, and gas well development benefits are improved.

Description

Technical Field

[0001] The invention relates to a method for calculating the amount of liquid accumulation and flow pressure in a wellbore of a high-pressure gas gathering and transmission well, and belongs to the field of gas production engineering. Background Art

[0002] Tight low-permeability gas reservoirs generally contain water without differentiation between gas and water. Once a gas well is put into production, gas and water are produced simultaneously. At the same time, the average pressure coefficient of the gas reservoir is <1, and the gas well has insufficient liquid-carrying capacity. Liquid accumulation, production reduction, and even flooding and well closure are prone to occur during production. Identifying liquid-accumulated wells and formulating a reasonable foam drainage and injection system based on the amount of liquid accumulated in the wellbore are the keys to achieving stable production of gas wells.

[0003] There are nearly 2,000 natural gas wells in the tight low-permeability gas fields of the Ordos Basin that use high-pressure gathering and transportation technology. Due to production cost constraints, it is unrealistic to use periodic flow pressure tests or generally install annular liquid level testing equipment for gas wells to monitor the amount of liquid accumulation and flow pressure in the wellbore. Therefore, a method for quantitatively calculating the amount of liquid accumulation and flow pressure in the wellbore through production data was established, which is of great significance for reducing the cost of judging the flow pressure and liquid accumulation of gas wells, improving the calculation speed, and thus being able to timely identify gas wells with liquid accumulation and matching the bubble drainage process.

[0004] For high-pressure gas gathering and transmission wells, there are currently two types of methods for determining the amount of liquid accumulated in the wellbore and the flow pressure. The first type is to monitor using devices such as infrasound or echo sounders. For example, the Chinese invention patent document with publication number CN108678729A discloses an automatic monitoring device and method for the liquid accumulation level in the wellbore of a high-pressure gas well, and the Chinese invention patent document with publication number CN208564538U discloses an automatic monitoring device for the liquid accumulation level in the wellbore of a high-pressure gas well. Both patents use the infrasound waves generated by the high-pressure gas at the wellhead to detect the liquid accumulation level in the annulus; for example, the Chinese invention patent document with publication number CN105649603A discloses a method for real-time testing of the amount of liquid accumulated in the wellbore of a gas well, using an echo sounder to monitor the height of the liquid level in the annulus; the second type is similar to the present invention, using a theoretical model to calculate the amount of liquid accumulated in the wellbore and the flow pressure For example, a Chinese invention patent document with publication number CN113338915A discloses a method for judging whether a gas well is filled with liquid and predicting the height of the liquid accumulation. The patent assumes that there is no liquid accumulation in the annulus, and calculates the bottom hole flow pressure of the wellbore without liquid accumulation and the pressure profile of the oil pipe without liquid accumulation through the static gas column. By comparing with the actual pressure profile in the oil pipe, the amount of liquid accumulated in the oil pipe is simply judged, but the amount of liquid accumulated in the annulus cannot be calculated; for example, a Chinese invention patent document with publication number CN103590812A discloses a calculation method, a calculation device and a determination method for the amount of liquid accumulated in a gas well. Although the patent calculates the amount of liquid accumulated in the annulus and the amount of liquid accumulated in the oil pipe at the same time, there is a problem of confusing the flow pressure under different states, and the flow pressure under the condition of no liquid accumulation is equivalent to the flow pressure under the condition of liquid accumulation, and then the amount of liquid accumulated in the annulus and the amount of liquid accumulated in the oil pipe are calculated separately, which is imperfect in terms of method. Summary of the invention

[0005] The purpose of the present invention is to provide a method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well, so as to solve the problem that the liquid-accumulated gas well is not discovered in time and the supporting implementation of the drainage and gas production process is not guided, resulting in liquid accumulation in the wellbore and reduced production of the gas well.

[0006] To achieve the above purpose, the steps of a method for calculating the amount of liquid accumulation and flow pressure in a wellbore of a high-pressure gas gathering and transmission well of the present invention are as follows:

[0007] 1) Complete the preparation of basic data for calculation;

[0008] 2) Set the initial value H1 of the equivalent liquid column height of the tubing liquid accumulation, and calculate the equivalent liquid column height H2 of the annular liquid accumulation according to the proportional coefficient k between H2 and H1;

[0009] 3) Using the basic data in step 1), the oil pressure p tf According to the pipe flow model, the pressure p1 at the oil pipe surface is calculated from the casing pressure p ts According to the static air column model, calculate the pressure p2 at the liquid surface in the annulus;

[0010] 4) The pressure p1 at the oil pipe surface, plus the gravity of the equivalent liquid column ρgH1 in the oil pipe, gives the flow pressure P wf1 , the pressure p2 at the annular liquid surface, plus the gravity of the equivalent liquid column ρgH2 in the annular space, we get the flow pressure p wf2 ;

[0011] 5) If p wf1 =p wf2 If the value is established, the set value is the equivalent liquid column height H1 of the oil pipe liquid accumulation, and the flow pressure p is calculated based on the basic data of the gas well. wf , the amount of liquid in the wellbore Q, if p wf1 =p wf2 If it is not true, adjust the H1 setting value and perform iterative calculation.

[0012] The method for calculating the amount of liquid accumulation and the flow pressure in the wellbore of a high-pressure gas gathering and transmission well established by the present invention does not rely on any testing device and has the characteristic of low calculation cost. At the same time, compared with other methods for calculating the amount of liquid accumulation and the flow pressure in the wellbore through theoretical models, the present invention simplifies the wellbore gas-liquid two-phase distribution pattern and introduces the ratio of the equivalent liquid column height in the annulus to the equivalent liquid column height in the oil pipe. It can simultaneously include the oil pipe accumulation and the annulus accumulation in the iterative calculation, and there is no problem of ignoring the annulus accumulation or confusing the flow pressure under different states, which is in line with actual production conditions.

[0013] Furthermore, the calculation basic data in step 1) include: the vertical height H of the wellbore, the measured length H of the wellbore m , comparison table of vertical depth and sounding of wellbore, inner diameter of casing Φ c (In the case of combined casing, there are multiple inner diameter values, recorded as Φc-1 ,…,Φ c-n ), oil pipe outer diameter Φ o1 、Inner diameter of oil pipe Φ o2 (In the case of combined tubing, refer to the case of casing and record them as Φ o1-1 ,…,Φ o1-n , Φ o2-1 ,…,Φ o2-n ), gas well casing pressure p ts 、Oil pressure tf , daily gas production q g and liquid-to-gas ratio WGR.

[0014] The present invention provides comprehensive and complete data support for subsequent calculation processes by collecting basic data required for calculation.

[0015] Furthermore, in step 2), k = H2 / H1, where H1 is the equivalent liquid column height of the tubing liquid accumulation, m; H2 is the equivalent liquid column height of the annular liquid accumulation, m. The calculation steps of H2 are as follows: Based on a large amount of measured flow pressure data of gas wells with pressure profile inflection points in the wellbore, an empirical formula for calculating the k value through casing pressure is established:

[0016] k=-0.000005p ts 5 +0.000297p ts 4 -0.007437p ts 3 +0.091081p ts 2 -0.559651p ts +1.633512;

[0017] In the formula, p ts is the wellhead casing pressure, MPa.

[0018] On the basis of setting the initial value of H1, and using the casing pressure p in the basic data ts Calculate k and get the H2 value, that is, H2=kH1.

[0019] The present invention establishes a k value calculation formula, and can calculate the equivalent liquid column height H2 of the annular liquid accumulation according to the equivalent liquid column height H1 of the oil pipe liquid accumulation, thereby avoiding direct measurement of H2 and making the calculation result more accurate.

[0020] Furthermore, in step 3), based on the initial value of H1, the oil pressure p tf , daily gas production q g and the liquid-gas ratio WGR, according to the Beggs & Brill gas-liquid two-phase pipe flow model, the pressure p1 at the oil pipe liquid surface can be calculated:

[0021]

[0022] Where: z is the distance of axial flow, m, where the integral total length of the z value is the vertical height H-H1 from the liquid level of the equivalent liquid column in the oil pipe to the wellhead based on the initial value of H1; p is the average pressure of the pipeline, MPa; ρ l is the liquid density, kg / m 3 ρ g is the gas density, kg / m 3 ;H l is the liquid holdup, m 3 / m 3 ; g is the acceleration due to gravity, m / s 2 , θ is the angle between the pipe and the horizontal, °; λ is the resistance coefficient along the two-phase flow, dimensionless; G is the mass flow rate of the mixture, m / s; v is the average flow rate of the mixture, m / s; v sg is the converted velocity of the gas, m / s; D is the diameter of the tube, m; A is the cross-sectional area of ​​the tube, m 2 .

[0023] The invention provides a specific method for calculating the pressure at the oil pipe liquid surface.

[0024] Furthermore, in step 3), based on the calculated H2 value, the casing pressure p ts According to the static air column model, the pressure p2 at the annular liquid surface can be calculated:

[0025]

[0026] Where: p2 is the annular liquid surface pressure, MPa; H is the vertical height of the wellbore, m; H-H2 is the vertical height from the annular equivalent liquid column surface to the wellhead, m; γ g is the relative density of natural gas, dimensionless; T is the average thermodynamic temperature of the static gas column in the wellbore, K; Z is the average compressibility factor of the static gas column in the wellbore, dimensionless.

[0027] The invention provides a specific method for calculating the pressure at the annular liquid accumulation surface.

[0028] Furthermore, in step 4), the flow pressure P wf1 、p wf2 The calculation formula is:

[0029] p wf1 =p1+ρgH1

[0030] p wf2 =p2+ρgH2

[0031] Where: p1 is the pressure at the liquid surface when the equivalent liquid column height in the tubing is H1, MPa; p2 is the pressure at the liquid surface when the equivalent liquid column height in the annulus is H2, MPa; ρ is the density of water, 1000kg / m3; g is the acceleration due to gravity, 9.8N / kg.

[0032] In order to improve the liquid carrying capacity of the wellbore during gas well production, the end of the oil pipe is as close to the middle depth of the reservoir as possible. The vertical height between the end of the oil pipe and the middle of the reservoir is generally <50m, and the corresponding pressure is <0.5MPa. Therefore, the vertical distance from the end of the oil pipe to the reservoir is ignored in the calculation of the present invention.

[0033] The present invention provides a specific flow pressure p wf1 、p wf2 The calculation method of .

[0034] Furthermore, in step 5), it is determined that P wf1 =p wf2 When it is established, it is necessary to calculate the flow pressure P wf , Wellbore fluid volume Q:

[0035] P wf =(p wf1 +P wf2 ) / 2

[0036] Flow pressure p wf The calculation formula needs to take into account the situation when there is no liquid accumulation in the gas well, that is, when H1 = 0, which is equivalent to the oil pressure p tf Direct calculation of bottom hole flow pressure p based on gas-liquid two-phase pipe flow model wf1 , sleeve pressure p ts Direct calculation of bottom hole flowing pressure p based on static gas column model wf2 , considering the model calculation error, there is p wf1 With p wf2 If they are not equal, take the average of the two.

[0037]

[0038] Where: Q is the amount of fluid in the wellbore, m 3 ; Φc is the inner diameter of the casing, m; Φo1 is the outer diameter of the tubing, m; Φo2 is the inner diameter of the tubing, m; H m2 When the height of the equivalent liquid column in the annulus is H2, according to the comparison table of vertical depth and sounding of the wellbore, the length of the equivalent liquid column in the annulus is m; H m1 When the height of the equivalent liquid column in the tubing is H1, according to the comparison table of vertical depth and sounding of the wellbore, the length of the equivalent liquid column in the tubing, m;

[0039] The present invention provides a specific flow pressure p wf , calculation method of wellbore liquid accumulation Q.

[0040] Furthermore, the amount of liquid accumulated in the wellbore Q is calculated. When a combined casing or a combined tubing is used, the amount of liquid accumulated in the wellbore is calculated in sections and the sum is calculated.

[0041] The present invention provides a method for calculating the amount of liquid accumulation and flowing pressure in the wellbore of a high-pressure gas gathering and transmission well, which is conducive to timely discovering high-pressure gas gathering and transmission wells with liquid accumulation in the wellbore, and calculating the amount of liquid accumulation in the wellbore and the flowing pressure, and can accurately guide the optimization and parameter design of the gas well drainage and gas production process, eliminate the liquid accumulation state in the wellbore, avoid the reduction in production due to liquid accumulation in the gas well, and improve the development efficiency of the gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] Figure 1 is a flow chart for calculating the amount of liquid accumulation and flow pressure in a wellbore in an embodiment of the method of the present invention;

[0043] Figure 2 Schematic diagram of gas-liquid two-phase distribution mode of high-pressure gas gathering and transmission well in the method embodiment of the present invention;

[0044] Figure 3 is a graph of the intersection of k value and casing pressure in the method embodiment of the present invention;

[0045] Figure 4 It is the first measured oil pipe pressure profile in the method embodiment of the present invention;

[0046] Figure 5 This is the third measured oil pipe pressure profile diagram in the method embodiment of the present invention. DETAILED DESCRIPTION

[0047] In order to make the purpose, technical solutions and advantages of the present invention more clear, the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments.

[0048] Method Example:

[0049] This embodiment provides a method for calculating the amount of liquid accumulation and flow pressure in a wellbore of a high-pressure gas gathering and transmission well. Taking Well A as an example, the well performs three rounds of calculations of the amount of liquid accumulation and flow pressure in the wellbore to guide the matching of drainage and production processes. The process is as follows: Figure 1 As shown:

[0050] Step 1) Complete the preparation of basic data for calculation;

[0051] Specifically, the basic data of Well A at three time points are prepared as shown in Table 1; the comparison table of wellbore vertical depth and sounding depth is shown in Table 2.

[0052] Table 1 Basic data preparation table for calculation of wellbore liquid loading and flow pressure

[0053]

[0054] Table 2 Comparison table of vertical depth and sounding depth of wellbore

[0055]

[0056] Step 2) setting an initial value H1 of the equivalent liquid column height of the tubing liquid accumulation, and calculating the equivalent liquid column height H2 of the annular liquid accumulation according to a proportionality coefficient k between H2 and H1;

[0057] Define the equivalent liquid column height H1 of the liquid accumulation in the tubing and the equivalent liquid column height H2 of the liquid accumulation in the annulus in step 2). For gas wells that have experienced wellbore liquid accumulation, during the production process, the annular space between the tubing and casing (referred to as the annulus) is in a static state, with a static liquid column at the bottom and a static gas column at the top; inside the tubing, under the disturbance of the airflow, there will be no pure liquid column in the tubing, but an uneven distribution pattern of a gas-water two-phase mixture with an inflection point in the pressure gradient. The pressure gradient below the inflection point reflects the discrete distribution of the liquid accumulation in the tubing under the disturbance of the airflow. This part of the liquid cannot reach the wellhead and slips off at the inflection point; the pressure gradient above the inflection point reflects the daily gas production and daily liquid production that can reach the ground and be measured. The present invention simplifies the gas-liquid two-phase distribution in the oil pipe into an equivalent pure liquid column formed by the liquid accumulation in the oil pipe at the lower part, and a uniform distribution of daily gas production and daily liquid production in the upper wellbore; similarly, the lower part of the annulus is an equivalent pure liquid column formed by the liquid accumulation in the annulus, and the upper part is a static gas column, such as Figure 2 Therefore, the vertical height of the equivalent pure liquid column formed by the tubing liquid accumulation is defined as the equivalent liquid column height H1 of the tubing liquid accumulation; the vertical height of the equivalent pure liquid column formed by the annular liquid accumulation is defined as the equivalent liquid column height H2 of the annular liquid accumulation.

[0058] The algorithm of the present invention needs to calculate the k value first, and then calculate H2, so it is necessary to establish a k value calculation formula. Figure 3 As shown in FIG, an empirical formula for calculating the k value through the casing pressure was established based on a large amount of measured flowing pressure data of gas wells with inflection points in the pressure profile of the wellbore.

[0059] Specifically, in actual production, the range of the initial value H1 of the equivalent liquid column height of the oil pipe liquid accumulation is 0-3127m. In order to better demonstrate the iterative process of the calculation method and prove that the algorithm has a unique solution, each round of calculation divides 0-3127m into 150 parts, which are used as the initial value of H1 to complete the calculation process from step 2) to step 5), as shown in Table 3. For example, on March 29, 2022, the 80th group H1 is assigned an initial value of 601m, and the k value calculated according to the k value calculation equation is 0.27, corresponding to the calculated H2 of 162m.

[0060] Step 3) Using the basic data in step 1), the oil pressure p tf According to the pipe flow model, the pressure p1 at the oil pipe surface is calculated from the casing pressure p ts According to the static air column model, calculate the pressure p2 at the liquid surface in the annulus;

[0061] Specifically, according to the basic data on March 29, 2022, when calculating the H1 assignment of the 80th group, p1 is 7.3MPa and p2 is 8.0MPa.

[0062] Step 4) Add the pressure p1 at the oil pipe surface to the gravity of the equivalent liquid column ρgH1 in the oil pipe to get the flow pressure p wf1 , the pressure p2 at the annular liquid surface, plus the gravity of the equivalent liquid column ρgH2 in the annular space, we get the flow pressure p wf2 ;

[0063] Specifically, according to the basic data on March 29, 2022, when calculating the H1 value of the 80th group, ρgH1 is 6.0MPa, p wf1 is 13.3MPa; ρgH2 is 1.6MPa, P wf2 It is 9.6MPa.

[0064] Step 5) If p wf1 =p wf2 If the value is established, the set value is the equivalent liquid column height H1 of the oil pipe liquid accumulation, and the flow pressure p is calculated based on the basic data of the gas well. wf , the amount of liquid in the wellbore Q, if p wf1 =p wf2 If it is not true, adjust the H1 setting value and perform iterative calculation.

[0065] Specifically, based on the basic data on March 29, 2022, the 80th group of H1 assignments are calculated. wf1 13.3MPa, p wf2 It is 9.6MPa, the two are not equal, and it is necessary to adjust the H1 setting value and calculate again.

[0066] Specifically, according to the calculation steps from step 2) to step 5), three rounds of calculations were completed on March 29, 2022, May 25, 2022, and October 23, 2022, 144 times in each round, and a total of 432 iterative calculations, as shown in Table 3. From the calculation results, the wellbore liquid accumulation and flow pressure calculated by the algorithm of the present invention have a unique solution, where the wellbore liquid accumulation on March 29, 2022 is 0m3 and the flow pressure is 8.2MPa; the wellbore liquid accumulation on May 25, 2022 is 1.8m3 and the flow pressure is 7.5MPa; the wellbore liquid accumulation on October 23, 2022 is 3.5m3 and the flow pressure is 7.4MPa. The degree of wellbore liquid accumulation is gradually increasing, and a matching drainage process is required.

[0067] Specifically, in order to verify the reliability of the calculation results, wellbore flow pressure profile tests were carried out on March 29, 2022 and October 23, 2022, respectively. Figure 4 , Figure 5From the test results, the flow pressure calculation error on March 29, 2022 was 2.6%, and the effusion calculation error was 0%; the flow pressure calculation error on October 23, 2022 was 5.3%, and the effusion calculation error was 12%, as shown in Table 4.

[0068] The method for calculating the amount of liquid accumulation and the flow pressure in the wellbore of a high-pressure gas gathering and transmission well established in the present invention does not rely on a certain testing device, but only needs to use the gas well production report data, and has the characteristic of low calculation cost; by simplifying the wellbore gas-liquid two-phase distribution mode, and introducing the ratio of the equivalent liquid column height in the annulus to the equivalent liquid column height in the oil pipe, the oil pipe accumulation and the annulus accumulation can be included in the iterative calculation at the same time, and there is no problem of ignoring the annulus accumulation or confusing the flow pressure under different states, which conforms to the actual production situation. After being converted into a computer program, it can automatically realize rapid cycle iteration, monitor the amount of liquid accumulation and the flow pressure in the wellbore in real time, and timely guide the matching of drainage and gas production processes, reduce the risk of reduced production due to liquid accumulation in gas wells, and improve the efficiency of gas well development.

[0069] Table 3 Basic data preparation table for calculation of wellbore liquid loading and flow pressure

[0070]

[0071] Table 4 Basic data preparation table for calculation of wellbore liquid loading and flow pressure

[0072]

Claims

1. A method for calculating the amount of liquid accumulation and flow pressure in a high-pressure gas gathering and transmission well, characterized in that: The steps include: 1) Complete the preparation of basic data for calculation; 2) Set the initial value H1 of the equivalent liquid column height of the tubing liquid accumulation, and calculate the equivalent liquid column height H2 of the annular liquid accumulation according to the proportional coefficient k between H2 and H1; 3) Using the basic data in step 1), the oil pressure p tf According to the pipe flow model, the pressure p1 at the oil pipe surface is calculated from the casing pressure p ts According to the static air column model, calculate the pressure p2 at the liquid surface in the annulus; 4) The pressure p1 at the oil pipe surface, plus the gravity of the equivalent liquid column ρgH1 in the oil pipe, gives the flow pressure p wf1 ; The pressure p2 at the annular liquid surface, plus the gravity of the equivalent liquid column ρgH2 in the annular space, gives the flow pressure P wf2 , where ρ is the density of water and g is the acceleration due to gravity; 5) If p wf1 =p wf2 If the value is established, the set value is the equivalent liquid column height H1 of the oil pipe liquid accumulation, and the flow pressure p is calculated based on the basic data of the gas well. wf , the amount of liquid in the wellbore Q; if p wf1 =p wf2 If it is not true, adjust the H1 setting value and perform iterative calculation.

2. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: The calculation basic data in step 1) include: the vertical height H of the wellbore, the measured length H of the wellbore m , comparison table of vertical depth and sounding of wellbore, inner diameter of casing Φ c 、Oil pipe outer diameter Φ o1 、Inner diameter of oil pipe Φ o2 , Gas well casing pressure p ts 、Oil pressure tf , daily gas production q g and liquid-to-gas ratio WGR.

3. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: In step 2), k=H2 / H1; the calculation steps of H2 are as follows: an empirical formula for calculating the k value through casing pressure is established based on a large amount of measured flow pressure data of gas wells with inflection points of pressure profiles in the wellbore: k=-0.000005p ts 5 +0.000297p ts 4 -0.007437p ts 3 +0.091081p ts 2 -0.559651p ts +1.633512; On the basis of setting the initial value of H1, and using the casing pressure p in the basic data ts Calculate k and get the H2 value, that is, H2=kH1.

4. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: In step 3), based on the initial value of H1, the oil pressure p tf , daily gas production q g and the liquid-gas ratio WGR, according to the Beggs & Brill gas-liquid two-phase pipe flow model, the pressure p1 at the oil pipe liquid surface can be calculated: Where: z is the distance of axial flow; p is the average pressure in the pipeline; ρl is the liquid density; ρ g is the gas density; h l is the liquid holdup; g is the gravitational acceleration, θ is the angle between the pipe and the horizontal; λ is the resistance coefficient along the two-phase flow; G is the mass flow rate of the mixture; v is the average flow rate of the mixture; v sg is the converted velocity of the gas; D is the diameter of the tube; A is the cross-sectional area of ​​the tube.

5. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: In step 3), based on the calculated H2 value, the casing pressure p ts According to the static air column model, the pressure p2 at the annular liquid surface can be calculated: Where: p2 is the annular liquid surface pressure; H is the vertical height of the wellbore; H-H2 is the vertical height from the annular equivalent liquid column surface to the wellhead; γ g is the relative density of natural gas; T is the average thermodynamic temperature of the static gas column in the wellbore; Z is the average compression factor of the static gas column in the wellbore.

6. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: In the step 4), the flow pressure p wf1 、p wf2 The calculation formula is: p wf1 =p1+ρgH1 p wf2 =p2+ρgH2 Where: p1 is the pressure at the liquid surface when the height of the equivalent liquid column in the tubing is H1; p2 is the pressure at the liquid surface when the height of the equivalent liquid column in the annulus is H2; ρ is the density of water; g is the acceleration due to gravity.

7. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 1, characterized in that: In step 5), it is determined that p wf1 =p wf2 When it is established, the flow pressure p is calculated wf , Wellbore fluid volume Q: p wf =(p wf1 +p wf2 ) / 2 Where: Q is the amount of liquid in the wellbore; Φ c is the inner diameter of the casing; Φ o1 is the outer diameter of the oil pipe; Φ o2 is the inner diameter of the oil pipe; H m2 When the height of the equivalent liquid column in the annulus is h2, according to the comparison table of vertical depth and sounding of the wellbore, the equivalent liquid column length in the annulus; H m1 When the height of the equivalent liquid column in the tubing is H1, according to the comparison table of vertical depth and sounding of the wellbore, the length of the equivalent liquid column in the tubing.

8. The method for calculating the amount of liquid accumulation and flow pressure in the wellbore of a high-pressure gas gathering and transmission well according to claim 7, characterized in that: Calculate the amount of liquid accumulated in the wellbore Q. When using combined casing or combined tubing, calculate the amount of liquid accumulated in the wellbore in sections and sum them up.

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