A vertical pipe two-phase flow pressure calculation method and system suitable for gas storage

Abstract

The application discloses a vertical pipe two-phase flow pressure calculation method and system suitable for gas storage, wherein the method comprises the following steps: inputting gas component parameters and calculating critical parameters; inputting well structure and segmenting a wellbore; fitting a temperature trinomial according to measured data; determining temperature and pressure at an entrance of a unit body; calculating initial values of iteration at the entrance of the unit body and pressure at an exit; calculating iteration values at the exit of the unit body and exit pressure; judging whether pressure error meets accuracy requirements; and segmentally completing distribution prediction of wellbore pressure. The application comprehensively considers the influence of multiple factors such as well structure and wellbore temperature, and is higher in model accuracy; on the basis of the Cullender-Smith single-phase flow wellbore pressure calculation method, the concept of liquid holdup rate is introduced according to Hagedorn-Brown, so that the fluid with less production liquid and more uniform gas-liquid mixing can be analyzed; the fitting effect is good, and the method is strong in generalizability.

Description

A method and system for calculating the pressure of two-phase flow in a vertical pipe of a gas storage facility. Technical Field

[0001] This invention relates to the field of reservoir engineering technology, and in particular to a method and system for calculating the two-phase flow pressure in a vertical pipe suitable for gas storage facilities. Background Technology

[0002] Gas storage facility operation involves a reciprocating natural gas injection and extraction process. Close monitoring of the fault caprock's sealing performance is crucial to determining and verifying the storage capacity and working gas volume, ensuring safe operation while achieving optimal working conditions. Changes in fault caprock sealing performance and storage capacity / working gas volume depend on formation pressure variations, requiring calculation of bottom hole pressure to extrapolate formation pressure. An underground gas storage facility's injection-production cycle consists of three phases: injection, shut-in, and production. Sometimes, temporary shut-in occurs during injection and production. To study the bottom hole pressure changes throughout the complete injection-production cycle, it is necessary to calculate the bottom hole flowing pressure during injection, the bottom hole static pressure during shut-in, and the bottom hole flowing pressure during production.

[0003] Previous researchers have studied many methods for calculating bottom hole pressure. Currently, commonly used methods include the average temperature and average deviation coefficient method, the numerical model method, and the Cullender-Smith method. Among these, the numerical model method includes the dry gas vertical pipe flow method and the VFPi method. The Cullender-Smith method has higher calculation accuracy than the average temperature and average deviation coefficient method because it considers the changes in temperature and deviation coefficient in the wellbore. However, the Cullender-Smith pressure calculation model can only be used for wellbore pressure calculation in single-phase gas wells and cannot be applied to gas wells with low production. The numerical model method requires historical data fitting, which can lead to significant errors due to human factors. Summary of the Invention

[0004] To address the challenges of determining wellbore pressure distribution during periodic gas injection and production operations in underground gas storage facilities, as well as the inaccurate wellbore pressure calculations caused by water production during some well production operations, this invention proposes a method and system for calculating two-phase flow pressure in vertical pipes suitable for gas storage facilities. This method comprehensively considers the gas composition of the gas storage facility, the wellbore structure, and the influence of wellbore temperature. It integrates three deviation coefficient calculation methods, two viscosity calculation methods, and two wellbore pressure calculation models. The Hagedorn-Brown method is used to modify the Cullender-Smith pressure calculation model, and liquid holdup is introduced to form a set of two-phase flow pressure calculation methods suitable for vertical pipe wells with low liquid production and relatively uniform gas-liquid mixing.

[0005] The technical solution adopted in this invention is as follows:

[0006] A method for calculating the pressure of two-phase flow in a vertical pipe of a gas storage facility includes the following steps:

[0007] S1. Input gas component parameters and calculate critical parameters;

[0008] S2. Input well structure and segment the well: According to the well structure, the well is segmented into n unit bodies at predetermined intervals, and each unit body is used as an independent control body;

[0009] S3. Fitting a temperature trinomial formula based on measured data: Based on the measured production data of each well, fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula, and calculate the temperature of each unit.

[0010] S4. Determine the temperature and pressure at the inlet of the unit cell: Determine the temperature T at the inlet of the i-th unit cell. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure P in For the temperature and pressure at the wellhead;

[0011] S5. Calculate the initial values ​​of the inlet and outlet pressures of the unit cell: based on the gas composition parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell segment. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) ;

[0012] S6. Calculate the iterative value and pressure at the unit cell outlet: based on gas composition parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit cell. out (0) Calculate the iterative value I at the unit cell exit. wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out ;

[0013] S7. Determine if the pressure error meets the accuracy requirements: Compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) Repeat steps S5 and S6; otherwise, proceed to the next step.

[0014] S8. Segmented prediction of wellbore pressure distribution: Pressure P ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Repeat steps S5 and S6 until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

[0015] Furthermore, in steps S5 and S6, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

[0016] Furthermore, in step S7, first determine |P out -P out (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

[0017] Furthermore, in step S1, the gas component parameters include mole fraction and relative molecular mass.

[0018] Furthermore, in step S1, the critical parameters include critical pressure and critical temperature.

[0019] A vertical pipe two-phase flow pressure calculation system suitable for gas storage facilities includes:

[0020] The parameter input module is configured to input gas component parameters and calculate critical parameters.

[0021] The wellbore segmentation module is configured to divide the wellbore into n unit bodies at predetermined intervals according to the wellbore structure, and to treat each unit body as an independent control body.

[0022] The temperature calculation module is configured to fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula based on the actual production data of each well, and calculate the temperature of each unit.

[0023] The temperature and pressure determination module is configured to determine the temperature T at the inlet of the i-th unit segment. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure Pin For the temperature and pressure at the wellhead;

[0024] The first calculation module is configured to calculate based on gas component parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) ;

[0025] The second calculation module is configured to calculate based on gas component parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit cell. out (0) Calculate the iterative value I at the unit cell exit. wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out ;

[0026] The error judgment module is configured to compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) If the condition is not met, proceed to the first and second calculation modules; otherwise, proceed to the distribution prediction module.

[0027] The distribution prediction module is configured to predict pressure P ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Then, the calculation proceeds to the first and second calculation modules until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

[0028] Furthermore, in the first and second calculation modules, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

[0029] Furthermore, in the error judgment module, first determine |P out -Pout (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

[0030] Furthermore, in the parameter input module, the gas component parameters include mole fraction and relative molecular mass.

[0031] Furthermore, in the parameter input module, the critical parameters include critical pressure and critical temperature.

[0032] The beneficial effects of this invention are as follows:

[0033] (1) The model has higher accuracy by comprehensively considering the influence of multiple factors such as well structure and well temperature;

[0034] (2) Based on the Cullender-Smith single-phase flow wellbore pressure calculation method, and based on the concept of liquid holdup introduced by Hagedorn-Brown, fluids with low production and relatively uniform gas-liquid mixing can be analyzed.

[0035] (3) It has a good fitting effect and strong generalizability.

[0036] In summary, this invention comprehensively considers the gas composition of the gas storage tank, the well structure, and the influence of wellbore temperature. It integrates three deviation coefficient calculation methods, two viscosity calculation methods, and two wellbore pressure calculation models. The Hagedorn-Brown method is used to modify the Cullender-Smith pressure calculation model, and liquid holdup is introduced to form a set of two-phase wellbore pressure calculation methods suitable for vertical pipes with low liquid production and relatively uniform gas-liquid mixing. Attached Figure Description

[0037] Figure 1 is a flowchart of the pressure calculation for two-phase flow in a vertical pipe provided in an embodiment of the present invention;

[0038] Figure 2 is a schematic diagram of stable one-dimensional two-phase pipe flow provided in an embodiment of the present invention;

[0039] Figure 3 is a flowchart of the iterative program calculation provided in an embodiment of the present invention;

[0040] Figure 4 is a comparison chart of the measured bottom hole pressure value and the calculated value of well XJ1 during a certain injection and production cycle provided in the embodiment of the present invention. Detailed Implementation

[0041] To provide a clearer understanding of the technical features, objectives, and effects of the present invention, specific embodiments are now described. It should be understood that the specific embodiments described herein are merely illustrative of the invention and are not intended to limit the invention; that is, the described embodiments are only a part of the embodiments of the invention, not all of them. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort are within the scope of protection of the present invention.

[0042] Example 1

[0043] This embodiment provides a method for calculating the two-phase flow pressure in a vertical pipe of a gas storage facility, as shown in Figure 1, including the following steps:

[0044] S1. Input gas component parameters and calculate critical parameters;

[0045] S2. Input well structure and segment the well: According to the well structure, the well is segmented into n unit bodies at predetermined intervals, and each unit body is used as an independent control body;

[0046] S3. Fitting a temperature trinomial formula based on measured data: Based on the measured production data of each well, fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula, and calculate the temperature of each unit.

[0047] S4. Determine the temperature and pressure at the inlet of the unit cell: Determine the temperature T at the inlet of the i-th unit cell. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure P in For the temperature and pressure at the wellhead;

[0048] S5. Calculate the initial values ​​of the inlet and outlet pressures of the unit cell: based on the gas composition parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell segment. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) ;

[0049] S6. Calculate the iterative value and pressure at the unit cell outlet: based on gas composition parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit cell. out (0) Calculate the iterative value I at the unit cell exit.wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out ;

[0050] S7. Determine if the pressure error meets the accuracy requirements: Compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) Repeat steps S5 and S6; otherwise, proceed to the next step.

[0051] S8. Segmented prediction of wellbore pressure distribution: Pressure P ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Repeat steps S5 and S6 until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

[0052] Preferably, in steps S5 and S6, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

[0053] Preferably, in step S7, first determine |P out -P out (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

[0054] Preferably, in step S1, the gas component parameters can be mole fraction and relative molecular mass, and the critical parameters can be critical pressure and critical temperature, as shown in Table 1.

[0055] Table 1 Gas composition parameters

[0056]

[0057] Preferably, as shown in Figure 2, the specific process of the vertical pipe two-phase flow pressure calculation method in this embodiment is as follows.

[0058] First, based on the fundamental equation of pressure gradient for one-dimensional steady-state pipe flow of single-phase fluid, and considering the calculation of bottom-hole flowing pressure based on wellhead pressure, the positive direction of coordinate Z is usually taken to be opposite to the flow direction, and the pipe inclination angle is defined as the angle between the pipe and the horizontal direction, as shown in Figure 3. The fundamental equation for gas-liquid two-phase pipe flow is:

[0059]

[0060] Among them, the two-phase flow mixture density ρ is composed of gravity, friction, and kinetic energy pressure gradient terms. m ρ fr In some empirical correlations, ρ and ρ are uniformly expressed as the density of the two-phase mixture under gravity, i.e., expressed by equation (2):

[0061] ρ m =ρ l H l +ρ g (1-H l (2)

[0062] Where, ρ g ρ is the gas phase density. l H is the density of the liquid phase. l This refers to the liquid holdup.

[0063] Typically, the change in kinetic energy due to increased flow velocity is small and often ignored. The mixture density ρ in the friction term... fr In some empirical formulas, the density ρ of a non-slip mixture is expressed by formula (3). ns :

[0064] ρ ns =ρ l λ l +ρ g (1-λ l (3)

[0065] Where, λ l This refers to the liquid retention rate without slippage.

[0066] Therefore, neglecting the kinetic energy term, the pressure gradient equation for vertical two-phase pipe flow is:

[0067]

[0068] The velocity v of the two-phase mixture m This represents the ratio of the total volumetric flow rate of a gas-liquid two-phase mixture to its cross-sectional area, i.e.:

[0069] v m =(q l +q g) / A (5)

[0070] Two-phase friction coefficient f m The calculation is performed using Jain's formula (6), where the two-phase Reynolds number is determined by formula (7):

[0071]

[0072]

[0073]

[0074] Where, μ m ,μ g ,μ l It is a mixture, and D is the inner diameter of the pipe.

[0075] The mixing density and flow velocity under any state (P, T) can be expressed as:

[0076]

[0077]

[0078] Substituting (9) and (10) into the pressure gradient equation (4), we get:

[0079]

[0080] Separating variables and integrating, we get:

[0081]

[0082] Second, when using the Cullender-Smith method to calculate wellbore pressure, the wellbore is typically divided into n segments for calculation. The specific methods and steps are as follows:

[0083]

[0084] in,

[0085]

[0086] If a well depth with a certain spacing is divided into n segments, then:

[0087]

[0088] The pressure calculation formula for any given segment is as follows:

[0089]

[0090] The above bottom-hole flowing pressure formula requires iterative calculation. The specific steps are as follows:

[0091] ① Divide the wellbore into n equal sections and convert the pressure at the wellhead to the bottom of the well;

[0092] ② Take P = P wh The unit entrance is calculated according to formula (14). The initial values ​​of the unit exit iteration are calculated using the modified empirical formula (17). Then, using the initial value of the iteration according to formula (14) At the output of the computing unit, I;

[0093]

[0094] ③ Calculate the unit outlet pressure P using the modified empirical formula (18). wf ,like Then P wf The value is assigned to the next wellhead pressure; otherwise, take... Repeat step ② until the accuracy requirement is met.

[0095]

[0096] Specifically, taking a gas storage facility as an example, the following data is selected from wells C4, C5, C6, C9, and C12 (with well logging interpretation data) and well XJ1 (with a bottomhole pressure gauge). The basic data are as follows: the depth of the six wells is 2500–2700 m; the tubing radius of the five wells is 76 mm; the tubing radius of XJ1 is 50.6 mm; the temperature gradient is 2℃ / 100 m; the wellhead temperature is 50–60℃; and a small amount of water is produced during gas production, ranging from 1 to 3 m³. 3 / d, natural gas specific gravity 0.65, pipe wall absolute roughness 0.016mm, water viscosity 0.8mPa·s, water density 1050kg / m³ 3 The surface tension of air and water is 0.06 N / m.

[0097] In the three different stages of gas injection, well shut-in, and gas production, the measured and calculated values ​​of the bottom hole pressure of each well were compared (Tables 2-4). Additionally, the measured and calculated values ​​of the bottom hole pressure of well XJ1 over one cycle were compared (Figure 4).

[0098] As shown in Tables 2-4 and Figure 4, the bottom-hole flowing pressure errors calculated using the method described in this embodiment are within 5%. The gas production deviation is relatively large, but it still meets the engineering calculation requirements. In Figure 4, the calculated pressures are slightly higher than the measured pressures. This may be because the wellhead and bottom-hole pressure measurements are basically accurate during strong injection and production, but the flow rate at the wellhead is very large, causing errors in the flow rate measurement. The measured flow rate used for theoretical calculation is slightly larger than the actual flow rate, resulting in a slightly larger theoretical bottom-hole pressure. If the flow rate measurement error is reduced, the difference between the theoretical and measured bottom-hole pressure values ​​will be positive or negative, but the absolute error will be smaller.

[0099] Table 2 Comparison of calculated and measured values ​​of bottom hole pressure during the gas injection stage

[0100]

[0101] Table 3 Comparison of calculated and measured values ​​of bottom hole pressure during the shut-in stage

[0102]

[0103] Table 4 Comparison of Calculated and Measured Bottomhole Pressure Values ​​During Gas Production Stage

[0104]

[0105]

[0106] Table 5 Comparison of measured bottom hole pressure values ​​and calculated values ​​using different methods

[0107]

[0108] Table 5 compares the method of this embodiment with the commonly used average temperature average compressibility coefficient method and Cullender-Smith method in engineering. It can be seen that the method used in this invention to calculate the bottom hole pressure can achieve high accuracy.

[0109] Example 2

[0110] This embodiment provides a vertical pipe two-phase flow pressure calculation system suitable for gas storage facilities, including:

[0111] The parameter input module is configured to input gas component parameters and calculate critical parameters.

[0112] The wellbore segmentation module is configured to divide the wellbore into n unit bodies at predetermined intervals according to the wellbore structure, and to treat each unit body as an independent control body.

[0113] The temperature calculation module is configured to fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula based on the actual production data of each well, and calculate the temperature of each unit.

[0114] The temperature and pressure determination module is configured to determine the temperature T at the inlet of the i-th unit segment. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure P in For the temperature and pressure at the wellhead;

[0115] The first calculation module is configured to calculate based on gas component parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) ;

[0116] The second calculation module is configured to calculate based on gas component parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit cell. out (0) Calculate the iterative value I at the unit cell exit. wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out ;

[0117] The error judgment module is configured to compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) If the condition is not met, proceed to the first and second calculation modules; otherwise, proceed to the distribution prediction module.

[0118] The distribution prediction module is configured to predict pressure P ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Then, the calculation proceeds to the first and second calculation modules until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

[0119] Furthermore, in the first and second calculation modules, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

[0120] Furthermore, in the error judgment module, first determine |P out -P out (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

[0121] Furthermore, in the parameter input module, the gas component parameters include mole fraction and relative molecular mass.

[0122] Furthermore, in the parameter input module, the critical parameters include critical pressure and critical temperature.

[0123] Example 3

[0124] This embodiment is based on embodiment 1:

[0125] This embodiment provides a computer device, including a memory and a processor. The memory stores a computer program, and the processor executes the computer program to implement the steps of the vertical pipe two-phase flow pressure calculation method applicable to gas storage tanks described in Embodiment 1. The computer program can be in the form of source code, object code, executable file, or some intermediate form.

[0126] Example 4

[0127] This embodiment is based on embodiment 1:

[0128] This embodiment provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of the vertical pipe two-phase flow pressure calculation method applicable to gas storage tanks described in Embodiment 1. The computer program can be in source code form, object code form, executable file, or some intermediate form. The storage medium includes any entity or device capable of carrying computer program code, a recording medium, a computer memory, a read-only memory (ROM), a random access memory (RAM), an electrical carrier signal, a telecommunication signal, and a software distribution medium, etc. It should be noted that the content contained in the storage medium can be appropriately added to or subtracted according to the requirements of legislation and patent practice in a jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, the storage medium does not include electrical carrier signals and telecommunication signals.

[0129] It should be noted that, for the sake of simplicity, the foregoing method embodiments are described as a series of actions. However, those skilled in the art should understand that this application is not limited to the described order of actions, as some steps may be performed in other orders or simultaneously according to this application. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions and modules involved are not necessarily essential to this application.

Claims

1. A method for calculating the pressure of two-phase flow in a vertical pipe of a gas storage facility, characterized in that, Includes the following steps: S1. Input gas component parameters and calculate critical parameters; S2. Input well structure and segment the wellbore: Based on the well structure, segment the wellbore into n unit cells at predetermined intervals, and treat each unit cell as an independent control volume; S3. Fit a temperature trinomial formula based on measured data: Based on the measured production data of each well, fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula, and calculate the temperature of each unit cell; S4. Determine the temperature and pressure at the inlet of the unit cell: Determine the temperature T at the inlet of the i-th unit cell. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure P in For the temperature and pressure at the wellhead; S5. Calculate the initial values ​​of the inlet and outlet pressures of the unit cell: based on the gas composition parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell segment. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) ; S6. Calculate the iterative value and pressure at the unit cell outlet: based on gas composition parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit cell. out (0) Calculate the iterative value I at the unit cell exit. wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out S7. Determine if the pressure error meets the accuracy requirements: Compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) Repeat steps S5 and S6; otherwise, proceed to the next step. S8. Segmented prediction of wellbore pressure distribution: Pressure P ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Repeat steps S5 and S6 until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

2. The method for calculating the two-phase flow pressure in a vertical pipe of a gas storage tank according to claim 1, characterized in that, In steps S5 and S6, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

3. The method for calculating the two-phase flow pressure in a vertical pipe of a gas storage facility according to claim 1, characterized in that, In step S7, first determine |P out -P out (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

4. The method for calculating the two-phase flow pressure in a vertical pipe of a gas storage facility according to claim 1, characterized in that, In step S1, the gas component parameters include mole fraction and relative molecular mass.

5. The method for calculating the two-phase flow pressure in a vertical pipe of a gas storage tank according to claim 1, characterized in that, In step S1, the critical parameters include critical pressure and critical temperature.

6. A vertical pipe two-phase flow pressure calculation system suitable for gas storage facilities, characterized in that, include: The parameter input module is configured to input gas component parameters and calculate critical parameters. The wellbore segmentation module is configured to divide the wellbore into n unit bodies at predetermined intervals according to the wellbore structure, and to treat each unit body as an independent control body. The temperature calculation module is configured to fit the temperature distribution curves under static, gas injection, and gas production conditions into a temperature trinomial formula based on the actual production data of each well, and calculate the temperature of each unit. The temperature and pressure determination module is configured to determine the temperature T at the inlet of the i-th unit segment. in and pressure P in Where 1≤i≤n, the initial value of i is 1, and the temperature T at the inlet of the first unit is... in and pressure P in For the temperature and pressure at the wellhead; The first calculation module is configured to calculate based on gas component parameters, critical parameters, and the pressure P at the inlet of the i-th unit cell. in Calculate the initial value I at the entrance of the i-th unit cell. wf (0) Based on the initial value I of the iteration wf (0) The modified Cullender-Smith pressure calculation model is used to calculate the initial pressure P at the outlet of the i-th unit segment. out (0) The second calculation module is configured to calculate based on gas component parameters, critical parameters, and the initial pressure P at the outlet of the i-th unit segment. out (0) Calculate the iterative value I at the unit cell exit. wf Based on the iteration value I wf The pressure P at the outlet of the i-th unit segment is calculated using the modified Cullender-Smith pressure calculation model. out The error judgment module is configured to compare the initial pressure value P. out (0) With pressure P out If the pressure error exceeds the preset accuracy threshold, then the pressure P will be adjusted. out As the initial pressure value P out (0) If the condition is not met, proceed to the first calculation module and the second calculation module; otherwise, proceed to the distribution prediction module. The distribution prediction module is configured to predict the pressure P. ou The pressure P at the entrance of the (i+1)th unit segment in The temperature T at the inlet of the (i+1)th unit cell is calculated using the temperature trinomial formula. in Then, the calculation proceeds to the first and second calculation modules until the pressure at the outlet of the nth unit is calculated, thus completing the prediction of the pressure distribution throughout the wellbore.

7. The vertical pipe two-phase flow pressure calculation system for gas storage tanks according to claim 6, characterized in that, In the first and second calculation modules, the method for generating the modified Cullender-Smith pressure calculation model includes: modifying the Cullender-Smith pressure calculation model using the Hagedorn-Brown method and introducing liquid holdup to calculate the two-phase vertical pipe flow wellbore pressure.

8. A vertical pipe two-phase flow pressure calculation system suitable for gas storage tanks according to claim 6, characterized in that, In the error judgment module, first judge |P out -P out (0) | / P out Check if ≤ε is true, where ε is a preset precision threshold; if yes, proceed to the next step; otherwise, reduce pressure P. out As the initial pressure value P out (0) Repeat steps S5 and S6.

9. A vertical pipe two-phase flow pressure calculation system suitable for gas storage tanks according to claim 6, characterized in that, In the parameter input module, the gas component parameters include mole fraction and relative molecular mass.

10. A vertical pipe two-phase flow pressure calculation system suitable for gas storage tanks according to claim 6, characterized in that, In the parameter input module, the critical parameters include critical pressure and critical temperature.

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