Method for determining water breakthrough time of gas well in water-bearing gas reservoir based on wellhead pressure

Abstract

The application discloses a method for determining water breakthrough time of a gas well in a water-bearing gas reservoir based on wellhead pressure, and relates to the technical field of oil and natural gas development.The method comprises the following steps: obtaining basic parameters of the gas well; determining formation pressure corresponding to different production times in the production process; calculating binomial productivity equation coefficients of the gas well at different times under water-free conditions; further calculating wellhead oil pressure or wellhead casing pressure at different production times under water-free conditions; comparing the wellhead oil pressure or wellhead casing pressure at different production times under water-free conditions with actual wellhead oil pressure or wellhead casing pressure; and determining the water breakthrough time of the gas well, wherein the wellhead casing pressure comprises wellhead casing pressure without an oil pipe and wellhead casing pressure with an oil pipe. The application adopts a method for comparing theoretical calculation of oil casing pressure with actual pressure to identify the water breakthrough start time of the gas well under water-free conditions. The method is simple and fast, accurate in prediction, good in error data processing effect, capable of covering the whole production stage of the gas reservoir in the identification range, and wide in application range.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, specifically to a method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure. Background Technology

[0002] In the development of water-bearing gas reservoirs, water production issues can adversely affect the normal production of gas wells. Once water is encountered in a gas well, the bottomhole flowing pressure increases, gas flow is obstructed, leading to a decrease in production capacity and affecting the energy utilization of the gas reservoir. If the water ingress time is not identified in a timely manner, production systems and drainage measures may lag behind, exacerbating the damage caused by water intrusion. Accurately determining the water ingress time of a gas well provides a basis for timely adjustments to the production plan, optimization of production pressure differentials, and the formulation of waterproofing and drainage measures. This can slow down the water production process, maintain stable and efficient production of the gas well, reduce the adverse effects of water intrusion on gas reservoir development, and is of great significance for achieving economical and efficient gas reservoir exploitation.

[0003] In the early stages of developing water-bearing gas reservoirs, wellhead productivity decline is typically driven by reservoir depletion. However, as production progresses, formation water may begin to impact reservoir pressure systems and productivity dynamics even before significant wellbore fluid accumulation occurs. Existing research and identification methods primarily focus on identifying wellbore fluid accumulation. Dynamic analysis methods are the most widely used in the field. These methods identify the onset of water impact on gas wells by analyzing changes in production data, and mainly include the critical fluid-carrying flow rate method, the detection surface method, the IP-IC cross-plot method, and the oil-casing pressure differential method. The critical liquid-carrying flow rate method calculates the liquid-carrying capacity of gas well gas flow. When the actual gas production is lower than the critical production rate, liquid accumulation at the bottom of the well is considered to have begun. The detection surface method uses sound waves, pressure, or temperature to detect changes in the liquid level. When the liquid level rises significantly and stabilizes in the lower part of the wellbore, it indicates that the gas well has entered the liquid control stage. The IP-IC cross plot method plots the changes in the gas production index (IP) and the liquid production index (IC). When the two intersect at an inflection point, it is determined that the gas well has transitioned from gas phase flow to gas-water two-phase flow. The oil-casing pressure difference method indicates that as production progresses, the oil-casing pressure difference gradually increases, indicating the beginning of bottom-hole liquid accumulation. For theoretical prediction of the water breakthrough time of gas wells in water-bearing gas reservoirs, the main methods are the seepage mechanism model method and the system identification method. The seepage mechanism model method is based on the gas-water two-phase seepage theory and uses physical equations to derive the time for water to advance to the bottom of the well. The system identification method treats the gas well as an input-output system and identifies the water breakthrough time by using dynamic data fitting and parameter recursion, utilizing changes in bottom-hole pressure, water saturation, and production rate. The above methods have the following problems: (1) Although the methods used in actual field application (such as the oil-casing pressure difference method) can effectively identify the formed liquid accumulation or the rise of the wellbore liquid level, they lack specific discrimination for the formation water to begin to affect the gas reservoir (such as the pressure gradient change in the near-well area and the early stage of the gas-water interface migrating to the well); (2) Among the theoretical prediction methods, the seepage method is mostly applicable to gas reservoirs with edge and bottom water, but its adaptability is limited in gas-water co-layer, heterogeneous or fractured systems; (3) Although the system identification method can achieve dynamic prediction to a certain extent, its model structure and parameter determination depend on a large amount of high-frequency measured data, the calculation is complicated and sensitive to the error of the input data, which easily leads to fluctuations in the prediction results and limited accuracy. Summary of the Invention

[0004] In view of this, the present invention proposes a method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure, in order to solve the problem that the existing methods for determining the water breakthrough time have limited applicability and low accuracy.

[0005] To solve at least one of the above-mentioned technical problems, the present invention provides a method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure, comprising the following steps: Step S1: Obtain the basic parameters of the gas well; Step S2: Determine the formation pressure corresponding to different production times during the production process; Step S3: Calculate the coefficients of the binomial productivity equation for gas wells at different times under waterless conditions; Step S4: Combine the coefficients of the binomial productivity equation of the gas well at different times under waterless conditions to calculate the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions. Step S5: Compare the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions with the actual wellhead oil pressure or wellhead casing pressure to determine the water breakthrough time of the gas well; Wellhead casing pressure includes wellhead casing pressure without tubing and wellhead casing pressure with tubing.

[0006] The technical effects achieved by this invention are: This invention uses a method of comparing theoretical calculations of oil casing pressure with actual pressure to determine the start time of water intrusion in gas wells under waterless conditions. This method is simple, fast, accurate, and effective in handling error data. It can cover the entire production stage of gas reservoirs and has a wide range of applications. Attached Figure Description

[0007] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation of the scope. For those skilled in the art, other related drawings can be obtained from these drawings without creative effort.

[0008] Figure 1 This is a graph showing the relationship between the actual cumulative gas production of a gas well and production time in an embodiment of the present invention. Figure 2 This illustrates the relationship between formation pressure and production time in an embodiment of the present invention. Figure 3 This is a graph showing the relationship between wellhead casing pressure and mining time, obtained by combining static pressure iteration in an embodiment of the present invention. Figure 4 This is a graph showing the relationship between bottom hole flowing pressure and production time in an embodiment of the present invention; Figure 5 This is a comparison chart of the calculated and actual values ​​of wellhead casing pressure in an embodiment of the present invention. Detailed Implementation

[0009] The present invention will be further described in detail below with reference to the embodiments and accompanying drawings.

[0010] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of the present invention, not all of them. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention. Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention.

[0011] Example: A method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure includes the following steps: Step S1: Obtain the basic parameters and production data of a gas well in the Sulige Gas Field; Here, "gas well" refers to a gas well in the gas field where the water produced by each well is not measured individually during the production process. Its water production is measured uniformly by the joint station, so it is impossible to directly obtain the real-time water production corresponding to a specific gas well.

[0012] Therefore, this method is mainly applicable to gas wells where formation water is present but single-well production data is lacking. If single-well production measurement conditions are available on-site, this method can still be used as an auxiliary judgment or cross-validation tool while directly determining the water breakthrough time.

[0013] The basic parameters can be divided into single-well controlled reserves. (m) 3 The data includes the gas testing production capacity equation, gas sample testing data, production dynamic data, and wellbore structure data. Specifically, the gas testing production capacity equation includes the binomial production capacity equation for gas well testing, as shown in the following formula: In the formula, Indicates the original formation pressure; Indicates the bottom hole flowing pressure; This indicates the daily gas production of a gas well; , These are their coefficients.

[0014] Based on actual well test data, the binomial productivity equation for gas wells is as follows: Gas sample testing data includes natural gas pressure, volume, temperature, critical pressure, critical temperature, and formation temperature. T =140℃, original formation pressure The composition of natural gas is mainly derived from the results of PVT analysis of natural gas. The analysis results in this embodiment are shown in Table 1: Table 1 Natural Gas Composition Production dynamic data includes daily gas production from gas wells. (10) 4 m 3 / d), current cumulative gas production (10) 8 m 3 ), actual wellhead oil pressure, actual wellhead casing pressure; The wellbore structure data includes the tubing inner diameter D=0.062 (m) and the well depth H=2443 (m).

[0015] Step S2: Determine the formation pressure corresponding to different production times during the production process; In this step, the material balance equation for a constant-volume gas-driven gas reservoir is first established, along with... Figure 1 The relationship between the actual cumulative gas production of the gas well shown determines the relationship between the simulated pressure and the production time. By substituting the measured cumulative gas production and the original formation pressure into the material balance equation, the reservoir pressure changes at different production stages can be calculated.

[0016] The mass balance equation for a constant-volume gas-driven gas reservoir can be expressed as follows: In the formula, This indicates the formation pressure corresponding to the current production time; Indicates the original formation pressure; Indicates the original formation pressure deviation coefficient; This represents the formation pressure deviation coefficient corresponding to the current production time. This indicates the current cumulative gas production. This indicates the controlled reserves of a single well.

[0017] The calculation method for the formation pressure deviation coefficient Z corresponding to the current production time includes the following steps: The formula for calculating the formation pressure deviation coefficient Z corresponding to the current production time is compared with the formula for the simulated relative density. The calculation formula is combined with Newton's iteration to obtain the pseudo-correlation density at Z=1. The initial value is iterated until the (K+1)th iteration, at which point the corresponding density is obtained. The value and the pseudo-contrast density of the Kth time The difference is in 10 -5 Within the range, the pseudo-contrast density at this time The value is used as the pseudo-contrast density Substitute the exact value of Z into the calculation formula to obtain the specific value of Z; The formation pressure deviation coefficient Z corresponding to the current production time satisfies the DAK method for fitting the Standing-Katz diagram, and its calculation formula is shown in the following formula: ; ; ; ; ; ; ; ; ; ; ; In the formula, Indicates the temperature to be compared; Indicates the relative density; The pseudo-contrast density satisfies the following formula: In the formula, This indicates a comparative pressure.

[0018] Based on quasi-comparative pressure The relationship between the formation pressure deviation coefficient Z and the formation pressure at different production times is obtained by iterative solution. and The relationship between formation pressure and production time was then derived, and the specific steps are as follows: First, for the current production time point, an initial value for the formation pressure is set. At this time, the initial value of the formation pressure satisfies the following formula: The relative pressure is calculated based on this initial value. And combined with the simulated comparison temperature The formation pressure deviation coefficient corresponding to the current initial formation pressure is obtained by iteratively using the DAK method. Then, Substituting the mass balance equation of a constant-volume gas-driven gas reservoir, we obtain the results of the first iteration. The details are as follows: At this time, if Then let As the new initial value for formation pressure iteration, the corresponding pseudo-correlation pressure is recalculated. The new formation pressure deviation coefficient was obtained using the DAK method. Substituting the results into the mass balance equation, we obtain the second iteration result. Repeat this iterative process to obtain... , ...until satisfied: At this time, take The calculated formation pressure value corresponds to the current production time, and its corresponding deviation coefficient is taken as the formation pressure deviation coefficient for the current production time. The specific calculation results are as follows: Figure 2 As shown.

[0019] Step S3: Calculate the coefficients of the binomial productivity equation for gas wells at different times under waterless conditions; The viscosity of natural gas is mainly calculated using the Lee-Gonzalez-Eakin semi-empirical method, as shown in the following formula: In the formula, Indicates the viscosity of natural gas; Indicates the density of natural gas; y Indicates density index; Indicates formation temperature; Indicates the molar mass of natural gas; This represents the molar mass of component i in natural gas; This represents the mole fraction of component i in natural gas; These represent empirical parameters related to temperature and gas molecular weight. A combined correction factor for temperature and the relative molecular mass of natural gas; y Indicates density index; This indicates the formation pressure at different production times; Represents the ideal gas constant; This represents the formation pressure deviation coefficient corresponding to the current production time.

[0020] The calculation results are shown in Table 2: Table 2 Natural gas viscosity under different formation pressures Based on the physical properties of natural gas under different pressures and the binomial productivity equation for gas well testing, the coefficients of the binomial productivity equation for gas wells under different pressures are obtained. The coefficients of the binomial productivity equation for gas wells at different times under waterless conditions are A and B. The specific calculation method is shown in the following formula: In the formula, A and B represent the coefficients of the binomial productivity equation for gas wells at different times under waterless conditions. Z This represents the formation pressure deviation coefficient corresponding to the current production time. Indicates the original formation pressure deviation coefficient; Indicates the viscosity of natural gas; This indicates the viscosity of natural gas under the original conditions; , These represent the coefficients of the binomial productivity equation during the gas testing phase, provided by well test data.

[0021] The binomial coefficients of production capacity corresponding to formation pressure at different times are then obtained, as shown in Table 3: Table 3. Binomial coefficients of production capacity under different formation pressures This established the relationship between formation pressure changes and the binomial coefficient of production capacity.

[0022] In addition, the bottom hole flowing pressure at different times under waterless conditions The calculation method is shown in the following formula: In the formula, This indicates the formation pressure corresponding to the current production time; This indicates the daily gas production of a gas well; Based on the above formula, the relationship between bottom hole flowing pressure and production time is obtained, as follows: Figure 4 As shown.

[0023] Step S4: Combine the coefficients of the binomial productivity equation of the gas well at different times under waterless conditions to calculate the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions. Because some gas wells in the field produce gas without tubing, the wellhead casing pressure includes both the casing pressure without tubing and the casing pressure with tubing. When producing without tubing—that is, directly with casing—the wellhead casing pressure and the wellhead oil pressure when producing with tubing are both calculated using the wellhead flowing pressure formula. However, when producing with tubing, the wellhead casing pressure is calculated using the wellhead static pressure formula.

[0024] The method for calculating wellhead oil pressure or wellhead casing pressure without tubing is as follows: Combine the flowing pressure calculation formula to iteratively calculate the wellhead oil pressure or wellhead casing pressure without tubing. The bottom hole flowing pressure is calculated by substituting the daily gas production of the gas well obtained in S1 and the formation pressure at different production times in S2 into the gas well production capacity formula at different times under waterless conditions in S3, thereby obtaining the bottom hole flowing pressure at different times under waterless conditions. The flowing pressure calculation formula is as follows: In the formula, Indicates the wellhead flowing pressure; This represents the bottom-hole flowing pressure at different times under waterless conditions; Indicates the coefficient of friction; This indicates the daily gas production of a gas well; Indicates average temperature; This represents the deviation coefficient under the average parameter; Indicates the relative density of natural gas; This indicates the inner diameter of the current production tubing string. If calculating the wellhead casing pressure without tubing, the inner diameter of the casing is used; if calculating the wellhead oil pressure, the inner diameter of the tubing is used. Represents the Reynolds number.

[0025] The specific steps for iteratively calculating wellhead oil pressure or wellhead casing pressure without tubing, based on the flowing pressure calculation formula, are as follows: S1: Based on the bottom hole flowing pressure with well depth H Estimate the initial wellhead flowing pressure using the following formula: S2: Based on the bottom hole flowing pressure Initial value of wellhead flowing pressure Calculate the average wellbore pressure: S3: At average wellbore pressure With average temperature Under the given conditions, the DAK method is used to calculate the natural gas deviation coefficient. And calculate the density of natural gas. Average volumetric flow rate airflow speed and Reynolds number : In the formula, Indicates ground pressure; Indicates the ground deviation coefficient; Indicates ground temperature; S4: Calculate the friction coefficient based on the Reynolds number and wellbore parameters. The above parameters were then substituted into the wellhead flowing pressure calculation formula to obtain the results of the first iteration. .

[0026] like Then let As the initial value for the new wellhead flowing pressure iteration, the above calculation process is repeated to obtain... , ...until satisfied At this time, take This is the calculated wellhead flowing pressure value after iterative convergence.

[0027] The method for calculating wellhead casing pressure when tubing is present is as follows: combine the static pressure calculation formula and iteratively calculate the wellhead casing pressure; The static pressure calculation formula is shown below: In the formula, Indicates the static pressure at the wellhead; This represents the bottom-hole flowing pressure at different times under waterless conditions; Indicates average temperature; This represents the deviation coefficient under the average parameter; Indicates the relative density of natural gas; Indicates the depth of the well.

[0028] Based on the static pressure calculation formula, the specific steps for calculating the wellhead casing pressure when tubing is present are as follows: S1: Based on the bottom hole flowing pressure with well depth H Estimate the initial static pressure at the wellhead using the following formula: S2: Based on the bottom hole flowing pressure Initial value of wellhead flowing pressure Calculate the average wellbore pressure: S3: At average wellbore pressure With average temperature Under the given conditions, the DAK method is used to calculate the natural gas deviation coefficient. Substituting this into the wellhead static pressure calculation formula, the first iteration result was obtained. : like Then let As the initial value for the new wellhead flowing pressure iteration, the above calculation process is repeated to obtain... , ...until satisfied At this time, take This is the calculated wellhead static pressure value after iterative convergence.

[0029] Taking static pressure calculation as an example, The change in wellhead casing pressure over time was calculated using iterative methods based on average temperature and pressure, as detailed below. Figure 3 As shown.

[0030] Step S5: Compare the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions with the actual wellhead oil pressure or wellhead casing pressure to determine the water breakthrough time of the gas well. Specifically, as follows... Figure 5 As shown in the example, the wellhead casing pressure with tubing was used to determine the water breakthrough time of the gas well. In the first four weeks of production, the calculated and measured values ​​were basically consistent, indicating that the gas well had not yet encountered water during this stage. From the fourth week onwards, the measured values ​​consistently exceeded the calculated values, meaning that formation water began to affect gas well production. Therefore, the water breakthrough time for this gas well was determined to be the fourth week after production. Furthermore, comparing the wellhead oil pressure and wellhead casing pressure at different production times under waterless conditions with the actual wellhead oil pressure or wellhead casing pressure to determine the water breakthrough time of a gas well is a routine operation in this field, and therefore no special limitations are made on its specific steps.

[0031] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure, characterized in that, Includes the following steps: Step S1: Obtain the basic parameters of the gas well; Step S2: Determine the formation pressure corresponding to different production times during the production process; Step S3: Calculate the coefficients of the binomial productivity equation for gas wells at different times under waterless conditions; Step S4: Combine the coefficients of the binomial productivity equation of the gas well at different times under waterless conditions to calculate the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions. Step S5: Compare the wellhead oil pressure or wellhead casing pressure at different production times under waterless conditions with the actual wellhead oil pressure or wellhead casing pressure to determine the water breakthrough time of the gas well; Wellhead casing pressure includes wellhead casing pressure without tubing and wellhead casing pressure with tubing.

2. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 1, characterized in that: The gas well in question lacks single-well water production measurement data.

3. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 1, characterized in that: The basic parameters include single-well controlled reserves, gas testing production capacity equation, gas sample detection data, production dynamic data, and well structure data; Among them, the gas testing production capacity equation includes the binomial production capacity equation for gas well testing; Gas sample testing data includes natural gas pressure, volume, temperature, critical pressure, critical temperature, as well as formation temperature, original formation pressure, and natural gas composition; Production dynamic data includes daily gas production of gas wells, current cumulative gas production, actual wellhead oil pressure, and actual wellhead casing pressure; Wellbore structure data includes tubing inner diameter, casing inner diameter, and well depth.

4. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 1, characterized in that: The calculation method for formation pressure corresponding to different production times during the production process described in step S2 is shown in the following formula: In the formula, This indicates the formation pressure corresponding to the current production time; Indicates the original formation pressure; Indicates the original formation pressure deviation coefficient; This represents the formation pressure deviation coefficient corresponding to the current production time. This indicates the current cumulative gas production. This indicates the controlled reserves of a single well.

5. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 4, characterized in that: The calculation method for the formation pressure deviation coefficient Z corresponding to the current production time includes the following steps: The formula for calculating the formation pressure deviation coefficient Z corresponding to the current production time is compared with the formula for the simulated relative density. The calculation formula is combined with Newton's iteration to obtain the pseudo-correlation density at Z=1. The initial value is iterated until the (K+1)th iteration, at which point the corresponding density is obtained. The value and the pseudo-contrast density of the Kth time The difference is in 10 -5 Within the range, the pseudo-contrast density at this time The value is used as the pseudo-contrast density Substitute the exact value of Z into the calculation formula to obtain the specific value of Z; The formation pressure deviation coefficient Z corresponding to the current production time satisfies the DAK method for fitting the Standing-Katz diagram, and its calculation formula is shown in the following formula: ； ； ； ； ； ； ； ； ； ； ； In the formula, Indicates the temperature to be compared; Indicates the relative density; The pseudo-contrast density satisfies the following formula: In the formula, This indicates a comparative pressure.

6. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 1, characterized in that: The coefficients of the binomial productivity equation for gas wells at different times under waterless conditions mentioned in step S3 are A and B, and the specific calculation method is shown in the following formula: In the formula, A and B represent the coefficients of the binomial productivity equation for gas wells at different times under waterless conditions. Z This represents the formation pressure deviation coefficient corresponding to the current production time. Indicates the original formation pressure deviation coefficient; Indicates the viscosity of natural gas; This indicates the viscosity of natural gas under the original conditions; , These represent the coefficients of the binomial capacity equation during the trial gas testing phase.

7. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 6, characterized in that: The method for calculating the viscosity of natural gas is shown in the following formula: In the formula, Indicates the viscosity of natural gas; Indicates the density of natural gas; y Indicates density index; Indicates formation temperature; Indicates the molar mass of natural gas; This represents the molar mass of component i in natural gas; This represents the mole fraction of component i in natural gas; These represent empirical parameters related to temperature and gas molecular weight. A combined correction factor for temperature and the relative molecular mass of natural gas; This indicates the formation pressure at different production times; Represents the ideal gas constant; This represents the formation pressure deviation coefficient corresponding to the current production time.

8. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 6, characterized in that: The calculation method for wellhead oil pressure or wellhead casing pressure without tubing in step S4 is as follows: Combine the flowing pressure calculation formula to iteratively calculate the wellhead oil pressure or wellhead casing pressure without tubing. The formula for calculating the flow pressure is as follows: In the formula, Indicates the wellhead flowing pressure; This represents the bottom-hole flowing pressure at different times under waterless conditions; Indicates the coefficient of friction; This indicates the daily gas production of a gas well; Indicates average temperature; This represents the deviation coefficient under the average parameter; Indicates the relative density of natural gas; This indicates the inner diameter of the current production tubing; Represents the Reynolds number; The specific steps for iteratively calculating wellhead oil pressure or wellhead casing pressure without tubing, based on the flowing pressure calculation formula, are as follows: S1: Calculate the initial value of the wellhead flowing pressure based on the bottom hole flowing pressure and the well depth; S2: Calculate the average wellbore pressure based on the initial values ​​of bottom hole flowing pressure and wellhead flowing pressure; S3: Under average wellbore pressure and average temperature conditions, the DAK method is used to calculate the natural gas deviation coefficient, and the natural gas density, average volumetric flow rate, gas flow velocity and Reynolds number are also calculated. S4: Calculate the friction coefficient based on the Reynolds number and wellbore parameters, and substitute these parameters into the wellhead flowing pressure calculation formula to obtain the first iteration result.

9. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 8, characterized in that: The method for calculating the wellhead casing pressure when there is tubing in step S4 is as follows: combine the static pressure calculation formula and iteratively calculate the wellhead casing pressure; The static pressure calculation formula is shown below: In the formula, Indicates the wellhead static pressure; This represents the bottom-hole flowing pressure at different times under waterless conditions; Indicates average temperature; This represents the deviation coefficient under the average parameter; Indicates the relative density of natural gas; Indicates the well depth. The specific steps are as follows: S1: Calculate the initial static pressure at the wellhead based on the bottom hole flowing pressure and well depth; S2: Calculate the average wellbore pressure based on the initial values ​​of bottom hole flowing pressure and wellhead flowing pressure; S3: Under the conditions of average wellbore pressure and average temperature, the natural gas deviation coefficient is calculated using the DAK method and substituted into the wellhead static pressure calculation formula to obtain the first iteration result.

10. The method for determining the water breakthrough time of a gas well with a water-bearing gas reservoir based on wellhead pressure according to claim 9, characterized in that: Bottom-hole flowing pressure at different times under anhydrous conditions The calculation method is shown in the following formula: In the formula, This indicates the formation pressure corresponding to the current production time; This indicates the daily gas production of a gas well.

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