Diagnostic method for recovery capacity of water-producing gas well after well shut-in

Abstract

The invention belongs to the technical field of petroleum and natural gas development, and particularly relates to a method for diagnosing the production recovery capacity of a water-producing gas well after well shut-in, and the method comprises the steps: building an inflow dynamic curve of the gas well; establishing an outflow dynamic curve of the gas well; judging whether the inflow dynamic curve and the outflow dynamic curve have an intersection point or not; if no intersection point exists, the gas well cannot naturally recover the production; if the intersection point exists, the gas well yield of the intersection point is compared with the critical liquid-carrying flow, and if the gas well yield of the intersection point is larger than the critical liquid-carrying flow, the gas well can recover production naturally; and if the gas well yield of the intersection point is smaller than or equal to the critical liquid-carrying flow, the gas well cannot naturally recover production. The gas well node analysis method is used for judging whether the gas well can normally recover the production or not under the natural condition, and the problem that an existing diagnosis method for the recovery capacity after the water-producing gas well is shut down is single is solved. The diagnosis method also has the advantage of high diagnosis precision, and can accurately diagnose whether the gas well can recover the production naturally or not.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas development, and particularly relates to a method for diagnosing the restart production capacity of a water-producing gas well after shut-in. Background Art

[0002] For gas fields with high hydrogen sulfide content in gas reservoirs, it is necessary to regularly shut down the entire gas field for maintenance. The maintenance period is generally about one month. When a water-bearing gas well is reopened after a long-term shut-in, the initial production liquid-gas ratio will increase significantly compared with the normal production before shut-in. There is a risk that these gas wells cannot be restarted normally during the restart production process. It is necessary to predict in advance whether the gas well can be naturally restarted. For gas wells that can be naturally restarted, no measures need to be taken, while for gas wells that cannot be naturally restarted, measures should be formulated in advance and a plan should be made to improve the management efficiency of water-producing gas wells.

[0003] At present, the research on the restart production capacity of gas wells generally focuses on gas wells that are about to stop flowing, and evaluates the restart production capacity from the perspective of whether they can carry liquid, and the diagnostic method is relatively single. Summary of the Invention

[0004] The purpose of the present invention is to provide a method for diagnosing the restart production capacity of a water-producing gas well after shut-in, so as to solve the problem of the single diagnostic method for the restart production capacity of existing water-producing gas wells after shut-in.

[0005] To achieve the above purpose, the technical solution of the present invention is:

[0006] A method for diagnosing the restart production capacity of a water-producing gas well after shut-in, the diagnostic method includes: establishing an inflow performance curve of the gas well; establishing an outflow performance curve of the gas well; determining whether there is an intersection point between the inflow performance curve and the outflow performance curve; if there is no intersection point, the gas well cannot be naturally restarted; if there is an intersection point, comparing the gas well production at the intersection point with the critical liquid-carrying flow rate, if the gas well production at the intersection point is greater than the critical liquid-carrying flow rate, the gas well can be naturally restarted; if the gas well production at the intersection point is less than or equal to the critical liquid-carrying flow rate, the gas well cannot be naturally restarted.

[0007] The beneficial effects of the above technical solution are: The present invention provides a new method for diagnosing the restart production capacity of a water-producing gas well after shut-in. The present invention uses the gas well nodal analysis method to determine whether the gas well can be normally restarted under natural conditions, and solves the problem of the single diagnostic method for the restart production capacity of existing water-producing gas wells after shut-in. The diagnostic method of the present invention also has the advantage of high diagnostic accuracy and can accurately diagnose whether the gas well can be naturally restarted.

[0008] The nodal analysis method for gas wells divides the production system into two parts, the inflow section and the outflow section, by setting nodes. The inflow section includes all parts between the node and the gas reservoir boundary; the outflow section includes all parts between the node and the calculation end point. The inflow and outflow models are used to represent the flow characteristics of the inflow and outflow sections respectively. The inflow performance model, that is, the inflow performance equation, is the relationship equation between the fluid (oil, gas, water) production rate and the corresponding bottom-hole flowing pressure under a certain formation pressure. The curve plotted from this equation is called the inflow performance curve. The outflow performance model, that is, the outflow performance equation, is the relationship equation between the fluid (oil, gas, water) production rate and the corresponding bottom-hole flowing pressure under a certain wellhead oil pressure. The curve plotted from it is the outflow performance curve. The intersection point of the two curves is the coordination point, and the flow rate corresponding to the coordination point is the reasonable production rate of the gas well.

[0009] For new wells, the nodal analysis method for gas wells is usually used to optimize completion parameters and select the optimal tubing size. For the already producing oil and gas wells, using the nodal analysis method for gas wells helps to scientifically manage production. At present, there is no relevant report on using the nodal analysis method for gas wells to diagnose the restart production capacity after the production gas well is shut in.

[0010] As a further improvement, establishing the inflow performance curve of the gas well includes: establishing the productivity equation of the gas well; obtaining the inflow performance curve of the gas well under different formation pressure conditions according to the productivity equation of the gas well;

[0011] Among them, the productivity equation of the gas well is:

[0012]

[0013]

[0014]

[0015] P R is the formation pressure, MPa; P wf is the bottom-hole pressure, MPa; A is the laminar flow coefficient; B is the turbulent flow coefficient; q is the gas flow rate, 10 4 m 3 / d; T is the formation temperature, K; is the gas viscosity, mPa·s; is the average deviation coefficient of the formation gas, dimensionless; is the gas-phase relative permeability at irreducible water saturation, dimensionless; h is the reservoir thickness, m; r e is the supply radius, m; r w is the wellbore radius, m; β is the turbulent flow factor; S is the true skin factor of the gas well, dimensionless, γ g is the relative density of natural gas, dimensionless.

[0016] The beneficial effects of the above technical solution are as follows: For gas wells with relatively frequent production adjustment, the bottom-hole flowing pressure can be calculated from the tubing head pressure under different operating regimes of the gas well, and the formation pressure can be calculated from the shut-in tubing head pressure. By using the above method, a conventional binomial productivity equation for the gas well can be established.

[0017] As a further improvement, the diagnosis method further includes: correcting the laminar flow coefficient A and the turbulent flow coefficient B, and establishing a productivity equation for the gas well by using the corrected laminar flow coefficient A' and the corrected turbulent flow coefficient B';

[0018] Among them, the laminar flow coefficient A and the turbulent flow coefficient B are corrected in the following manner:

[0019]

[0020]

[0021] A is the laminar flow coefficient; B is the turbulent flow coefficient; A' is the corrected laminar flow coefficient, and B' is the corrected turbulent flow coefficient; is the gas-phase relative permeability at irreducible water saturation, dimensionless; B g is the gas volume factor; μ g is the gas-phase viscosity, mPa·s; WGR is the produced liquid-gas ratio, m 3 / 10 4 m 3 ; R wgr is the condensate-gas ratio, m 3 / 10 4 m 3 ; μ w is the water-phase viscosity, mPa·s; r e is the supply radius, m; r w is the wellbore radius, m; S t is the total water breakthrough skin factor, dimensionless; a and b are regression coefficients; S is the true skin factor of the gas well, dimensionless; K rg is the gas-phase relative permeability, dimensionless.

[0022] The beneficial effects of the above technical solution are as follows: Considering that as the formation pressure decreases, the A and B coefficients in the productivity equation change dynamically. By correcting the A and B coefficients in the present invention, the productivity equation can more accurately reflect the actual situation of different formations, further improving the accuracy of the diagnosis method.

[0023] As a further improvement, establishing the outflow performance curve of a gas well includes: calculating the bottom-hole flowing pressure during the production stage of the gas well using multiple pipe flow models; comparing the measured bottom-hole flowing pressure of the gas well with the bottom-hole flowing pressures calculated by different pipe flow models, and comparing the coincidence rates of the bottom-hole flowing pressures calculated by different pipe flow models; taking the pipe flow model with the highest coincidence rate in different liquid-gas ratio stages as the applicable pipe flow model for that liquid-gas ratio stage, to obtain the applicable pipe flow models for different liquid-gas ratio stages; using the applicable pipe flow models for different liquid-gas ratio stages to obtain the outflow performance curve of the gas well under different wellhead oil pressures and different liquid-gas ratios.

[0024] The beneficial effects of the above technical solution are: the coincidence rate of the bottom-hole flowing pressure calculated by different pipe flow models is related to the liquid-gas ratio. By selecting different pipe flow models in different liquid-gas ratio stages in the present invention, the simulation accuracy of the outflow curve in different production stages of the gas well can be improved, and further the accuracy of diagnosis can be improved.

[0025] Further, the pipe flow models include the Hagedron Brown model, the Beggs-Brill model, the Gray model, and the Duns and Ros Original model.

[0026] As a further improvement, after establishing the inflow performance curve of the gas well and establishing the outflow performance curve of the gas well, the diagnosis method further includes: determining the applicable inflow performance curve of the gas well after opening based on the predicted reservoir formation pressure after opening; comparing the predicted maximum liquid-gas ratio after opening with the liquid-gas ratio stages applicable to different pipe flow models, and combining with the wellhead pressure limit to determine the applicable pipe flow model after opening, to obtain the outflow performance curve of the gas well.

[0027] The beneficial effects of the above technical solution are: based on the predicted reservoir formation pressure after opening, the predicted maximum liquid-gas ratio after opening, and the wellhead pressure limit, the applicable inflow performance curve and outflow performance curve after opening can be determined, which can accurately reflect the conditions of the gas well after opening and further improve the accuracy of diagnosis.

[0028] Further, the reservoir formation pressure after opening is predicted based on the current pressure situation and pressure drop trend of the reservoir, and the maximum liquid-gas ratio after opening is predicted based on the relationship between the gas well shut-in time and the change in production liquid-gas ratio.

[0029] As a further improvement, the diagnosis method further includes: correcting the gravity coefficient and friction coefficient, and establishing a pipe flow model using the corrected gravity coefficient and friction coefficient.

[0030] The beneficial effects of the above technical solution are: by correcting the gravity coefficient and friction coefficient, the accuracy of the pipe flow model can be improved, enabling the pipe flow model to more accurately reflect the state of the gas well and further improving the accuracy of the final diagnosis result.

[0031] Furthermore, the diagnostic method further includes: correcting the gravity coefficient and friction coefficient by using pressure test data. Specifically, the gravity coefficient and friction coefficient can be corrected by using the measured formation pressure and bottom-hole flowing pressure of the gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] Figure 1 is a flowchart of the diagnostic method for the restart capacity of a water-producing gas well after shut-in in Embodiment 1 of the present invention;

[0033] Figure 2 is the inflow performance curve of a gas well under different formation pressure conditions in Embodiment 1 of the present invention;

[0034] Figure 3 is the comparison between the bottom-hole flowing pressure calculated by different pipe flow models and the measured bottom-hole flowing pressure of Well P104-1 in Embodiment 1 of the present invention, as well as the liquid-gas ratio curve, where the pressure gauge refers to the measured bottom-hole flowing pressure measured by a pressure gauge, BB refers to the bottom-hole flowing pressure calculated by the Beggs-Brill pipe flow model, Gray refers to the bottom-hole flowing pressure calculated by the Gray pipe flow model, HB refers to the bottom-hole flowing pressure calculated by the Hagedron Brown pipe flow model, and DRO refers to the bottom-hole flowing pressure calculated by the Duns and Ros Original pipe flow model;

[0035] Figure 4 is the inflow performance curve and outflow performance curve of a gas well in Embodiment 1 of the present invention;

[0036] Figure 5 is the inflow performance curve and outflow performance curve of another gas well in Embodiment 1 of the present invention. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0037] The present invention provides a diagnostic method for the restart capacity of a water-producing gas well after shut-in. The diagnostic method includes: establishing an inflow performance curve of the gas well; establishing an outflow performance curve of the gas well; determining whether there is an intersection point between the inflow performance curve and the outflow performance curve; if there is no intersection point, the gas well cannot restart naturally; if there is an intersection point, comparing the gas well production at the intersection point with the critical liquid-carrying flow rate. If the gas well production at the intersection point is greater than the critical liquid-carrying flow rate, the gas well can restart naturally; if the gas well production at the intersection point is less than or equal to the critical liquid-carrying flow rate, the gas well cannot restart naturally.

[0038] The present invention uses the gas well nodal analysis method to determine whether a gas well can restart normally under natural conditions. Currently, there is no relevant report on using the gas well nodal analysis method to diagnose the restart capacity of a water-producing gas well after shut-in. The diagnostic method of the present invention has the advantage of high diagnostic accuracy and solves the problem of the single diagnostic method for the restart capacity of existing water-producing gas wells after shut-in.

[0039] To make the objectives, technical solutions and advantages of the present invention clearer, taking a high-sulfur gas field as an example, the present invention will be further described in conjunction with the accompanying drawings.

[0040] Example 1 An example of a diagnostic method for the restart capacity of a gas-producing well after shut-in

[0041] As Figure 1 can be seen, the diagnostic method for the restart capacity of a gas-producing well after shut-in includes the following steps:

[0042] 1. Establish an inflow performance model for the gas well

[0043] 1.1 Based on the fitting of the gas well productivity test results and production performance data, establish a gas well productivity equation, and track and evaluate the gas well productivity according to the gas well production performance. The calculation steps are as follows:

[0044] In high-sulfur gas fields, the gas well production rate is adjusted frequently. Use the bottom-hole flowing pressure converted from the tubing head pressure under different operating systems during the production rate adjustment process, and then combine the formation pressure converted from the shut-in tubing head pressure to establish the gas well productivity equation;

[0045]

[0046]

[0047]

[0048] P R is the formation pressure, MPa; P wf is the bottom-hole pressure, MPa; A is the laminar flow coefficient; B is the turbulent flow coefficient; q is the gas flow rate, 10 4 m 3 / d; T is the formation temperature, K; is the gas viscosity, mPa·s; is the average deviation coefficient of the formation gas, dimensionless; is the relative permeability of the gas phase under irreducible water saturation, dimensionless; h is the reservoir thickness, m; r e is the supply radius, m; r e is the wellbore radius, m; β is the turbulent flow factor; S is the true skin factor of the gas well, dimensionless; γ g is the relative density of natural gas, dimensionless.

[0049] 1.2 Use the modified laminar flow coefficient A' and the modified turbulent flow coefficient B' to establish the inflow performance model of the gas well

[0050] Considering that as the formation pressure drops, the laminar flow coefficient A and the turbulent flow coefficient B in the gas well productivity equation change dynamically, continuously modify the laminar flow coefficient A and the turbulent flow coefficient B to obtain the productivity equation under different formation pressure conditions.

[0051] Using the conventional A and B coefficients to evaluate the productivity of water-producing gas wells will result in a higher calculation result. Therefore, considering the productivity loss caused by gas-water relative permeability and near-well additional skin, the A and B coefficients in the productivity equation of gas wells are corrected by the method of correcting the relative permeability curve, and then the productivity of gas wells after water breakthrough is calculated.

[0052] The corrected productivity coefficients are calculated by the following formula:

[0053]

[0054] S t = S + S b

[0055]

[0056]

[0057]

[0058] A is the laminar flow coefficient; B is the turbulent flow coefficient; A' is the corrected laminar flow coefficient, and B' is the corrected turbulent flow coefficient; K rg is the gas-phase relative permeability, dimensionless; is the gas-phase relative permeability at irreducible water saturation, dimensionless; WGR is the production liquid-gas ratio, m 3 / 10 4 m 3 ; R wgr is the condensate liquid-gas ratio, m 3 / 10 4 m 3 ; B g is the gas volume coefficient; μ g is the gas-phase viscosity, mPa·s; μ w is the water-phase viscosity, mPa·s; a and b are regression coefficients; r dam is the damage radius, m; r w is the wellbore radius, m; r e is the supply radius, m; S t is the total skin at water breakthrough, dimensionless; S is the true skin factor of the gas well, dimensionless; S b is the skin after water breakthrough, dimensionless.

[0059] Combined with the formation pressure conversion result, the productivity equation of the gas well is established, and the A and B coefficients in the productivity equation are further dynamically corrected. By establishing the relationship between the production liquid-gas ratio WGR of the water-producing gas well and the change of water saturation near the well bottom, and then determining the gas-phase relative permeability at different water saturations from the relative permeability curve, the coefficients of the productivity equation of the gas well after water breakthrough are corrected. The obtained productivity equation is the inflow performance relationship between pressure and production during the flow process from the formation to the well bottom.

[0060] 1.3 Calculate the inflow performance curve under different formation pressure conditions

[0061] Assume a series of bottom-hole flowing pressures. For each bottom-hole flowing pressure, calculate the production rate at this flowing pressure according to the obtained gas well productivity equation and formation pressure, and plot the relationship curve between the production rate and the corresponding bottom-hole flowing pressure under a certain formation pressure, which is the inflow performance curve, as Figure 2 shown.

[0062] 2. Establish the outflow performance model of the gas well

[0063] 2.1 Determine the applicable tubing flow model for different liquid-gas ratio stages

[0064] According to field practice, different tubing flow models should be adopted for gas wells at different liquid-gas ratios to adapt to the model calculations of different production stages of water-carrying gas wells. Based on the continuous bottom-hole flowing pressure data recorded by the permanent downhole pressure gauge of Well 104-1 in a certain area, the relationship curves of bottom-hole flowing pressure, liquid-gas ratio and cumulative gas production are made respectively to verify the feasibility of the method of the present invention. Referring to Figure 3 , comparing the bottom-hole flowing pressure results calculated by different tubing flow models with the bottom-hole flowing pressure measured by the pressure gauge, it is found that as the liquid-gas ratio increases, the tubing flow model with a high original coincidence rate is no longer suitable for the current stage of flowing pressure calculation. Therefore, the tubing flow model with the highest coincidence rate is selected as the applicable tubing flow model for different liquid-gas ratio stages respectively. The error between the pressure calculated by the selected tubing flow model and the measured pressure is 5%. The applicable tubing flow models for different liquid-gas ratio stages are shown in Table 1. The tubing flow model determined in this way is closer to the actual situation of the gas well, with a high overall fitting degree and a coincidence rate of over 90%, which can meet the simulation accuracy requirements of the outflow curves of different gas wells. In order to verify the general applicability of this method, another water-producing gas well, Well 3011-5 in a certain area with a downhole pressure gauge and a well with measured bottom-hole flowing pressure data by production logging in this block are selected for comparative verification, and the coincidence rate reaches over 90%.

[0065] Table 1 Selection of tubing flow models at different liquid-gas ratios

[0066] Liquid-gas ratio <0.15 0.15～0.6 0.6～9.0 Applicable pipe flow model Hagedron Brown Beggs-Brill Gray

[0067] Hagedron Brown model:

[0068] Beggs-Brill model:

[0069] Gray model:

[0070] ρ m is the mixture density, Kg / m3 ;H L is the liquid holdup rate; g is the gravitational acceleration, m / s 2 , ρ L is the liquid density, Kg / m 3 ρ g is the gas phase density, Kg / m 3 ; D is the inner diameter of the oil pipe, m; f m is the two-phase friction coefficient; A is the cross-sectional area of ​​the pipe, m 2 ; V SL is the liquid phase apparent velocity, m / s; Mt is the velocity per m produced under standard surface conditions. 3 Total mass of gas-associated oil, gas and water, Kg / m 3 ;q L is the surface liquid production, m 3 / d; Vm is the mixture flow rate, m / s; is the pressure drop, MPa / m; θ is the tube bevel; ρ f Density of the mixture without slippage, Kg / m 3 ; p is the pressure acting on the fluid, MPa; λ L is the volume liquid content, dimensionless; f ns is the friction coefficient of the mixture when it flows, dimensionless; Vsg is the gas converted flow velocity, m / s; G is the mass flow rate of the gas-liquid mixture, Kg / s.

[0071] 2.2. Correct the gravity coefficient and friction coefficient, and use the corrected gravity coefficient and friction coefficient to establish the gas well pipe flow model

[0072] The gas well pipe flow model mainly converts the bottom hole flow pressure based on production parameters such as wellhead oil pressure, gas volume and liquid-gas ratio. The difference between the bottom hole flow pressure and the wellhead oil pressure represents the pressure loss in the wellbore, which consists of two parts: one is the pressure loss caused by the gravity of the fluid itself, and the other is the pressure loss caused by friction, which are represented by the gravity coefficient and the friction coefficient respectively. m or ns ) is used for correction to further improve the accuracy of the pipe flow model.

[0073] Specifically, since there are deviations between the calculated gravity coefficient and friction coefficient and the actually tested gravity coefficient and friction coefficient, the gravity coefficient and friction coefficient are adjusted so that the calculated gravity coefficient and friction coefficient are equal to the actually tested values.

[0074] 2.3 Calculate the outflow dynamic curve under different oil pressure and different liquid-gas ratio conditions

[0075] For a certain wellhead pressure and liquid-gas ratio, assume a series of production rates, and calculate the bottom-hole flowing pressure at this production rate according to the pipe flow model established in 2.2. Plot the relationship curve between the production rate and the corresponding bottom-hole pressure under certain wellhead pressure and liquid-gas ratio conditions, which is the inflow performance curve.

[0076] 3. Determine the inflow performance curve and outflow performance curve applicable to the gas well after opening the well

[0077] Specifically, the inflow performance curve and outflow performance curve applicable to the gas well after opening the well are determined based on the predicted formation pressure after the gas well is opened, the predicted maximum liquid-gas ratio after opening the well, and the wellhead oil pressure.

[0078] According to the current production performance of the gas well and the empirical method, it is predicted that the change multiple of the liquid-gas ratio between the long-term shut-in and the initial stage of opening the well for the gas well is between 1.2 and 4.0 times, and the liquid-gas ratio of 10 gas wells at the initial stage of opening the well is between 1.6 and 5.9m 3 / 10 4 m 3 Between, based on the initial liquid-gas ratio of the gas well and the multiple relationship between the liquid-gas ratio after long-term shut-in and the initial liquid-gas ratio after opening the well, the liquid-gas ratio after opening the well can be calculated.

[0079] The wellhead oil pressure is in accordance with the wellhead pressure limit (9 MPa) designed for the pipeline network.

[0080] The formation pressure is predicted according to the current formation pressure and the pressure drop trend.

[0081] 4. Comprehensively judge whether the water-producing gas well can resume production naturally based on the inflow performance model and outflow performance model

[0082] Use the established single-well inflow and outflow model, and carry out nodal analysis according to parameters such as the wellhead oil pressure, predicted formation pressure, and liquid-gas ratio to diagnose the production status during the resumption of production. If the inflow curve and the outflow curve have an intersection point (coordination point), and the production rate at the coordination point is greater than the critical liquid-carrying flow rate, then it can resume production naturally; if there is no coordination point or the production rate at the coordination point is less than or equal to the critical liquid-carrying flow rate, it cannot resume production naturally.

[0083] The results of nodal analysis show that under the wellhead pressure limit condition, there are intersection points (coordination points) between the inflow and outflow curves of 7 gas wells. Among them, the production rates at the coordination points of 4 gas wells are greater than the critical liquid-carrying flow rate and can resume production naturally; the inflow performance curve and outflow performance curve of one gas well are as Figure 4As shown, there are two intersections between the inflow dynamic curve and the outflow dynamic curve. The gas volumes at the two intersections are different. At the intersection with a smaller gas volume, the flow of the gas well is unstable. Therefore, the intersection with a larger gas volume is taken as the coordination point. The production rate at the coordination point of the gas well is greater than the critical liquid-carrying flow rate, and the well can resume production naturally. There are three gas wells where the inflow dynamic curve and the outflow dynamic curve have intersections, but the production rate at the coordination point is less than the critical liquid-carrying flow rate, so they cannot resume production naturally; there are another three wells without a coordination point and cannot resume production naturally; among them, the inflow dynamic curve and the outflow dynamic curve of one gas well are as Figure 5 shown, and there is no intersection between the inflow dynamic curve and the outflow dynamic curve, so it cannot resume production naturally.

Claims

1. A diagnostic method for the restart capacity of a water-producing gas well after shut-in, characterized in that, The described diagnostic method includes: Establishing the inflow performance curve of the gas well; Establishing the outflow performance curve of the gas well; Judging whether there is an intersection point between the inflow performance curve and the outflow performance curve; if there is no intersection point, the gas well cannot be naturally restored to production; if there is an intersection point, comparing the gas well production at the intersection point with the critical liquid-carrying flow rate. If the gas well production at the intersection point is greater than the critical liquid-carrying flow rate, the gas well can be naturally restored to production; if the gas well production at the intersection point is less than or equal to the critical liquid-carrying flow rate, the gas well cannot be naturally restored to production.

2. The diagnostic method for the production capacity recovery of a water-producing gas well after shut-in according to claim 1, wherein The establishing of the inflow performance curve of the gas well includes: establishing the productivity equation of the gas well; according to the productivity equation of the gas well, obtaining the inflow performance curve of the gas well under different formation pressure conditions; Wherein, the productivity equation of the gas well is: P R is the formation pressure, MPa; P wf is the bottom-hole pressure, MPa; A is the laminar flow coefficient; B is the turbulent flow coefficient; q is the gas flow rate, 10 4 m 3 / d; T is the formation temperature, K; is the gas viscosity, mPa·s; is the average deviation coefficient of formation gas, dimensionless; is the relative permeability of gas phase under irreducible water saturation, dimensionless; h is the reservoir thickness, m; r e is the supply radius, m; r w is the wellbore radius, m; β is the turbulent factor; S is the true skin factor of gas well, dimensionless; γ g is the relative density of natural gas, dimensionless.

3. The diagnostic method for the production capacity recovery of a water-producing gas well after shut-in according to claim 2, wherein The diagnostic method further includes: correcting the laminar flow coefficient A and the turbulent flow coefficient B, and establishing the productivity equation of the gas well by using the corrected laminar flow coefficient A' and the corrected turbulent flow coefficient B'; Wherein, the laminar flow coefficient A and the turbulent flow coefficient B are corrected by the following method: A is the laminar flow coefficient; B is the turbulent flow coefficient; A’ is the corrected laminar flow coefficient, and B’ is the corrected turbulent flow coefficient; is the gas-phase relative permeability at irreducible water saturation; dimensionless; B g is the gas volume coefficient; μ g is the gas-phase viscosity, mPa·s; WGR is the production liquid-gas ratio, m 3 / 10 4 m 3 ; R wgr is the condensate-gas ratio, m 3 / 10 4 m 3 ; μ w is the water-phase viscosity, mPa·s; r e is the supply radius, m; r w is the wellbore radius, m; S t is the total water breakthrough skin, dimensionless; a and b are regression coefficients; S is the true skin factor of the gas well, dimensionless; K rg is the gas-phase relative permeability, dimensionless.

4. The diagnostic method for the production capacity recovery of a gas-producing water well after shut-in according to claim 1, wherein The establishing of the outflow performance curve of the gas well includes: Calculating the bottom-hole flowing pressure during the production stage of the gas well by using multiple pipe flow models; Comparing the measured bottom-hole flowing pressure of the gas well with the bottom-hole flowing pressure calculated by different pipe flow models, and comparing the coincidence rate of the bottom-hole flowing pressure calculated by different pipe flow models; Taking the pipe flow model with the highest coincidence rate in different liquid-gas ratio stages as the applicable pipe flow model for this liquid-gas ratio stage, and obtaining the applicable pipe flow models for different liquid-gas ratio stages; Using the applicable pipe flow models for different liquid-gas ratio stages to obtain the outflow performance curve of the gas well under different wellhead oil pressures and different liquid-gas ratios.

5. The diagnostic method for the restart capacity of a gas-producing water well after shut-in according to claim 4, wherein, After establishing the inflow performance curve of the gas well and establishing the outflow performance curve of the gas well, the diagnostic method further includes: determining the applicable inflow performance curve of the gas well after opening the well according to the predicted formation pressure of the gas reservoir after opening the well; Comparing the predicted maximum liquid-gas ratio after opening the well with the liquid-gas ratio stages applicable to different pipe flow models, and combining with the wellhead pressure limit to determine the applicable pipe flow model after opening the well, and obtaining the outflow performance curve of the gas well.

6. The diagnostic method for the production resumption capacity of a water-producing gas well after shut-in according to claim 4, wherein The diagnostic method further includes: correcting the gravity coefficient and the friction coefficient, and establishing a pipe flow model by using the corrected gravity coefficient and the corrected friction coefficient.

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