A method and system for determining the location of a gas well tubing leak

Abstract

The application discloses a method and system for determining the position of a gas well tubing leakage point, comprising the following steps: determining a suspected leakage well section of a production gas well to be detected; performing encryption processing on a set of conventional temperature and pressure gradient test points in the suspected leakage well section, so as to obtain a plurality of encrypted stop points; calculating the wellbore temperature of a suspected leakage point between adjacent encrypted stop points according to the pressure of all the encrypted stop points; and determining the position of a target leakage point by analyzing the temperature gradient characteristics of different suspected leakage points according to the wellbore temperature of all the suspected leakage points. The position of the tubing leakage point can be conveniently and accurately determined by judging the change of the temperature gradient, so that the method and system have wide engineering application value.

Description

Technical Field

[0001] This invention relates to the field of oil pipeline leak detection technology, and in particular to a method and system for determining the location of leaks in gas well tubing. Background Technology

[0002] During gas well production, problems such as tubing corrosion, perforation, and breakage can easily occur due to various factors, including changes in fluid properties, tubing material, and the age of the tubing in the well, affecting the normal production of the well.

[0003] Currently, detection methods for tubing corrosion perforation or breakage include differential pressure monitoring between tubing and casing, gas lift verification, tracer verification, electromagnetic flaw detection, gamma magnetic positioning instrument, and retrieval tubing string.

[0004] However, the method of monitoring oil and casing pressure difference relies on empirical qualitative judgment, which has the problem of inaccurate positioning; although the electromagnetic flaw detection method has high judgment accuracy, the construction operation is complex and costly. Summary of the Invention

[0005] The purpose of this invention is to provide a solution for quickly and accurately diagnosing the location of oil pipe leaks, thereby solving the problems of inaccurate location and complex and costly construction operations in the prior art.

[0006] To address the aforementioned technical problems, this invention provides a method for determining the location of leaks in gas well tubing, comprising: identifying a suspected leak section of a production gas well to be inspected; densifying conventional temperature and pressure gradient test points set in the suspected leak section to obtain multiple densified stop points; calculating the wellbore temperature of suspected leaks between adjacent densified stop points based on the pressure of all densified stop points; and determining the location of the target leak by analyzing the temperature gradient characteristics of different suspected leaks based on the wellbore temperatures of all suspected leaks.

[0007] Preferably, the step of determining the suspected leakage section of the production gas well to be inspected includes: based on the casing pressure rise rate and oil-casing pressure difference of the production gas well to be inspected, using the principle of communicating vessels, inferring the depth range containing the leakage point, and recording it as the suspected leakage section.

[0008] Preferably, the step of calculating the wellbore temperature of suspected leak points between adjacent encrypted stop points based on the wellbore pressure of all encrypted stop points includes: calculating the pressure gradient between adjacent encrypted stop points based on the pressure of each encrypted stop point; determining the data acquisition time interval between adjacent encrypted stop points and the distance interval from each suspected leak point to its previous encrypted stop point; and obtaining the wellbore temperature of each suspected leak point using a preset wellbore temperature expression based on the pressure gradient, the data acquisition time interval, and the distance interval.

[0009] Preferably, the expression for the preset wellbore temperature is:

[0010] T fe =′γ×gG×dp×t×z

[0011] Among them, T fe denoted by γ, gG represents the temperature gradient of natural gas in the casing, dp represents the pressure gradient, t represents the data acquisition time interval, z represents the distance interval between the suspected leak point and its previous intensified stop point, and γ′ represents the coefficient.

[0012] Preferably, the step of determining the location of the target leak point by analyzing the temperature gradient characteristics of different suspected leak points based on the wellbore temperatures of all suspected leak points includes: determining a reference position corresponding to each suspected leak point; obtaining the temperature gradient of each suspected leak point by calculating the ratio of the wellbore temperature of each suspected leak point to the wellbore temperature at the corresponding reference position based on the wellbore temperature of each suspected leak point; and determining the location of the target leak point by using a gradient threshold based on the temperature gradient of each suspected leak point.

[0013] Preferably, the step of determining the location of the target leak point based on the temperature gradient of each suspected leak point using a gradient threshold includes: determining the suspected leak point as the location of the target leak point when the temperature gradient of at least one suspected leak point exceeds the gradient threshold, wherein the gradient threshold is 3.25.

[0014] Preferably, the location of a leak-free point near each suspected leak point is used as the corresponding reference location.

[0015] Preferably, when no suspected leak section is detected in the production gas well to be inspected, there is no need to carry out the steps of densification processing, wellbore temperature calculation of suspected leaks, and location of target leaks.

[0016] On the other hand, embodiments of the present invention provide a computer-readable storage medium storing computer-executable instructions that, when executed by a processor, implement the steps of the method described in any one or more of the above embodiments.

[0017] Furthermore, embodiments of the present invention also provide a system for determining the location of leaks in gas well tubing, comprising: a leak coarse calculation result generation module configured to determine the suspected leak section of the production gas well to be inspected; a test point densification processing module configured to densify conventional temperature and pressure gradient test points set in the suspected leak section to obtain multiple densified stop points; a wellbore temperature calculation module configured to calculate the wellbore temperature of suspected leaks between adjacent densified stop points based on the pressure of all densified stop points; and a leak location module configured to determine the location of the target leak by analyzing the temperature gradient characteristics of different suspected leaks based on the wellbore temperatures of all suspected leaks.

[0018] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0019] This invention proposes a method and system for determining the location of leaks in gas well tubing. This method and system, while recording conventional pressure data, calculates the wellbore temperature at different suspected leak points. By analyzing the temperature gradients at these suspected leak points, the location of the leak is determined. This approach can conveniently and accurately pinpoint the location of tubing leaks without incurring additional costs, thus reducing expenses and possessing broad engineering application value.

[0020] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0021] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0022] Figure 1 This is a schematic diagram illustrating the steps of a method for determining the location of a gas well tubing leak, as provided in an embodiment of this application.

[0023] Figure 2 This is a schematic diagram of the system for determining the location of a gas well tubing leak, provided in an embodiment of this application. Detailed Implementation

[0024] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that, as long as there is no conflict, the various embodiments and features in the various embodiments of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0025] Furthermore, the steps illustrated in the flowcharts of the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions. Also, although a logical order is shown in the flowcharts, in some cases the steps shown or described may be performed in a different order than that shown here.

[0026] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms “a” and “an” as used herein are also intended to include the plural. It should also be understood that the terms “comprising” and / or “including” as used herein specify the presence of the stated features, integers, steps, operations, units, and / or components, without excluding the presence or addition of one or more other features, integers, steps, operations, units, components, and / or combinations thereof.

[0027] During gas well production, problems such as tubing corrosion, perforation, and breakage can easily occur due to various factors, including changes in fluid properties, tubing material, and the age of the tubing in the well, affecting the normal production of the well.

[0028] Currently, detection methods for tubing corrosion perforation or breakage include differential pressure monitoring between tubing and casing, gas lift verification, tracer verification, electromagnetic flaw detection, gamma magnetic positioning instrument, and retrieval tubing string.

[0029] However, the method of monitoring oil and casing pressure difference relies on empirical qualitative judgment, which has the problem of inaccurate positioning; although the electromagnetic flaw detection method has high judgment accuracy, the construction operation is complex and costly.

[0030] Figure 1 This is a schematic diagram illustrating the steps of a method for determining the location of a gas well tubing leak according to an embodiment of this application. See below for reference. Figure 1 The specific process steps of the method for determining the location of a gas well tubing leak (hereinafter referred to as the "leak location detection method") described in the embodiments of the present invention will be explained.

[0031] Step S110: Identify the suspected leak section of the production gas well to be inspected.

[0032] When determining the location of the target leak in a production gas well to be inspected, it is first necessary to determine the depth range of the leak in the well to be inspected, and then determine the section of the well suspected of having a leak, so that the location of the target leak can be obtained based on the section of the well suspected of having a leak.

[0033] In one embodiment, the suspected leak section can be the entire well section of the producing gas well to be inspected. To improve efficiency, this embodiment first estimates the depth range containing the leak when determining the suspected leak section, and then defines the depth range containing the leak as the suspected leak section. Specifically, step S110 includes: based on the casing pressure rise rate and the oil-casing pressure difference of the producing gas well to be inspected, using the principle of communicating vessels, estimating the depth range containing the leak, and recording it as the suspected leak section.

[0034] Specifically, for a gas well in normal production, if the casing pressure continues to rise, firstly, based on the oil-casing pressure difference and the rate of increase in casing pressure (the casing is generally filled with annular protective agent), the location of the leak in the tubing is roughly calculated using the principle of communicating vessels, and the depth range containing the leak is recorded as the suspected leak section.

[0035] Specifically, when a continuous increase in casing pressure occurs, it is necessary to first rule out interference caused by packer failure before determining whether a leak exists in the tubing of the production gas well to be inspected. Furthermore, because the level of the annular protective agent inside the casing can be inaccurate due to tubing expansion, it is necessary to densify the conventional temperature and pressure gradient test points to obtain the location of the target leak.

[0036] Step S120: The conventional temperature and pressure gradient test points set in the well section suspected of leaking are densified to obtain multiple densified stop points.

[0037] After identifying the suspected leak section, the conventional temperature and pressure gradient test points set in the suspected leak section are densified to obtain multiple densified stop points that can be used to determine the location of the target leak.

[0038] Optionally, to make the location of the target leak more accurate, after obtaining the suspected leak section, a section 500 meters above and below the suspected leak section can be determined, and the conventional temperature and pressure gradient test points set in this section can be densified to obtain multiple densified stop points.

[0039] In this embodiment, the interval between two adjacent encryption stops is not limited and can be reasonably selected according to actual application requirements. For example, it can be 10m.

[0040] Step S130: Calculate the wellbore temperature of suspected leak points between adjacent encrypted stop points based on the pressure of all encrypted stop points.

[0041] When there is no leak in the tubing, the fluid inside the tubing undergoes heat conduction with the tubing, and the heat flux density is proportional to the temperature gradient, so the temperature gradient is relatively stable. However, when there is a leak in the tubing, the temperature gradient will change. Therefore, the location of the target leak can be determined by the temperature gradient. When analyzing the temperature gradient, it is necessary to calculate the wellbore temperature of the suspected leak between adjacent infill stops based on the pressure of all infill stops.

[0042] In one embodiment, when calculating the wellbore temperature, it is necessary to first calculate the pressure gradient between adjacent densification stops based on the pressure at each densification stop, then obtain the distance interval between each suspected leak point and its previous densification stop, and then calculate the wellbore temperature of each suspected leak point based on the pressure gradient and the distance interval. Specifically, step S130 includes the following sub-steps A1-A3:

[0043] Sub-step A1: Calculate the pressure gradient between adjacent encryption stops based on the pressure at each encryption stop.

[0044] Sub-step A2 determines the data collection time interval between adjacent encrypted stop points and the distance interval between each suspected leak point and its previous encrypted stop point.

[0045] Sub-step A3: Based on the pressure gradient, data acquisition time interval, and distance interval, the wellbore temperature of each suspected leak point is obtained using a preset wellbore temperature expression.

[0046] In sub-step A3, the preset wellbore temperature expression is:

[0047] T fe =′Υ×gG×dp×t×z (1)

[0048] Among them, T fe denoted by , gG represents the temperature gradient of natural gas in the casing, dp represents the pressure gradient, t represents the data acquisition time interval, z represents the distance interval between the suspected leak point and its previous intensified stop point, and ′Υ represents the coefficient.

[0049] Specifically, when the preset wellbore temperature expression is obtained, the temperature at the suspected leak point in the tubing to be inspected is calculated based on the enthalpy balance, given the location of the leak.

[0050] H b =(Q ob ×C po ×ρ o +Q wb ×C pw ×ρ w +Q gb ×C pg ×ρ g )×T b (2)

[0051] H t =(Q ot ×C po ×ρ o +Q wt ×C pw ×ρ w +Q gt ×C pg ×ρ g )×T t (3)

[0052] The enthalpy balance between the encrypted stop points corresponding to the suspected leaks is given:

[0053] H t =H b +(ΔQ ob×C po ×ρ o +ΔQ wb ×C pw ×ρ w )×T geo +ΔQ gb ×C pg ×ρ g ×T gas (4)

[0054] In summary, the temperature of the previous encryption stop point corresponding to the suspected leak is:

[0055]

[0056] Referring to the Curtis & Witterholt wellbore fluid flow model, the temperature above the leak point after external fluid enters the wellbore, as proposed by Ramey, is calculated using the following formula:

[0057]

[0058] When the suspected leak point is gas, the inlet temperature is calculated using the Joule-Thomson method:

[0059]

[0060] Among them, T f T t Both represent the temperature of the previous encrypted stop point corresponding to the suspected leak point, H. b ΔQ represents the enthalpy of the previous encrypted stop point corresponding to the suspected leak. ob C represents the change in heat of the crude oil inside the pipeline. po ρ represents the specific heat capacity of crude oil in the pipeline. o The gradient of crude oil, ΔQ wb C represents the change in heat of the formation water within the oil pipeline. pw ρ represents the specific heat capacity of formation water inside the oil pipeline. w T represents the gradient of formation water. geo Represents formation temperature, ΔQ gb C represents the change in heat of natural gas within the pipeline. pg ρ represents the specific heat capacity of natural gas inside the pipeline. g T represents the gradient of natural gas. Ge T gas Both represent the temperature of the natural gas at the leak point, Q. ot Q represents the flow rate of crude oil in the pipeline. wt Q represents the flow rate of formation water within the oil pipeline. gt The flow rate of natural gas in the tubing is represented by z, the distance is represented by t, the time interval is represented by gG, the temperature gradient of natural gas in the casing is represented by A, and the longitudinal height of the leak point is represented by T.fe R represents the wellbore temperature, T represents the gas constant, M represents the molar mass of the gas, Z represents the compressibility factor of the gas, ΔP represents the pressure change, P represents the initial pressure of the gas, and H represents the initial pressure of the gas. t T represents the enthalpy of the next encrypted stop point corresponding to the suspected leak. b The temperature T represents the temperature of the previous encrypted stop point corresponding to the suspected leak. t This indicates the temperature of the next encrypted stop point corresponding to the suspected leak.

[0061] The preset wellbore expression is obtained by combining formulas (5), (6) and (7).

[0062] Specifically, the gradient for crude oil is calculated as 0.8, the gradient for natural gas as 0.23, the gradient for formation water as 1.1, the gradient for natural gas inside the casing as 0.19, and the longitudinal height of the leak point as 0.5 cm.

[0063] Step S140: Based on the wellbore temperature of all suspected leak points, determine the location of the target leak point by analyzing the temperature gradient characteristics of different suspected leak points.

[0064] Because heat exchange occurs between the fluid in the wellbore and the gas in the casing at the leak point, the oil temperature near the leak point decreases. The leak point increases the instability of oil flow, which may cause localized friction and energy loss, generating heat and raising the temperature near the leak point. The specific temperature change is also affected by various factors, such as the flow velocity and pressure of the fluid in the tubing, the size and shape of the leak point, and the temperature and medium of the surrounding environment. Through analysis of temperature data and multiple verifications, it was found that the temperature gradient at the leak point in the gas well during production fluctuates abnormally compared to the normal well section temperature gradient. When there is no leak in the tubing, heat conduction occurs between the fluid in the tubing and the tubing itself. According to Fourier's law of thermal conductivity, the heat flux density q (the amount of heat transferred per unit area perpendicular to the direction of heat flow) is proportional to the temperature gradient. Therefore, the temperature gradient is relatively stable. However, when the fluid flow in the wellbore is unstable, the heat transfer becomes unstable, causing the temperature at the leak location to change over time. The magnitude of the temperature change is a function of the material's specific heat and density, which also causes slight changes in the temperature gradient. It is necessary to quantify the range of temperature gradient changes. Therefore, after obtaining the wellbore temperature of the suspected leak point, the location of the target leak point is determined by analyzing the temperature gradient characteristics of different leak points.

[0065] In one embodiment, when determining the location of a target leak, a reference location corresponding to each suspected leak location is first determined. Then, a temperature gradient is determined based on the wellbore temperature of each suspected leak location and the wellbore temperature at the reference location. The location of the target leak is then obtained based on the temperature gradient. Specifically, step S140 includes the following sub-steps B1-B3:

[0066] Sub-step B1: Determine the reference location for each suspected leak point.

[0067] Sub-step B2: Based on the wellbore temperature of each suspected leak point, the temperature gradient of each suspected leak point is obtained by calculating the ratio of the wellbore temperature of each suspected leak point to the wellbore temperature at the corresponding reference location.

[0068] Sub-step B3: Based on the temperature gradient of each suspected leak point, use the gradient threshold to determine the location of the target leak point.

[0069] In sub-step B1, when determining the reference location, the location of the non-leaking point near each suspected leak point is used as the corresponding reference location.

[0070] In sub-step B3, when determining the target leak location, suspected leak locations with temperature gradients greater than a gradient threshold are identified as target leak locations. Specifically, when the temperature gradient of at least one suspected leak location exceeds the gradient threshold, that suspected leak location is identified as the target leak location.

[0071] The gradient threshold is 3.25.

[0072] In one embodiment, when a suspected leak section exists in the production gas well to be inspected, leak detection is performed on the production gas well to be inspected; if no suspected leak section exists in the production gas well to be inspected, this operation is not performed. Specifically, the leak location detection method further includes: step S150, when no suspected leak section is detected in the production gas well to be inspected, there is no need to perform the steps of densification processing, wellbore temperature calculation of suspected leaks, and target leak location positioning.

[0073] Based on the above-described method for determining the location of leaks in gas well tubing, the present invention also provides a computer-readable storage medium storing computer-executable instructions that, when executed by a processor, implement the steps of the method described in any one or more of the above embodiments.

[0074] Based on the above-described method for determining the location of a gas well tubing leak, the present invention also provides a system for determining the location of a gas well tubing leak. This system for determining the location of a gas well tubing leak implements the method described above.

[0075] Figure 2 This is a schematic diagram of a system for determining the location of a gas well tubing leak, according to an embodiment of this application. Figure 2 As shown in the embodiment of the present invention, the system for determining the location of a gas well tubing leak includes: a leak coarse calculation result generation module 201, a measuring point densification processing module 202, a wellbore temperature calculation module 203, and a leak location module 204.

[0076] Specifically, the leak point rough calculation result generation module 201 is implemented according to the method described in step S110 above, and is configured to determine the suspected leak section of the production gas well to be tested; the measuring point densification processing module 202 is implemented according to the method described in step S120 above, and is configured to densify the conventional temperature and pressure gradient test points set in the suspected leak section to obtain multiple densified stop points; the wellbore temperature calculation module 203 is implemented according to the method described in step S130 above, and is configured to calculate the wellbore temperature of the suspected leak point between adjacent densified stop points based on the pressure of all densified stop points; the leak point location module 204 is implemented according to the method described in step S140 above, and is configured to determine the location of the target leak point by analyzing the temperature gradient characteristics of different suspected leak points based on the wellbore temperature of all suspected leak points.

[0077] This invention proposes a method and system for determining the location of leaks in gas well tubing. This method and system, while recording conventional pressure data, calculates the wellbore temperature at different suspected leak points. By analyzing the temperature gradients at these suspected leak points, the location of the leak is determined. This approach can conveniently and accurately pinpoint the location of tubing leaks without incurring additional costs, thus reducing expenses and possessing broad engineering application value.

[0078] 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 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.

[0079] In the description of this invention, unless otherwise stated, "a plurality of" means two or more; the terms "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," "tail," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing the invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the invention. Furthermore, the terms "first," "second," "third," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0080] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "connected" and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0081] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0082] The phrase "an embodiment" or "an embodiment" used in this specification means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" or "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0083] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for determining the location of a leak in a gas well tubing, characterized in that, include: Identify the suspected leak section of the production gas well to be inspected; The conventional temperature and pressure gradient test points set in the well section suspected of having a leak were densified to obtain multiple encrypted stop points; Calculate the wellbore temperature of suspected leak points between adjacent encrypted stop points based on the pressure of all encrypted stop points; Based on the wellbore temperature of all suspected leak points, the location of the target leak point is determined by analyzing the temperature gradient characteristics of different suspected leak points.

2. The method according to claim 1, characterized in that, The steps for identifying suspected leak sections in a production gas well to be inspected include: Based on the casing pressure rise rate and oil-casing pressure difference of the gas well to be tested, the depth range containing the leak is estimated using the principle of communicating vessels, and is denoted as the suspected leak section.

3. The method according to claim 1 or 2, characterized in that, The step of calculating the wellbore temperature of suspected leak points between adjacent infill stops based on the wellbore pressure of all infill stops includes: Calculate the pressure gradient between adjacent encryption stops based on the pressure at each encryption stop; Determine the data collection time interval between adjacent encrypted stop points and the distance interval from each suspected leak point to its previous encrypted stop point; Based on the pressure gradient, the data acquisition time interval, and the distance interval, the wellbore temperature of each suspected leak point is obtained using a preset wellbore temperature expression.

4. The method according to claim 3, characterized in that, The preset wellbore temperature expression is: T fe =′Υ×gG×dp×t×z Among them, T fe denoted by , gG represents the temperature gradient of natural gas in the casing, dp represents the pressure gradient, t represents the data acquisition time interval, z represents the distance interval between the suspected leak point and its previous intensified stop point, and ′Υ represents the coefficient.

5. The method according to any one of claims 1 to 4, characterized in that, The step of determining the location of the target leak point by analyzing the temperature gradient characteristics of different suspected leak points based on the wellbore temperatures of all suspected leak points includes: Determine the reference location for each suspected leak point; Based on the wellbore temperature of each suspected leak point, the temperature gradient of each suspected leak point is obtained by calculating the ratio of the wellbore temperature of each suspected leak point to the wellbore temperature at the corresponding reference location. Based on the temperature gradient of each suspected leak point, the location of the target leak point is determined using a gradient threshold.

6. The method according to claim 5, characterized in that, The step of determining the location of the target leak point based on the temperature gradient of each suspected leak point using a gradient threshold includes: When the temperature gradient at at least one suspected leak point exceeds the gradient threshold, the suspected leak point is identified as the target leak point location, wherein the gradient threshold is 3.

25.

7. The method according to claim 5 or 6, characterized in that, Use the locations of non-leaking points near each suspected leak point as corresponding reference locations.

8. The method according to any one of claims 1 to 7, characterized in that, If no suspected leak section is detected in the production gas well to be inspected, there is no need to carry out the steps of densification processing, wellbore temperature calculation of suspected leak point and location of target leak point.

9. A computer-readable storage medium storing computer-executable instructions that, when executed by a processor, implement the steps of the method as described in any one of claims 1 to 8.

10. A system for determining the location of a leak in a gas well tubing, characterized in that, include: The leak point rough calculation result generation module is configured to determine the suspected leak section of the production gas well to be inspected; The test point encryption processing module is configured to encrypt the conventional temperature and pressure gradient test points set in the well section suspected of leaking, and obtain multiple encrypted stop points. The wellbore temperature calculation module is configured to calculate the wellbore temperature of suspected leak points between adjacent indentation points based on the pressure of all indentation points. The leak location module is configured to determine the location of the target leak point by analyzing the temperature gradient characteristics of different suspected leak points based on the wellbore temperature of all suspected leak points.

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